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1	Comparable EBITDA, comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See the non-GAAP measures section for more information.

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•	anticipated business prospects

•	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 costs for planned projects, including projects under construction 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

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

•	expected industry, market and economic conditions.

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•	inflation rates, commodity prices and capacity prices

•	timing of financings and 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

•	integrity and reliability of our assets

•	access to capital markets

•	anticipated construction costs, schedules and completion dates

•	acquisitions and divestitures.

•	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 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 and foreign exchange rates

•	weather

•	cyber security

•	technological developments

•	economic conditions in North America as well as globally.

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•	EBITDA

•	EBIT

•	funds generated from operations

•	comparable earnings

•	comparable earnings per common share

•	comparable EBITDA

•	comparable EBIT

•	comparable depreciation and amortization

•	comparable interest expense

•	comparable interest income and other expense

•	comparable income tax expense.

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•	certain fair value adjustments relating to risk management activities

•	income tax refunds and adjustments and changes to enacted 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

•	write-downs of assets and investments.

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•	a $34 million adjustment to income tax expense due to the enactment of a two per cent increase in the Alberta corporate income tax rate in June 2015

•	a charge of $8 million after-tax for severance costs primarily as a result of the restructuring of our major projects group in response to delayed timelines on certain of our major projects, along with a continued focus on enhancing the efficiency and effectiveness of our operations.

•	a gain on sale of Cancarb Limited and its related power generation business of $99 million after tax

•	a net loss resulting from the termination of a contract with Niska Gas Storage of $31 million after tax.

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•	higher earnings from Bruce Power from higher volumes as a result of fewer outage days at Bruce A partially offset by lower Bruce B volumes due to increased planned outage days

•	higher uncontracted volumes on the Keystone Pipeline System

•	higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in the second half of 2014 and higher earnings at Cartier Wind

•	higher earnings from Canadian Pipelines due to incentive earnings recorded for the Canadian Mainline and a higher average investment base on NGTL partially offset by lower Canadian Mainline ROE

•	lower earnings from U.S. Power mainly due to the timing of earnings recognized on certain contracts in our power marketing business, reflecting the different pricing profiles between the power prices we charge our customers and the prices we pay for volumes purchased

•	lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes

•	higher interest expense from new debt issuances and higher foreign exchange on interest related to U.S. dollar-denominated debt.

•	higher uncontracted volumes on the Keystone Pipeline System

•	higher earnings from Eastern Power due to the sale of unused natural gas transportation, higher contractual earnings at Bécancour and incremental earnings from Ontario solar facilities acquired in the second half of 2014

•	higher earnings from Bruce Power from increased volumes as a result of fewer outage days at Bruce A, partially offset by lower Bruce B volumes due to increased planned outage days

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•	higher earnings from U.S. and International Pipelines due to increased earnings from the Tamazunchale Extension which was placed in service in 2014, higher ANR Southeast transportation revenue and ANR's first quarter 2015 settlement with a producer for damages to ANR's pipeline. These were partially offset by increased spending on pipeline integrity work

•	higher earnings from U.S. Power mainly due to increased margins on and higher sales volumes to wholesale, commercial and industrial customers partially offset by lower earnings from U.S. generating assets primarily due to the impact of lower realized power prices

•	lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes

•	higher interest expense from debt issuances and higher foreign exchange on interest related to U.S. dollar-denominated debt.

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1	Represents our 50 per cent share.

2	In-service date to be aligned with industry requirements.

3	Estimated project cost dependent on the timing of the Presidential permit.

4	Approximately two years from the date the Keystone XL permit is received.

5	Excludes transfer of Canadian Mainline natural gas assets.

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1	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

2	There were no specific items in any of these periods.

1	Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments. In November 2014, we sold our interest in Gas Pacifico/INNERGY.

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2

Beginning in August 2014, TC PipeLines, LP began its at-the-market equity issuance program which, when utilized, decreases ownership interest in TC PipeLines, LP. On October 1, 2014, we sold our remaining 30 per cent direct interest in Bison to TC PipeLines, LP. On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TC PipeLines, LP. The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of GTN, Bison and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.

3	Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TC PipeLines, LP.

4	Effective October 1, 2014, we have no direct ownership in Bison. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.

5	Effective April 1, 2015, we have no direct ownership in GTN. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.

6	Represents our 61.7 per cent ownership interest.

7	Includes our share of the equity income from Gas Pacifico/INNERGY and TransGas as well as general and administration costs relating to our U.S. and International Pipelines. In November 2014, we sold our interest in Gas Pacifico/INNERGY.

8	Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

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•	higher earnings from the Tamazunchale Extension which was placed in service in 2014

•	higher ANR Southeast transportation revenue and ANR's first quarter 2015 settlement with a producer for damages to ANR's pipeline, partially offset by increased spending on pipeline integrity work.

1	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, 2015 were 564 Bcf (2014 – 599 Bcf). Average per day was 3.1 Bcf (2014 – 3.3 Bcf).

2	Field receipt volumes for the NGTL System for the six months ended June 30, 2015 were 2,006 Bcf (2014 – 1,879 Bcf). Average per day was 11.1 Bcf (2014 – 10.4 Bcf).

3	Under its current rates, which are approved by the FERC, changes in average investment base do not affect results.

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1	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

2	There were no specific items in any of these periods.

•	higher uncontracted volumes

•	incremental earnings from the Gulf Coast extension which was placed in service in late January 2014

•	a stronger U.S. dollar and its positive effect on the foreign exchange impact

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1	Comparable depreciation and amortization is equivalent to the GAAP measure, depreciation and amortization.

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

•	higher earnings from Bruce Power from higher volumes as a result of fewer outage days at Bruce A, partially offset by lower Bruce B volumes due to increased planned outage days

•	higher earnings from Eastern Power due to incremental earnings from Ontario solar facilities acquired in the second half of 2014 and higher earnings at Cartier Wind

•	lower earnings from U.S. Power mainly due to the timing of earnings recognized on certain contracts in our power marketing business, reflecting the different pricing profiles between the power prices we charge our customers and the prices we pay for volumes purchased

•	lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes.

•	higher earnings from Eastern Power due to the sale of unused natural gas transportation, higher contractual earnings at Bécancour and incremental earnings from Ontario solar facilities acquired in 2014

•	higher earnings from Bruce Power from increased volumes as a result of fewer outage days at Bruce A partially offset by lower Bruce B volumes due to increased planned outage days

•	higher earnings from U.S. Power mainly due to increased margins and higher sales volumes to wholesale, commercial and industrial customers primarily offset by lower earnings on U.S. generating assets primarily due to the impact of lower realized power prices

•	lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes

•	lower earnings from Natural Gas Storage due to lower realized natural gas price spreads

•	a stronger U.S. dollar and its positive effect on the foreign exchange impact.

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1	The realized and unrealized gains and losses from financial derivatives used to manage Canadian Power’s assets are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives included in revenue are excluded to arrive at Comparable EBITDA.

2	Includes revenues from the sale of unused natural gas transportation, sale of excess natural gas purchased for generation and Cancarb sales of thermal carbon black up to April 15, 2014 when it was sold.

3	Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy. Equity income does not include any earnings related to our risk management activities.

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1	Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership.

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

3	Does not include facilities that provide power to us under PPAs.

4	Does not include Bécancour because power generation has been suspended since 2008.

5	Higher plant availability in Eastern Power was the result of higher availability at Halton Hills because of a maintenance outage in second quarter 2014.

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1	Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. 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. Bruce B realized sales prices per MWh includes revenues under the floor price mechanism and revenues from contract settlements.

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1	The realized and unrealized gains and losses from financial derivatives used to manage U.S. Power’s assets are presented on a net basis in Power revenues. The unrealized gains and losses from financial derivatives included in revenue are excluded to arrive at Comparable EBITDA.

2	Includes the cost of fuel consumed in generation.

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

2	Plant availability for the three and six months ended June 30 was lower in 2015 than the same periods in 2014 due to an unplanned outage at the Ravenswood facility.

1	New England ISO all hours Mass Hub price

2	Zone J in New York City where the Ravenswood plant operates

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•	the timing of recognizing earnings on certain contracts in our power marketing business due to different power pricing profiles between the prices we charge our customers and the prices we pay for volumes purchased

•	lower realized capacity prices in New York

•	higher margins and higher sales to wholesale, commercial and industrial customers.

•	higher margins and higher sales volumes to wholesale, commercial and industrial customers

•	lower realized capacity prices in New York

•	lower realized power prices and generation at our facilities in New York and New England partially offset by lower fuel costs.

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1	There were no specific items in any of these periods.

•	higher interest expense due to debt issues of:

◦	US$750 million in May 2015

◦	US$750 million in March 2015

◦	US$350 million in March 2015 by TC PipeLines, LP

◦	US$750 million in January 2015

◦	US$1.25 billion in February 2014

◦	partially offset by Canadian and U.S. dollar-denominated debt maturities

•	a stronger U.S. dollar and its effect on the foreign exchange impact on interest expense related to U.S. dollar-denominated debt.

•	increased AFUDC related to our rate-regulated projects, primarily the Energy East Pipeline and our Mexico pipelines

•	higher realized losses in 2015 compared to 2014 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income

•	the impact of a strengthening U.S. dollar on the translation of foreign currency denominated working capital.

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1	See the non-GAAP measures section in this MD&A for further discussion of funds generated from operations.

•	our ability to generate cash flow from operations

•	our access to capital markets

•	approximately $6.0 billion of unutilized, unsecured credit facilities.

•	the expansion of the NGTL System

•	construction of Mexico pipelines

•	construction of the Northern Courier pipeline

•	continued work on the ANR pipeline expansion

•	construction of the Napanee power project.

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1	The Junior subordinated unsecured notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL and are callable at TCPL's option at any time on or after May 20, 2025 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

2	The Junior subordinated notes were issued to TransCanada Trust. The interest rate is fixed at 5.875 per cent per annum and will reset starting May 2025 until May 2045 to the three month LIBOR plus 3.778 per cent per annum; from May 2045 to May 2075 the interest rate will reset to the three month LIBOR plus 4.528 per cent per annum.

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1	Holders of the cumulative redeemable first preferred shares set out in this table are entitled to receive a fixed, cumulative, quarterly preferred dividend, as and when declared by the Board with the exception of Series 4 preferred shares. The holders of Series 4 preferred shares are entitled to receive quarterly, floating rate, cumulative, preferred dividends as and when declared by the Board.

2	We may, at our option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends on the redemption option date and on every fifth anniversary date thereafter.

3	Commencing June 30, 2015, the floating quarterly dividend rate for the Series 4 preferred shares is 1.945 per cent and will reset every quarter going forward.

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•	accounts receivable

•	portfolio investments

•	the fair value of derivative assets

•	cash and notes receivable.

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1	Fair values equal carrying values.

2	Net income in the three and six months ended June 30, 2015 included net realized gains of $2 million and $5 million, respectively, (2014 - gains of $5 million and $11 million, respectively) related to the interest component of cross-currency swaps settlements.

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1	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in energy 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 expense, respectively.

2	For the three and six months ended June 30, 2015, net realized gains on fair value hedges were $2 million and $4 million, respectively, (2014 - gains of $2 million and $3 million, respectively) and were included in interest expense. For the three and six months ended June 30, 2015 and 2014, we did not record any amounts in net income related to ineffectiveness for fair value hedges.

3

The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other expense as appropriate, as the original hedged item settles. For the three and six months ended June 30, 2015 and 2014, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

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

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

3	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.

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•	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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1	The Junior subordinated unsecured notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL and are callable at TCPL's option at any time on or after May 20, 2025 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

2	The Junior subordinated notes were issued to TransCanada Trust. The interest rate is fixed at 5.875 per cent per annum and will reset starting May 2025 until May 2045 to the three month LIBOR plus 3.778 per cent per annum; from May 2045 to May 2075 the interest rate will reset to the three month LIBOR plus 4.528 per cent per annum.

1	Holders of the cumulative redeemable first preferred shares set out in this table are entitled to receive a quarterly fixed, cumulative, preferred dividend, as and when declared by the Board with the exception of Series 4 preferred shares. The holders of Series 4 preferred shares are entitled to receive quarterly, floating rate, cumulative, preferred dividends as and when declared by the Board.

2	TransCanada may, at its option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus all accrued and unpaid dividends on the redemption option date and on every fifth anniversary date thereafter.

3	Commencing June 30, 2015, the floating quarterly dividend rate for the Series 4 preferred shares is 1.945 per cent and will reset every quarter going forward.

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

2	Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest loss of $30 million.

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

2	Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gain of $118 million.

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 $78 million ($49 million, net of tax) at June 30, 2015. 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 for additional detail.

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1	Fair values equal carrying values.

2	Net income in the three and six months ended June 30, 2015 included net realized gains of $2 million and $5 million, respectively,(2014 - gains of $5 million and $11 million, respectively) related to the interest component of cross-currency swaps which is offset in interest expense.

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1	Notes receivable are included in other current assets and intangible and other assets on the condensed consolidated balance sheet.

2	Long-term debt is recorded at amortized cost, except for US$750 million (December 31, 2014 - US$400 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, 2015 included unrealized gains of $3 million and nil, respectively, (2014 - gains of $1 million and losses of $5 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$750 million of long-term debt at June 30, 2015 (December 31, 2014 - US$400 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

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1	Available for sale assets are recorded at fair value and included in intangible and other assets 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	Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.

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1

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

2	Fair values equal carrying values.

3	As at June 30, 2015.

4	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

5

Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in energy 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 expense, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other expense, as appropriate, as the original hedged item settles.

6

All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $3 million and a notional amount of US$750 million as at June 30, 2015. For the three and six months ended June 30, 2015, net realized gains on fair value hedges were $2 million and $4 million, respectively, and were included in interest expense. For the three and six months ended June 30, 2015, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7	For the three and six months ended June 30, 2015, there were no gains or losses included in net income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

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1

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

2	Fair values equal carrying values.

3	As at December 31, 2014.

4	Volumes for power and natural gas derivatives are in GWh and Bcf, respectively.

5

Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell power and natural gas are included net in energy 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 expense, respectively. The effective portion of the change in fair value of derivative instruments in hedging relationships is initially recognized in OCI and reclassified to energy revenues, interest expense and interest income and other expense, as appropriate, as the original hedged item settles.

6

All hedging relationships are designated as cash flow hedges except for interest rate derivative instruments designated as fair value hedges with a fair value of $3 million and a notional amount of US$400 million as at December 31, 2014. Net realized gains on fair value hedges for the three and six months ended June 30, 2014 were $2 million and $3 million, respectively, and were included in interest expense. For the three and six months ended June 30, 2014, the Company did not record any amounts in net income related to ineffectiveness for fair value hedges.

7	For the three and six months ended June 30, 2014, there were no gains or losses included in net income for discontinued cash flow hedges where it was probable that the anticipated transaction would not occur.

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

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

3	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, 2015.

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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, 2014.

1	For the three and six months ended June 30, 2015, energy revenues include unrealized gains attributed to derivatives in the Level III category that were still held at June 30, 2015 of $11 million and $8 million, respectively (2014 - losses of $2 million and $2 million, respectively).

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1	TransCanada’s share of the potential estimated current or contingent exposure.

2	Except for one guarantee with no termination date.

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 financial results

•	PRGT reached a significant milestone when PNW LNG announced a positive FID, subject to two conditions, for their proposed liquefaction and export facility on the West Coast of B.C.

•	Received a majority of the pipeline and facilities permits for PRGT and Coastal GasLink

•	Received regulatory approval for the $1.7 billion North Montney Mainline project

•	Continued to advance our master limited partnership strategy with the drop down of the remaining 30 per cent interest in Gas Transmission Northwest LLC (GTN) for US$457 million

•	Completed over $1.5 billion of financing with the issuance of junior subordinated and medium-term notes

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NGTL System Expansions: The NGTL System has approximately $6.8 billion of new supply and demand facilities currently under development. In second quarter 2015, we continued to advance several of these capital expansion projects and plan to file additional facilities applications for this program through the remainder of 2015. We have received additional requests for firm receipt service that we anticipate will increase the overall capital spend on the NGTL System beyond the previously announced program and continue to work with our customers to best match their requirements for 2016, 2017 and 2018 in-service dates.

•	Canadian Mainline: On March 31, 2015, we submitted a compliance toll filing in response to direction from the NEB’s RH-001-2014 Decision issued in November 2014. On June 12, 2015, the NEB approved the applied-for compliance tolls, as filed. These final tolls became effective on July 1, 2015 which allowed, among other things, the recording of incentive earnings as approved by the NEB.

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PRGT: In second quarter 2015, we received six of the eleven pipeline and facilities permits from the B.C. Oil and Gas Commission (BC OGC) needed to build and operate PRGT. We anticipate decisions on the remaining BC OGC permits in third quarter 2015. PRGT is a 900 km (559 mile) natural gas pipeline that will deliver gas from the North Montney producing region near Fort St. John, B.C. at an interconnect on the NGTL System to the proposed PNW LNG facility near Prince Rupert, B.C.

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Coastal GasLink: We have received eight of ten pipeline and facilities permits from the BC OGC and anticipate receiving the remaining two permits in third quarter 2015. We are continuing our engagement with Aboriginal groups along the pipeline route and on June 29, 2015 we announced the signing of project agreements with Wet’suwet’en First Nation, Skin Tyee Nation, Nee-Tahi-Buhn Band, Yekooche First Nation, Doig River First Nation and Halfway River First Nation, all of northern B.C.

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GTN Drop Down: On April 1, 2015, we closed the sale of our remaining 30 per cent interest in GTN to our master limited partnership, TC PipeLines, LP (the Partnership). The US$457 million sale, which included a US$11 million purchase price adjustment, was comprised of US$264 million in cash, the assumption of US$98 million in proportional GTN debt and the issuance of US$95 million of new Class B units to TransCanada. The Class B units entitle us to a cash distribution based on 30 per cent of GTN's annual cash distribution after certain thresholds are achieved, namely 100 per cent of distributions above US$20 million in the first five years and 25 per cent of distributions above US$20 million in subsequent years.

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Energy East Pipeline: On April 2, 2015, we announced that the marine and associated tank terminal in Cacouna, Québec will not be built as a result of the recommended reclassification of beluga whales as an endangered species. We are currently evaluating other options and amendments to the project are expected to be submitted to the NEB in fourth quarter 2015. The NEB has continued to process the application in the interim.

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•	Keystone Pipeline System: In July 2015, the Keystone Pipeline System marked the safe delivery of the one billionth barrel of Canadian and U.S. crude oil and celebrated the five-year anniversary of the official start of oil deliveries for the 4,247 km (2,639 mile) cross-border pipeline from Hardisty, Alberta to markets in the American Midwest and in 2014 to the U.S. Gulf Coast.

•	Keystone XL: In January 2015, the Department of State (DOS) re-initiated the national interest review and requested the eight federal agencies with a role in the review to complete their consideration of whether Keystone XL serves the national interest. All of the agency comments were submitted.

•	Heartland Pipeline and TC Terminals: On May 7, 2015, the Alberta Energy Regulator issued a permit for construction of the Heartland Pipeline. The in-service date of the project will be aligned to meet market requirements for incremental capacity between the Heartland region near Edmonton, Alberta and Hardisty, Alberta.

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Alberta Greenhouse Gas (GHG) Emissions: On June 25, 2015, the Alberta government announced a renewal and change to the Specified Gas Emitters Regulations (SGER) in Alberta. Since 2007 under the SGER, established industrial facilities with GHG emissions above a certain threshold are required to reduce their emissions by 12 per cent below an average intensity baseline and a carbon levy of $15 per tonne is placed on emissions above this target. The changed regulations include an increase in the emissions reductions target to 15 per cent in 2016 and 20 per cent in 2017, along with an increase in the carbon levy to $20 per tonne in 2016 and $30 per tonne in 2017. Our Sundance and Sheerness

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•	Ravenswood: In late May 2015, the 972 megawatt Unit 30 at the Ravenswood Generating Station returned to service after a September 2014 unplanned outage which resulted from a problem with the generator associated with the high pressure turbine.

•	Our Board of Directors declared a quarterly dividend of $0.52 per share for the quarter ending September 30, 2015 on TransCanada’s outstanding common shares. The quarterly amount is equivalent to $2.08 per common share on an annualized basis.

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Financing Activities: In May 2015, a newly formed financing trust (the Trust) issued US$750 million of 60-year junior subordinated trust notes to third party investors with a fixed interest rate of 5.625 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 us in US$750 million junior subordinated notes at a rate of 5.875 per cent which includes a 0.25 per cent administration charge. On a subordinated basis, the obligations of the Trust are guaranteed by TransCanada.

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Preferred Share Rate Reset and Conversion: In June 2015, Series 3 shareholders converted 5.5 million of our 14 million outstanding Series 3 Cumulative Redeemable First Preferred Shares on a one-for-one basis into Series 4 floating-rate Cumulative Redeemable First Preferred Shares. The rate on the Series 3 Shares was reset and they will now pay an annual fixed dividend rate of 2.152 per cent on a quarterly basis for the five-year period which began on June 30, 2015. The Series 4 Shares will pay a floating quarterly dividend for the same five-year period with the rate set for the first quarterly floating rate period (June 30, 2015 to but excluding September 30, 2015) at 1.945 per cent per annum and will be reset every quarter going forward.

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