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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.

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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

•	expected impact of regulatory outcomes

•	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 industry, market and economic conditions.

•	inflation rates, commodity prices and capacity prices

•	nature and scope of hedging

•	regulatory decisions and outcomes

•	foreign exchange rates

•	interest rates

•	tax rates

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

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•	integrity and reliability of our assets

•	access to capital markets

•	anticipated construction costs, schedules and completion dates.

•	our ability to realize the anticipated benefits from the acquisition of Columbia

•	our ability to successfully implement our strategic initiatives

•	whether our strategic initiatives 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 we receive from our energy business

•	regulatory decisions and outcomes

•	outcomes of legal proceedings, including arbitration and insurance claims

•	performance and credit risk of our counterparties

•	changes in market commodity prices

•	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

•	interest, tax and foreign exchange rates

•	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

•	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 including certain ongoing maintenance and liquidation costs

•	acquisition costs.

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•	a $255 million after-tax net 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 in second quarter, an incremental loss of $176 million after tax recorded in second quarter on the sale of the thermal and wind package and $10 million year-to-date of after-tax disposition costs

•	an after-tax charge of $15 million in second quarter and $39 million year-to-date for integration-related costs associated with the acquisition of Columbia

•	an after-tax charge of $4 million in second quarter and $11 million year-to-date related to the maintenance of Keystone XL assets which is being expensed pending further advancement of the project

•	a $7 million income tax recovery in first quarter 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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•	a $176 million after-tax impairment charge in first quarter on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs

•

a charge of $113 million in second quarter and $139 million year-to-date related to costs associated with the acquisition of Columbia. In second quarter, $109 million related to the dividend equivalent payments on the subscription receipts issued as part of the permanent financing of the transaction, $10 million ($36 million year-to-date) related to acquisition costs and $6 million related to interest earned on the subscription receipt funds held in escrow

•	an after-tax charge of $9 million in second quarter and $15 million year-to-date related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project

•	an after-tax charge of $10 million in second quarter for restructuring charges mainly related to 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

•	an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016.

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•	higher contribution from U.S. Natural Gas Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016

•	higher earnings from Bruce Power mainly due to higher volumes resulting from fewer planned outage days

•	higher interest expense mainly as a result of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt issuances

•	higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlán beginning in December 2016

•	higher earnings from Liquids Pipelines mainly due to higher volumes.

•	higher contribution from U.S. Natural Gas Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016

•	higher interest expense as a result of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt issuances

•	higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlán beginning in December 2016

•	higher earnings from Bruce Power mainly due to higher volumes resulting from fewer planned outage days partially offset by higher interest expense

•	higher earnings from Liquids Pipelines mainly due to higher volumes

•	higher earnings from Western Power following the termination of the Alberta PPAs in March 2016.

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1	As of June 30, 2017, near-term NGTL System capital projects are being reported by expected in-service dates.

2	Our proportionate share.

3	Amounts reflect our proportionate share of the remaining capital costs that Bruce Power expects to incur on its life extension investment programs in advance of major refurbishment outages which are expected to begin in 2020.

4	Reflects U.S./Canada foreign exchange rate of $1.30 at June 30, 2017.

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1	Our proportionate share.

2	Carrying value reflects amount remaining after impairment charge recorded in fourth quarter 2015.

3	Excludes transfer of Canadian Mainline natural gas assets.

4	Reflects U.S./Canada foreign exchange rate of $1.30 at June 30, 2017.

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1	Includes results from Foothills, Ventures LP and our share of equity income from our investment in TQM.

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1	Field receipt volumes for the NGTL System for the six months ended June 30, 2017 were 2,070 Bcf (2016 – 2,075 Bcf). Average per day was 11.4 Bcf (2016 – 11.4 Bcf).

2	Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the six months ended June 30, 2017 were 474 Bcf (2016 – 530 Bcf). Average per day was 2.6 Bcf (2016 – 2.9 Bcf).

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1	We completed the acquisition of Columbia on July 1, 2016 and the publicly held units of Columbia Pipeline Partners LP (CPPL) on February 17, 2017.

2	Results from Northern Border and Iroquois reflect our share of equity income from these investments. We acquired additional interests in Iroquois of 0.65 per cent on May 1, 2016 and 4.87 per cent on March 31, 2016. TC PipeLines, LP acquired TransCanada's 49.34 per cent interest in Iroquois and its remaining 11.81 per cent interest in PNGTS on June 1, 2017.

3	TC PipeLines, LP periodically conducts at-the-market equity issuances which decrease our ownership in TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of Great Lakes and PNGTS through our ownership interest in TC PipeLines, LP for the periods presented.

4	Represents our 53.6 per cent direct interest in Great Lakes. The remaining 46.4 per cent is held by TC PipeLines, LP.

5	Includes our effective ownership in Millennium and Hardy Storage and our direct ownership in Iroquois and PNGTS up to June 1, 2017.

6	Comparable EBITDA for the portions of TC PipeLines, LP, PNGTS and CPPL that we do not own. Effective February 17, 2017, we acquired the remaining publicly held units of CPPL.

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•	US$193 million and US$443 million of EBITDA for the three and six months ended June 30, 2017 as a result of the acquisition of Columbia on July 1, 2016

•	higher ANR transportation and storage revenue resulting from a FERC-approved rate settlement, effective August 1, 2016.

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1	Represents our 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline.

•	incremental earnings from Topolobampo. The Topolobampo project has experienced a delay in construction which, under the terms of our Transportation Service Agreement (TSA) with the CFE, constitutes a force majeure event with provisions allowing for the collection and recognition of revenue as per the original TSA service commencement date of July 2016

•	incremental earnings from Mazatlán. Construction is complete and the collection and recognition of revenue began per the terms of the TSA in December 2016

•	equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction.

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•	higher volumes on Keystone pipeline

•	higher contribution from liquids marketing activities

•	increased business development activities, including advancement of Keystone XL

•	a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. operations.

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1	Included losses from the Alberta PPAs up to March 7, 2016 when the PPAs were terminated.

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

3	U.S. Northeast power assets no longer depreciated effective November 2016 when classified as held for sale.

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•	in 2017, a net gain of $481 million before tax related to the monetization of our U.S. Northeast power business which included a $717 million gain on the sale of TC Hydro, a loss of $219 million on the sale of the thermal and wind package and $17 million of pre-tax disposition costs. See Recent developments section for more details

•	in 2016, a $240 million pre-tax charge, which included a $29 million impairment of our equity investment in ASTC Power Partnership, on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs

•	unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks as follows:

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1	Includes the realized gains and losses from financial derivatives used to manage Canadian Power’s assets which are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives have been excluded to arrive at comparable EBITDA.

2	Includes revenues from the sale of unused natural gas transportation and sale of excess natural gas purchased for generation.

3	Included Alberta PPAs up to March 7, 2016 when the PPAs were terminated.

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

5	Plant availability was higher in the three and six months ended June 30, 2017 than the same periods in 2016 due to an unplanned outage at the Mackay River facility as a result of the Northern Alberta wildfires in 2016.

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1	Represents our 48.4 per cent (2016 - 48.5 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	Includes the realized gains and losses from financial derivatives used to manage U.S. Power’s business which are presented on a net basis in Power revenues. The unrealized gains and losses from financial derivatives are excluded to arrive at comparable EBITDA.

2	Includes the cost of fuel consumed in generation.

3	TC Hydro earnings included up to April 19, 2017 sale date; Ravenswood, Ironwood, Ocean State Power and Kibby Wind earnings included up to June 2, 2017 sale date.

4	U.S. Northeast power assets no longer depreciated effective November 2016 when classified as held for sale.

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•	acquisition and integration costs associated with the acquisition of Columbia

•	foreign exchange loss on an inter-affiliate loan, which is offset in Interest income and other. This peso-denominated loan to the Sur de Texas project represents our proportionate share of its financing

•	restructuring costs related to expected future losses under lease commitments.

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•	debt assumed in the acquisition of Columbia on July 1, 2016

•	U.S. dollar-denominated long-term debt and junior subordinated notes issuances, including the impact of foreign exchange

•	higher capitalized interest on Liquids and LNG projects and the Napanee power generating facility

•	in 2016, the dividend equivalent payments on the subscription receipts issued to partially fund the Columbia acquisition.

•	foreign exchange impact on the translation of foreign currency denominated working capital balances

•	income of $18 million related to Coastal GasLink project costs incurred to date. See Recent developments section for more information

•	realized losses in 2017 compared to realized gains in 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•	foreign exchange gain on an inter-affiliate loan receivable from the Sur de Texas project which is offset in Corporate segmented losses

•	in 2016, interest income on the gross proceeds of the subscription receipts held in escrow

•	unrealized gains on risk management activities in 2017 compared to 2016. These amounts have been excluded from comparable earnings.

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•	our ability to generate cash flow from operations

•	our access to capital markets

•	approximately $8.3 billion of unutilized, unsecured committed credit facilities.

1	See the non-GAAP measures section in 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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•	expansion of Columbia pipelines

•	expansion of the NGTL System

•	construction of Mexico pipelines

•	expansion of the Canadian Mainline

•	capital additions to our ANR pipeline

•	construction of the Napanee power generating facility.

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

2

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

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•	accounts receivable

•	the fair value of derivative assets

•	cash and cash equivalents.

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1	Fair values equal carrying values.

2	In the three and six months ended June 30, 2017, net realized gains of $1 million and $2 million, respectively, (2016 - gains of $2 million and $4 million, respectively) related to the interest component of cross-currency swaps settlements are included in 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	Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast power business, a loss of $49 million and a gain of $7 million were recorded in net income in the three months ended March 31, 2016 relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale.

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

2	Reported within revenues on the condensed consolidated statement of income.

3	Reported within interest income and other on the condensed consolidated statement of income.

4	Reported within interest expense on the condensed consolidated statement of income.

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•	regulatory decisions

•	negotiated settlements with shippers

•	acquisitions and divestitures

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service

•	regulatory decisions.

•	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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•	a $265 million net after-tax gain related to the monetization of our U.S. Northeast power business which includes 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 which are 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 business

•	a charge of $7 million after tax related to the maintenance of Keystone XL assets which are 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.

•	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 are 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 form 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 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 related to retention, severance and integration expenses

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•	$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 are 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

•	a charge of $9 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are 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.

•	a $176 million after-tax impairment charge on the carrying value of our Alberta PPAs as a result of our decision to terminate the PPAs

•	a charge of $26 million related to costs associated with the acquisition of Columbia

•	a charge of $6 million after tax related to Keystone XL costs for the maintenance and liquidation of project assets which are being expensed pending further advancement of the project

•	an additional $3 million after-tax loss on the sale of TC Offshore which closed on March 31, 2016.

•	a $2,891 million after-tax impairment charge on the carrying value of our investment in Keystone XL and related projects

•	an $86 million after-tax loss provision related to the sale of TC Offshore expected to close in early 2016

•

a net charge of $60 million after tax for our business restructuring and transformation initiative comprised of $28 million mainly related to 2015 severance costs and a provision of $32 million for 2016 planned severance costs and expected future losses under lease commitments. These charges form part of a restructuring initiative which commenced in 2015 to maximize the effectiveness and efficiency of our existing operations and reduce overall costs

•	a $43 million after-tax charge related to an impairment in value of turbine equipment held for future use in our Energy business

•	a charge of $27 million after tax related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

•	a $199 million positive income adjustment related to the impact on our net income from non-controlling interests of TC PipeLines, LP's impairment of their equity investment in Great Lakes.

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

2

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

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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 is net of non-controlling interest losses of $49 million.

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

2	Other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $90 million and gains of $1 million, respectively.

3

Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $9 million ($6 million, net of tax) at June 30, 2017. 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 9 for additional detail.

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1	Fair values equal carrying values.

2	In the three and six months ended June 30, 2017, net realized gains of $1 million and $2 million, respectively, (2016 - gains of $2 million and $4 million, respectively) related to the interest component of cross-currency swap settlements are included in interest expense.

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1	Notes receivable was included in Assets held for sale at December 31, 2016 on the condensed consolidated balance sheet. The fair value was calculated based on the original contract terms.

2	Long-term debt is recorded at amortized cost except for US$850 million (December 31, 2016 - US$850 million) that is attributed to hedged risk and recorded at fair value.

3

Consolidated net income for the three and six months ended June 30, 2017 included unrealized losses of $1 million and unrealized gains of $1 million, respectively, (2016 - unrealized losses of $1 million and $13 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of long-term debt at June 30, 2017 (December 31, 2016 - US$850 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

1	Available for sale assets are recorded at fair value and included in other current assets and restricted investments on the condensed consolidated balance sheet.

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

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 OCI.

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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	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 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	Following the March 17, 2016 announcement of the Company's intention to sell the U.S. Northeast power assets, a loss of $49 million and a gain of $7 million were recorded in net income in the three months ended March 31, 2016 relating to discontinued cash flow hedges where it was probable that the anticipated underlying transaction would not occur as a result of a future sale.

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

2	Reported within revenues on the condensed consolidated statement of income.

3	Reported within interest income and other on the condensed consolidated statement of income.

4	Reported within interest expense on the condensed consolidated statement of income.

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 six months ended June 30, 2017.

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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, 2016.

1	For the three and six months ended June 30, 2017, revenues include unrealized losses of $1 million and gains of $1 million, respectively, attributed to derivatives in the Level III category that were still held at June 30, 2017 (2016 - gains of $6 million and $8 million, respectively).

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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.

•	Second quarter 2017 financial results

•	Declared a quarterly dividend of $0.625 per common share for the quarter ending September 30, 2017

•	Announced $2 billion of additional expansions on the NGTL System to increase receipt and delivery capacity

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•	In April, closed the sale of TC Hydro for US$1.07 billion and in June completed the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind for US$2.029 billion. The proceeds from the sales were used to fully retire the acquisition bridge facilities which partially financed the Columbia acquisition

•	On June 1, sold a 49.34 per cent interest in Iroquois Gas Transmission System, LP (Iroquois), together with our remaining 11.81 per cent interest in Portland Natural Gas Transmission System (PNGTS), to our master limited partnership, TC PipeLines, LP for a value of US$765 million

•	Raised US$500 million at TC PipeLines, LP from issuance of 10 year senior unsecured notes

•	Raised $1.5 billion in gross proceeds through a Canadian offering of Junior Subordinated Notes maturing in 2077

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Established an At-The-Market (ATM) program that allows us to issue up to $1 billion in common shares from time to time over a 25-month period, at our discretion, at the prevailing market price when sold in Canada or the United States. The ATM program will be activated at our discretion, if and as required, based on the spend profile of TransCanada’s capital program and relative cost of other funding options

•	In July, launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil on the Keystone Pipeline and for the Keystone XL Pipeline project from Hardisty, Alberta to markets in Cushing, Oklahoma and the U.S. Gulf Coast

•	On July 25, 2017, we were notified that Pacific NorthWest (PNW) LNG would not be proceeding with their proposed LNG project.  As part of our Prince Rupert Gas Transmission (PRGT) agreement, following receipt of a termination notice, we would be reimbursed for the full costs and carrying charges incurred to advance the PRGT project. We expect to receive this payment later in 2017

•	On July 28, announced a $0.2 billion expansion project on the Canadian Mainline in southern Ontario

•	NGTL System: In June, we announced an additional $2 billion expansion program, subject to regulatory approvals, supported by new contracted customer demand for approximately 3 Bcf/d of incremental firm receipt and delivery services. The expansion will also increase delivery capacity at the Alberta/British Columbia

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Canadian Mainline Tolling Option Open Season: In April, an application was filed with the National Energy Board (NEB) for approval of the long-term fixed-price service from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The NEB is following a modified Streamlined Application Process with adjudication expected to follow after oral arguments are presented on September 11, 2017. The new service is requested to begin November 1, 2017.

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Canadian Mainline Maple Compressor Expansion Project: The Canadian Mainline has received requests for expansion capacity to the southern Ontario market plus delivery to Atlantic Canada via the TQM and PNGTS systems. The requests for approximately 80 MMcf/d of firm service underpin the need for new compression at the existing Maple compressor site. Customers have executed 15-year precedent agreements to proceed with the estimated $160 million project. Once we have completed our tariff process for this capacity addition, an application to the NEB for approval to proceed with the project is planned for early 2018 to meet a November 1, 2019 in-service date.

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Coastal GasLink: The continuing delay in the Final Investment Decision (FID) for the LNG Canada project has triggered a restructuring of provisions in the Coastal GasLink project agreement with LNG Canada that will result in the payment of certain amounts to TransCanada with respect to carrying charges on costs incurred since inception of the project. An approximate $80 million payment will be received in September 2017, followed by quarterly payments of approximately $7 million until further notice. We continue to work with LNG Canada under the agreement towards a FID.

•	Prince Rupert Gas Transmission: On July 25, 2017, we were notified that PNW LNG would not be proceeding with their proposed LNG project.  As part of our PRGT agreement, following receipt of a termination notice, we would be reimbursed for the full costs and carrying charges incurred to advance the PRGT project. We expect to receive this payment later in 2017.

•	Sale of Iroquois and PNGTS to TC PipeLines, LP: On June 1, 2017, we sold a 49.34 per cent interest in Iroquois, together with our remaining 11.81 per cent interest in PNGTS, to our master limited partnership, TC PipeLines, LP for a value of US$765 million.

•	Leach XPress and Rayne XPress: We continue to advance construction on the US$1.5 billion Leach XPress and the US$0.4 billion Rayne XPress projects. Both projects are expected to enter service in November 2017.

•	Keystone XL: On July 27, 2017, we launched an open season to solicit additional binding commitments from interested parties for transportation of crude oil on the Keystone Pipeline and for the Keystone XL Pipeline project from Hardisty, Alberta to markets in Cushing, Oklahoma and the U.S. Gulf Coast. The open season will close on September 28, 2017.

•	Grand Rapids: In June, the Grand Rapids pipeline commenced line fill activities with anticipated in-service in third quarter 2017.

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Monetization of U.S. Northeast power business: On April 19, 2017, we closed the sale of TC Hydro to Great River Hydro, LLC for US$1.07 billion resulting in a gain of $717 million ($441 million after-tax) recorded in second quarter 2017. On June 2, 2017, we completed the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC for US$2.029 billion. An additional loss of approximately $219 million ($176 million after-tax) was recorded in second quarter 2017, primarily related to an adjustment to the purchase price and repair costs for an unplanned outage at Ravenswood prior to close. Insurance recoveries for a portion of the repair costs are expected to be received by the end of 2017 which will partially reduce this loss.

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•	Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.625 per share for the quarter ending September 30, 2017 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.50 per common share on an annualized basis.

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Junior Subordinated Debt Issuance: In May 2017, TransCanada Trust issued $1.5 billion of 60-year Junior Subordinated Notes in Canada to third party investors with a fixed interest rate of 4.65 per cent for the first ten years converting to a floating rate thereafter. The notes are callable at par beginning ten years following their issuance. All of the proceeds of the issuance by the Trust were loaned to TransCanada PipeLines Limited (TCPL) in $1.5 billion of subordinated notes at a rate of 4.90 per cent which includes a 0.25 per cent administration charge.

•	Financing at TC PipeLines, LP: In May 2017, TC PipeLines, LP raised US$500 million from issuance of 10-year senior unsecured notes bearing an interest rate of 3.90 per cent.

•	Dividend Reinvestment Plan (DRP): Based on the most recent quarter, approximately 35 per cent of the common share dividends declared are being reinvested in TransCanada common shares through our DRP.

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ATM Equity Issuance Program: In June 2017, we established an ATM program that allows us to issue common shares from treasury having an aggregate gross sales price of up to $1.0 billion or their U.S. dollar equivalent, from time to time, at our discretion, at the prevailing market price when sold through the Toronto Stock Exchange or the New York Stock Exchange. The ATM program, which is effective for a 25-month period, will be activated at our discretion, if and as required, based on the spend profile of TransCanada’s capital program and relative cost of other funding options. At June 30, 2017, no common shares were issued under the program.

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