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1	Comparable EBITDA, comparable earnings, comparable earnings per common share, 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 including the divestiture of certain assets

•	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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•	planned monetization of our U.S. Northeast power assets and a minority interest in our Mexican natural gas pipeline business

•	inflation rates, commodity prices and capacity prices

•	timing of financings and hedging

•	regulatory decisions and outcomes

•	termination of the Alberta PPAs

•	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 realize the anticipated benefits of the acquisition of Columbia

•	timing and execution of our planned asset sales

•	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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•	EBITDA

•	EBIT

•	funds generated from operations

•	distributable cash flow

•	distributable cash flow per common share

•	comparable earnings

•	comparable earnings per common share

•	comparable EBITDA

•	comparable EBIT

•	comparable distributable cash flow

•	comparable distributable cash flow per common share

•	comparable income from equity investments

•	comparable interest expense

•	comparable interest income and other

•	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

•	impairment of assets and investments including ongoing maintenance and liquidation costs

•	acquisition costs.

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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 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 form 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.

•	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

•	an after-tax charge of $8 million 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.

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•	higher interest income and other due to increased AFUDC related to our rate-regulated projects and realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income

•	higher interest expense from debt issuances and lower capitalized interest

•	lower earnings from Bruce Power mainly due to higher planned outage days, partially offset by lower depreciation

•	higher earnings from U.S. and International Pipelines due to higher ANR Southeast Mainline transportation revenues and lower OM&A expenses

•	lower earnings from Liquids Pipelines due to lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink

•	higher earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant acquired February 1, 2016 and insurance recoveries related to an unplanned outage at Ravenswood

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

•	higher interest income and other due to increased AFUDC related to our rate-regulated projects and realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income

•	higher interest expense from debt issuances and lower capitalized interest

•	lower earnings from Liquids Pipelines due to lower uncontracted volumes on Keystone Pipeline and lower volumes on Marketlink

•	higher earnings from our U.S. and International Pipelines due to higher ANR Southeast Mainline transportation revenues and lower OM&A expenses, offset by a first quarter 2015 non-recurring settlement

•	lower earnings from U.S. Power mainly due to decreased margins on sales to wholesale, commercial and industrial customers, the impact of lower capacity prices in New York and lower realized prices in both New England and New York, offset by incremental earnings from the Ironwood power plant and insurance recoveries related to an unplanned outage at Ravenswood

•	lower earnings from Eastern Power due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour

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

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1	Reflects U.S./Canada foreign exchange rate of $1.30 at June 30, 2016.

1	Our proportionate share.

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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.

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1	Results from TQM, Northern Border, Iroquois and TransGas reflect our share of equity income from these investments. We closed the purchase of an additional 4.87 per cent interest in Iroquois on March 31, 2016 and an additional 0.65 per cent interest on May 1, 2016.

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

4	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.

5	Represents our 61.7 per cent ownership interest in 2015. Effective January 1, 2016, our direct ownership interest in PNGTS was 11.8 per cent as a result of the dropdown transaction between us and TC PipeLines, LP.

6	Includes our share of the equity income from TransGas as well as general and administration costs relating to our U.S. and International Pipelines.

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

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•	higher ANR Southeast Mainline transportation revenues and lower OM&A expenses, offset by a first quarter 2015 non-recurring settlement

•	lower contributions from Mexican Pipelines primarily due to lower revenue

•	higher transportation revenues from Great Lakes

•	higher contribution from TC PipeLines, LP.

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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, 2016 were 530 Bcf (2015 – 564 Bcf). Average per day was 2.9 Bcf (2015 – 3.1 Bcf).

2	Field receipt volumes for the NGTL System for the six months ended June 30, 2016 were 2,075 Bcf (2015 – 2,006 Bcf). Average per day was 11.4 Bcf (2015 – 11.1 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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•	lower uncontracted volumes on Keystone Pipeline

•	lower volumes on Marketlink

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

•	lower business development spending

•	growing contribution of Liquids Marketing.

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•	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 in March 2016

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

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1	Included Sundance A and Sheerness PPAs, and the Sundance B PPA held through our investment in ASTC Power Partnership up to March 7, 2016.

2	Included our share of equity income from our investments in ASTC Power Partnership up to March 7, 2016, Portlands Energy and Bruce Power.

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•	lower earnings from Bruce Power mainly due to higher planned outage days, partially offset by lower depreciation

•	higher earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant in Lebanon, Pennsylvania acquired February 1, 2016 and insurance recoveries related to an unplanned outage at Ravenswood

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

•	lower earnings from Eastern Power due to lower contractual earnings at Bécancour.

•	lower earnings from U.S. Power mainly due to decreased margins on sales to wholesale, commercial and industrial customers, the impact of lower capacity prices in New York and lower realized prices in both New England and New York, offset by incremental earnings from the Ironwood power plant and insurance recoveries related to an unplanned outage at Ravenswood

•	lower earnings from Eastern Power due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour

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

•	lower earnings from Bruce Power mainly due to higher planned outage days, partially offset by lower depreciation and higher gains from contracting activities

•	higher earnings from Natural Gas Storage due to higher realized natural gas storage price spreads.

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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 and sale of excess natural gas purchased for generation.

3	Includes our share of equity income from our investments in ASTC Power Partnership, which held the Sundance B PPA, and Portlands Energy. Comparable equity income excludes a $29 million charge related to the Sundance B PPA termination which was held in ASTC Power Partnership and does not include any gains or losses related to our risk management activities.

4	Includes Sundance A, Sundance B and Sheerness PPAs up to March 7, 2016.

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1	Includes volumes from Sundance A and Sheerness PPAs and our 50 per cent ownership interest of the Sundance B PPA held through the ASTC Power Partnership up to March 7, 2016.

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

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

4	Plant availability was lower in the three and six months ended June 30, 2016 than the same periods in 2015 due to an unplanned outage at the Mackay River facility as a result of the Northern Alberta wildfires.

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

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1	Represents our 48.5 per cent ownership interest in Bruce Power after the merger on December 4, 2015 and our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B up to December 3, 2015. 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 revenues from contract settlements and cost flow-through items.

4	Excludes unrealized gains and losses on contracting activities and revenues from cobalt sales.

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1	Includes fuel and lease expenses recovery on a flow-through basis estimated at approximately $8.00 per MWh.

1	Includes fuel expense recovery on flow-through basis estimated at approximately $5.00 per MWh.

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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	Increase primarily due to Ironwood acquisition.

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

3	Plant availability was lower in the three and six months ended June 30, 2015 compared to the same periods in 2016 due to an unplanned outage at the Ravenswood facility from September 2014 to May 2015.

1	New England ISO all hours Mass Hub price.

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

3	The METED Zone price in Pennsylvania where the Ironwood plant operates. Average price for the six months ended June 30, 2016 is from the Ironwood acquisition date of February 1 to June 30, 2016.

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•	higher earnings due to our acquisition of the Ironwood power plant on February 1, 2016

•	higher earnings resulting from 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

•	insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008

•	lower capacity revenues due to lower realized capacity prices in New York and the impact of lower availability as a result of a unit outage from September 2014 to May 2015, partially offset by insurance recoveries, net of deductibles at Ravenswood.

•	lower margins on sales to wholesale, commercial and industrial customers offset by higher sales to customers in the PJM market

•	lower capacity revenues due to lower realized capacity prices in New York and the impact of lower availability as a result of a unit outage from September 2014 to May 2015, partially offset by insurance recoveries, net of deductibles at Ravenswood

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

•	higher earnings due to our acquisition of the Ironwood power plant

•	insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008.

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•	costs associated with the acquisition of Columbia

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

1	This amount represents the dividend equivalent payments on the subscription receipts. See the Financial condition section for more information on the subscription receipts.

•	higher interest expense as a result of long-term debt issuances in 2015 and 2016, partially offset by Canadian and U.S. dollar-denominated debt maturities

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

•	lower capitalized interest on Keystone XL and related projects following the November 6, 2015 denial of a U.S. Presidential Permit, partially offset by higher capitalized interest on liquids projects, LNG projects and the Napanee power generating facility.

1	This amount represents interest income on the gross proceeds of the subscriptions receipts held in escrow. See the Financial condition section for more information on the subscription receipts.

•	increased AFUDC related to our rate-regulated projects including Mexico pipelines, expansions on the NGTL System and the ANR Southeast Mainline

•	realized gains in 2016 compared to realized losses in 2015 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar denominated income.

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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 $8.7 billion of unutilized, unsecured committed credit facilities.

1	Reflects distributions received from operating activities and excludes additional distributions of $725 million following Bruce Power's financing program.

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•	expansion of the NGTL System

•	construction of Mexico pipelines

•	expansion of the ANR pipeline

•	construction of the Northern Courier pipeline

•	expansion of the Canadian Mainline

•	construction of the Napanee power generating facility.

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1	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at LIBOR plus an applicable margin. Proceeds from specified asset monetizations must be used to repay these facilities. Proceeds from these facilities are held in Restricted cash. See Recent developments section for more information.

2	Reflects coupon rate. Re-issuance yield was 2.69 per cent.

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1	Includes repurchases of common shares pursuant to private agreements with third-parties.

2	Includes brokerage fees.

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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 6 preferred shares. The holders of Series 6 preferred shares are entitled to receive a quarterly floating rate cumulative preferred dividend, 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. In addition, Series 6 preferred shares are redeemable by us at any time other than on a designated redemption option date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.

3	Commencing June 30, 2016, the floating quarterly dividend rate for the Series 6 preferred shares is 2.034 per cent and will reset every quarter going forward.

1	Dividend equivalent payments are a term of the subscription receipts and are not declared by the Board.

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1	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at Libor plus an applicable margin. Proceeds from specified asset monetizations must be used to repay these facilities. See Recent developments section for more information.

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•	accounts receivable

•	restricted investments

•	the fair value of derivative assets

•	cash and cash equivalents

•	notes receivable.

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1	Fair values equal carrying values.

2	In the three and six months ended June 30, 2016, net realized gains of $2 million and $4 million, respectively, (2015 - gains of $2 million and $5 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.

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2	Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast power assets, a loss of $49 million and a gain of $7 million (2015 - nil) 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 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	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at Libor plus an applicable margin. Proceeds from specified asset sales must be used to repay these facilities. Proceeds from these facilities are held in Restricted cash. See Note 15, Subsequent event for more information.

2	Reflects coupon rate. Re-issuance yield was 2.69 per cent.

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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 6 preferred shares. The holders of Series 6 preferred shares are entitled to receive a quarterly floating rate cumulative preferred dividend as and when declared by the Board.

2

TransCanada may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary date thereafter. In addition, Series 6 preferred shares are redeemable by TransCanada at any time other than on a designated redemption option date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.

3	The holder will have the right, subject to certain conditions, to convert their first preferred shares of a specified series into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter.

4	Commencing June 30, 2016, the floating quarterly dividend rate for the Series 6 preferred shares is 2.034 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 (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest gains of $3 million and losses of $1 million, respectively.

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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 $101 million and $3 million, respectively.

3

Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $22 million ($14 million, net of tax) at June 30, 2016. 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.

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	In the three and six months ended June 30, 2016, net realized gains of $2 million and $4 million, respectively, (2015 - gains of $2 million and $5 million, respectively) related to the interest component of cross-currency swap settlements are included in interest expense.

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$800 million (December 31, 2015 - 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, 2016 included unrealized losses of $1 million and $13 million, respectively, (2015 - gains of $3 million and nil, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$800 million of long-term debt at June 30, 2016 (December 31, 2015 - US$850 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	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 and natural gas.

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

1	Volumes for power and natural gas derivatives are in GWh and Bcf, 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 merchant power assets, a loss of $49 million and a gain of $7 million (2015 - nil) 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, 2016.

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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, 2015.

1	For the three and six months ended June 30, 2016, revenues include unrealized gains of $6 million and $8 million attributed to derivatives in the Level III category that were still held at June 30, 2016 (2015 - gains of $11 million and $8 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.

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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 financial results

•	Declared a quarterly dividend of $0.565 per common share for the quarter ending September 30, 2016

•	On July 1, 2016, we closed the acquisition of Columbia valued at US$13 billion comprised of a purchase price of approximately US$10.3 billion and Columbia debt of approximately US$2.7 billion

•	On July 4, 2016, exchanged 96.6 million subscription receipts into the same number of common shares

•	Awarded a contract to construct the US$2.1 billion Sur de Texas to Tuxpan pipeline in Mexico, a joint venture with IEnova. TransCanada holds a 60 per cent interest in the joint venture and will operate the pipeline

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•	Announced reinstatement of issuance of common shares from treasury at a two per cent discount under TransCanada's Dividend Reinvestment Plan commencing with the dividends declared on July 27, 2016

•	Continued to advance the monetization of the Company's U.S. Northeast power assets and a minority interest in its Mexican pipeline business.

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Acquisition of Columbia Pipeline Group: On July 1, 2016, we closed the acquisition of Columbia valued at US$13 billion, comprised of a purchase price of approximately US$10.3 billion and Columbia debt of approximately US$2.7 billion. The acquisition was initially financed through proceeds of $4.4 billion from the sale of subscription receipts, bridge term loan credit facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and following closing of the acquisition, were exchanged into 96.6 million TransCanada common shares. We are targeting US$250 million of annual cost, revenue and financing benefits over the next two years and expect the acquisition, net of financing and the planned asset monetizations, to be accretive to earnings per share in the first full year of ownership.

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Monetization of U.S. Northeast power assets and a minority interest in Mexican pipelines: The permanent financing for the acquisition of the Columbia Pipeline Group involves portfolio management that includes the monetization of our U.S. Northeast power assets and a minority interest in our Mexico gas pipeline business. The process of engaging advisors has been completed and the initial stages of soliciting interested parties is well underway. We expect to provide an update as to the outcome of that process by the end of 2016. Proceeds from these monetizations will be used to retire draws from the bridge loan facilities.

•	Master Limited Partnership Strategy Review: On July 1, 2016, we announced that a financial advisor has been retained to assist us in developing a master limited partnership (MLP) strategy. A decision on the MLP strategy is expected to be communicated by the end of 2016.

•	Dividend Declaration: Our Board of Directors declared a quarterly dividend of $0.565 per share for the quarter ending September 30, 2016 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.26 per common share on an annualized basis.

•	Dividend Reinvestment Plan: Reinstated issuance of common shares from treasury at a two per cent discount under TransCanada's Dividend Reinvestment Plan commencing with the dividends declared on July 27, 2016.

•	Debt offerings: During the second quarter TransCanada issued $300 million of seven year medium term notes and $700 million of thirty year notes in Canada at interest rates of 3.69 per cent and 4.35 per cent,

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NGTL System: In second quarter 2016, we placed approximately $450 million of facilities in service with another $400 million of facilities approved and currently under construction.  New long term delivery contracts on the NGTL System to the Alberta/BC border (Sundre Crossover project) will require construction of approximately $135 million in facilities not previously included in our 2018 Facilities program.  We are currently assessing additional demand requests. A re-evaluation of facility requirements to meet future aggregate system service requirements has been undertaken.  As a result, some changes in our spending profile are expected to occur to match revised facility in-service dates. The total estimated projected capital for the NGTL System remains at approximately $7.3 billion, including the Sundre Crossover project, and the North Montney and Merrick pipelines. We expect deferrals of approximately $225 million related to the 2016/17 Facilities program and $210 million related to the 2018 Facilities program with revised in-service dates from 2018 through 2020.

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Sur de Texas-Tuxpan Pipeline: On June 13, 2016, we announced that our joint venture with IEnova was chosen to build, own and operate the US$2.1 billion Sur de Texas-Tuxpan pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 2.6 billion cubic feet per day with the Comisión Federal de Electricidad (CFE). TransCanada holds a 60 per cent interest in the joint venture and will operate the asset. We expect to invest approximately US$1.3 billion in the partnership to construct the 42-inch diameter, approximately 800-kilometre (km) (497-mile) pipeline and anticipate an in-service date of late 2018. The pipeline will start offshore in the Gulf of Mexico, at the border point near Brownsville, Texas and end in Tuxpan, Mexico, in the state of Veracruz. The pipeline will connect to TransCanada’s Tamazunchale and Tuxpan-Tula pipelines as well as with other transporters in the region.

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Tula-Villa de Reyes Pipeline: On April 11, 2016, we announced we were awarded the contract to build, own and operate the Tula-Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 million cubic feet per day with the CFE. We expect to invest approximately US$550 million in a 36-inch diameter, 420-km (261-mile) pipeline with an anticipated in-service date of early 2018. The pipeline will begin in Tula, in the state of Hidalgo, and terminate in Villa de Reyes, in the state of San Luis Potosí, transporting natural gas to power generation facilities in the central region of the country. The project will interconnect with our Tamazunchale and Tuxpan-Tula pipelines as well as with other transporters in the region.

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ANR Section 4 Rate Case: In January 2016, ANR filed a Section 4 Rate Case with the Federal Energy Regulatory Commission (FERC) that requests an increase to ANR's maximum transportation rates. In February 2016, the FERC issued an order that accepted and suspended ANR’s rate and tariff changes to become effective August 1, 2016, subject to refund and the outcome of a hearing. In addition, in March 2016, the FERC established a procedural schedule for the hearing and appointed a settlement judge to assist the parties in their settlement negotiations. The hearing is currently scheduled for early February 2017.

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Coastal GasLink: On July 11, 2016, the LNG Canada joint venture participants announced a delay to their final investment decision for the proposed liquefied natural gas facility in Kitimat, BC.  At this time a future FID date has not been determined.  In light of this announcement, TransCanada is working with LNG Canada to determine the appropriate pacing of the Coastal GasLink development schedule and work activities.

•	Houston Lateral and Terminal: We commenced commercial transactions in July 2016 for August 2016 deliveries on the Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline System to Houston, Texas. The terminal has an initial storage capacity of 700,000 barrels of crude oil.

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Energy East Pipeline: On May 17, 2016, we filed a consolidated application with the National Energy Board (NEB) for Energy East. On June 16, 2016, Energy East achieved a major milestone with the NEB determining the application sufficiently complete to initiate the formal regulatory review process. This determination of completeness marks the start of the mandated twenty one month NEB review process, which culminates in a formal recommendation to the Governor in Council (Federal Cabinet). The Governor in Council will then have six months to decide whether to approve the project and if so, on what conditions.

•	Bruce Power Financing: In second quarter 2016, Bruce Power issued bonds and borrowed under its bank credit facility as part of its financing program to fund its capital program and make distributions to its partners. Distributions received from Bruce Power in second quarter 2016 included $725 million from this financing program.

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