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

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•	planned changes in our business 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 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

•	comparable funds generated from operations

•	comparable distributable cash flow

•	comparable distributable cash flow per common share

•	comparable earnings

•	comparable earnings per common share

•	comparable EBITDA

•	comparable EBIT

•	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 goodwill, investments and other assets including ongoing maintenance and liquidation costs

•	acquisition costs.

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

•	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

•

costs associated with the acquisition of Columbia including an after-tax charge of $67 million in third quarter, primarily relating to retention, severance and integration expenses, and $206 million year-to-date which included $109 million related to the dividend equivalent payments on the subscription receipts issued as part of the permanent financing of the transaction, $36 million related to acquisition costs and $6 million related to interest earned on the subscription receipt funds held in escrow

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

•	an after-tax charge of $9 million in third quarter and $24 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 year-to-date 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

•	$3 million of after-tax costs related to the monetization of our U.S. Northeast Power business

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

•	an after-tax charge of $6 million in third quarter and $14 million year-to-date 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 $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.

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•	higher earnings from U.S. Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition and higher ANR transportation and storage revenue resulting from higher rates effective August 1, 2016

•	higher interest expense from debt issuances and lower capitalized interest

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

•	higher contribution from Mexican pipelines primarily due to earnings from Topolobampo beginning in July 2016

•	higher interest income and other due to 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 earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant acquired in February 2016 and higher sales to customers in the PJM market, offset by lower capacity revenues in New York

•	higher earnings from Bruce Power mainly due to lower depreciation and our increased ownership interest, partially offset by higher losses from contracting activities

•	higher earnings from Canadian Pipelines primarily due to a higher NGTL investment base and incentive earnings from Canadian Mainline and NGTL.

•	higher earnings from our U.S. Pipelines due to incremental earnings from Columbia following the July 1, 2016 acquisition, higher ANR transportation and storage revenue resulting from higher rates effective August 1, 2016, higher ANR Southeast Mainline transportation revenues and lower OM&A expenses

•	higher interest expense from debt issuances and lower capitalized interest

•	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

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

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1	CFE has recognized that a force majeure has delayed construction and revenue has been recorded in third quarter 2016 as per terms of the Transportation Service Agreement (TSA). See the Recent developments section for more information.

2	In-service date is dependent on a positive final investment decision.

3	Our proportionate share.

4	Reflects U.S./Canada foreign exchange rate of $1.31 at September 30, 2016.

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1	Our proportionate share.

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

3	Excludes transfer of Canadian Mainline natural gas assets.

4	Reflects U.S./Canada foreign exchange rate of $1.31 at September 30, 2016.

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

2	We completed the acquisition of Columbia on July 1, 2016. Represents our effective ownership in these assets.

4	Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TCLP.

5	Represents our 30 per cent direct ownership interest until April 1, 2015 at which point the 30 per cent interest was sold to TCLP.

6	Represents our 61.7 per cent ownership interest in 2015 and 11.8 per cent effective January 1, 2016 as a result of the sale of 49.9 per cent interest to TCLP.

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

8	Comparable EBITDA for the portions of TCLP, PNGTS and Columbia Pipeline Partners LP that we do not own.

•	US$174 million of contributions from Columbia as a result of the acquisition on July 1, 2016

•	higher contribution from Mexican pipelines primarily due to incremental earnings from Topolobampo. The Topolobampo project has experienced a delay in construction, which, under the terms of the TSA, constitutes a force majeure and, as a result, we began realizing revenue in July 2016.

•	higher ANR transportation and storage revenue resulting from higher rates as part of our rates settlement effective August 1, 2016, higher ANR Southeast Mainline transportation revenues and lower OM&A expenses, offset by a first quarter 2015 non-recurring settlement with a producer

•	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 nine months ended September 30, 2016 were 802 Bcf (2015 – 833 Bcf). Average per day was 2.9 Bcf (2015 – 3.1 Bcf).

2	Field receipt volumes for the NGTL System for the nine months ended September 30, 2016 were 3,080 Bcf (2015 – 2,994 Bcf). Average per day was 11.2 Bcf (2015 – 11.0 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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•	a $1,085 million pre-tax impairment charge on the Ravenswood goodwill. As a result of information received during the process to monetize our U.S. Northeast Power business in third quarter 2016, it was determined that the fair value of Ravenswood no longer exceeds its carrying value.

•	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

•	$5 million of pre-tax costs related to the process of monetizing our U.S. Northeast Power business

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

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

•	higher earnings from U.S. Power mainly due to incremental earnings from the Ironwood power plant acquired in February 2016 and higher contributions from sales to customers in the PJM market, offset by lower capacity revenues in New York

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

•	higher earnings from Bruce Power mainly due to lower depreciation and our increased ownership interest, partially offset by higher losses from contracting activities.

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

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

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

•	higher earnings from Bruce Power mainly due to lower depreciation and our increased ownership interest, partially offset by lower volumes and higher operating costs from higher planned outage days.

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 comparable equity income from our investments in ASTC Power Partnership, which held the Sundance B PPA, and Portlands Energy. Comparable equity income does not include any gains or losses related to our risk management activities and, for the nine months ended September 30, 2016 excludes a $29 million charge related to the Sundance B PPA termination which was held in ASTC Power Partnership.

4	Included 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	Does not include Bécancour because power generation remains suspended.

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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 realized gains and losses from contracting activities 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 a flow-through basis estimated at approximately $5.00 per MWh.

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1	Includes Ironwood acquisition commencing February 1, 2016.

2	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.

3	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 nine months ended September 30, 2015 compared to the same period 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.

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

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

•	higher sales to wholesale utility 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 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 partially offset by higher sales to customers in the PJM wholesale utility market

•	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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•	acquisition and integration 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 of $109 million on the subscription receipts issued to partially fund the Columbia acquisition and $6 million of other acquisitions related costs. See the Financial condition section for more information.

•	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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•	higher interest expense on debt acquired in the acquisition of Columbia on July 1, 2016

•	higher foreign exchange on interest on 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 issued to partially fund the Columbia acquisition. See the Financial condition section for more information.

•	higher AFUDC related to our rate-regulated projects, primarily Mexico Pipelines, Energy East Pipeline, NGTL expansion and Columbia projects

•	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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•	our ability to generate cash flow from operations

•	our access to capital markets

•	approximately $8.6 billion of unutilized, unsecured committed credit facilities.

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

2	Reflects distributions received from equity investee operating activities and excludes additional distributions of $725 million resulting from Bruce Power's financing program.

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•	expansion of the NGTL System

•	construction of Mexico pipelines

•	expansion of the ANR pipeline

•	expansion of Columbia pipelines

•	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 the U.S. Northeast Power business monetizations and the November 2016 common equity offering will be used to partially repay these facilities.

2	Reflects coupon rate on re-opening of existing medium term notes (MTN) issue. New MTNs were issued at a premium resulting in a re-issuance yield of 2.69 per cent.

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 August 15, 2026 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

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2	The Junior subordinated unsecured notes were issued to TransCanada Trust. The interest rate is fixed at 6.125 per cent per annum and will reset starting August 2026 until August 2046 to the three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the three month LIBOR plus 5.64 per cent per annum.

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	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 September 30, 2016, the floating quarterly dividend rate for the Series 6 preferred shares is 2.073 per cent and will reset every quarter going forward.

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1	These facilities were put in place to finance a portion of the Columbia acquisition and bear interest at the LIBOR plus an applicable margin. Proceeds from the U.S. Northeast Power business monetizations and the November 2016 common equity offering will be used to partially repay these facilities.

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•	accounts receivable

•	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 nine months ended September 30, 2016, net realized gains of $1 million and $5 million, respectively, (2015 - gains of $2 million and $7 million, respectively) related to the interest component of cross-currency swaps settlements are included in interest expense.

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1	Realized and unrealized gains and losses on held for trading derivative instruments used to purchase and sell commodities are included net in revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held for trading derivative instruments are included net in interest expense and interest income and other, respectively.

2	Following the March 17, 2016 announcement of our intention to sell the U.S. Northeast Power business, a loss of $49 million and a gain of $7 million (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.

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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

•	impairment of goodwill and other assets.

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

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

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

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

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

•	a charge of $113 million related to costs associated with the acquisition of Columbia

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

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

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

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

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

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

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

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

•

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

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

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•	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 the U.S. Northeast Power business sales and the November 2016 common equity offering will be used to partially repay these facilities.

2	Reflects coupon rate on re-opening of existing medium term notes (MTN) issue. New MTNs were issued at a premium resulting in a re-issuance yield of 2.69 per cent.

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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 August 15, 2026 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 6.125 per cent per annum and will reset starting August 2026 until August 2046 to the three month LIBOR plus 4.89 per cent per annum; from August 2046 to August 2076 the interest rate will reset to the three month LIBOR plus 5.64 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 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 September 30, 2016 the floating quarterly dividend rate for the Series 6 preferred shares is 2.073 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 and cash flow hedges is net of non-controlling interest gains of $21 million and $3 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 is net of non-controlling interest losses of $80 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 $23 million ($14 million, net of tax) at September 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 12 for additional detail.

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1	Fair values equal carrying values.

2	In the three and nine months ended September 30, 2016, net realized gains of $1 million and $5 million, respectively, (2015 - gains of $2 million and $7 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 nine months ended September 30, 2016 included unrealized gains of $7 million and losses of $6 million, respectively, (2015 - losses of $9 million and $9 million, 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 September 30, 2016

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

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

1	Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities.

2	Unrealized gains and losses on other restricted investments are included in OCI.

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1	Fair value equals carrying value.

2	Includes purchases and sales of power, natural gas and liquids.

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1	Fair value equals carrying value.

2	Includes purchases and sales of power 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 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 nine months ended September 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 nine months ended September 30, 2016, revenues include unrealized gains of $1 million and $3 million, respectively, attributed to derivatives in the Level III category that were still held at September 30, 2016 (2015 - losses of $2 million and gains of $6 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	At September 30, 2016 exchange rate of $1.31

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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.

•	Third quarter financial results

•	Declared a quarterly dividend of $0.565 per common share for the quarter ending December 31, 2016

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

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

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•	Announced the 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

•	Issued US$1.2 billion of junior subordinated notes in the United States that mature in 2076

•	Announced that ANR filed a comprehensive settlement of its current Natural Gas Act Section 4 rate case with the Federal Energy Regulatory Commission (FERC)

•	Launched an open season on the Canadian Mainline seeking binding commitments on a new long-term, fixed price tolling option

•	On November 1, 2016, we announced the following strategic updates:

◦	An agreement to purchase all of the common units of Columbia Pipeline Partners LP (CPPL) for US$17.00 per common unit for a total amount of approximately US$915 million

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Acquisition of Columbia Pipeline Group: On July 1, 2016, we closed the US$13 billion acquisition of Columbia comprised of a purchase price of approximately US$10.3 billion and Columbia debt of approximately US$2.7 billion. The acquisition was financed through proceeds of $4.4 billion from the sale of subscription receipts, senior unsecured asset 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

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Monetization of U.S. Northeast Power business: On November 1, 2016, we announced that we expect to realize approximately US$3.7 billion from the monetization of our the U.S. Northeast Power business. This includes the announced sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors for US$2.2 billion and TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC for US$1.065 billion, with the remainder attributed to the marketing business which is expected to be realized going forward. These two sale transactions are expected to close in the first half of 2017 subject to certain regulatory and other approvals and will include closing adjustments. These sales are expected to result in an approximate $1.1 billion after-tax net loss which is comprised of a $656 million after-tax goodwill impairment charge recorded at September 30, 2016, an approximate $863 million after-tax net loss on the sale of the thermal and wind package to be recorded in fourth quarter 2016 and an approximate $443 million after-tax gain on the sale of the hydro assets upon close of that transaction. Proceeds from these sales and future realization of value of the marketing business will be used to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities which were used to partially finance the Columbia acquisition earlier this year.

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Decision to maintain our current ownership interest in Mexican natural gas pipelines: On November 1, 2016, we announced a decision to maintain our current ownership interest in a growing portfolio of natural gas pipeline assets in Mexico rather than sell a minority interest in six of these pipelines, which is consistent with maintaining a simple corporate structure. We currently own and operate the Tamazunchale and Guadalajara natural gas pipelines and are in the process of investing US$3.8 billion to develop and complete construction of four additional pipelines plus fund our interest in the Sur de Texas project, all of which will serve growing natural gas demand in Mexico. All projects are expected to be in-service by the end of 2018 and are underpinned by 25-year take-or-pay contracts with the Comisión Federal de Electricidad (CFE). Once completed, we expect our Mexican natural gas pipeline assets to be accretive to earnings per share and generate approximately US$575 million of annual EBITDA, up from US$181 million in 2015.

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Common Equity Offering: On November 1, 2016, in conjunction with our decision to maintain our current ownership interest in a growing Mexican natural gas pipelines business, and concurrent with the release of these financial results, we also entered into an agreement with a group of underwriters to proceed with an offering of common shares. The common shares will be offered to the public in Canada and the United States through the underwriters or their representatives. The offering is subject to the receipt of all necessary regulatory and stock exchange approvals. Proceeds from the offering will be used to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities which were used to partially finance the acquisition of Columbia.

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Agreement to Acquire Columbia Pipeline Partners LP: On November 1, 2016, we announced that we have entered into an agreement and plan of merger through which our wholly-owned subsidiary, Columbia Pipeline Group, Inc., has agreed to acquire, for cash, all of the outstanding publicly held common units of CPPL at a price of US$17.00 per common unit for an aggregate transaction value of approximately US$915 million. The transaction is expected to close in first quarter 2017 subject to receipt of CPPL unitholder approval and customary closing conditions and is expected to be accretive to earnings per share and simplify our corporate structure.

•	Dividend Declaration: Our Board of Directors declared a quarterly dividend of $0.565 per share for the quarter ending December 31, 2016 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.26 per common share on an annualized basis.

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•	Dividend Reinvestment Plan: Approximately $175 million or 39 per cent of dividends paid on October 31 were reinvested in TransCanada common shares through our Dividend Reinvestment Plan following the reinstatement of issuance from Treasury at a two per cent discount announced in July 2016.

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Other Financing Activities: In August 2016, TransCanada Trust issued US$1.2 billion of 60-year junior subordinated trust notes to third party investors with a fixed interest rate of 5.875 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$1.2 billion junior subordinated notes at a rate of 6.125 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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NGTL System: On October 31, 2016, the Government of Canada approved our $1.3 billion NGTL 2017 Facilities Application.  In addition, on October 6, 2016, the NEB recommended to the government approval of the $439 million Towerbirch Project. This project consists of a 55 km (34 miles) pipeline loop and a 32 km (20 miles) pipeline extension of the NGTL System in northwest Alberta and northeast B.C. The NEB approved NGTL’s continued use of its existing rolled-in toll methodology for this project. Of NGTL’s $5.4 billion near-term capital program, we have received approvals for $4.0 billion, while $0.5 billion has been filed and is awaiting approval. Approximately $0.9 billion is expected to be filed with regulators in the future.

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North Montney Mainline: In March 2016, we filed a request with the NEB for a one year extension to the June 10, 2016 sunset clause in the North Montney Mainline project Certificate of Public Convenience and Necessity. On September 15, 2016, the NEB approved the sunset clause extension to June 10, 2017. The extension continues to be subject to the condition that construction shall not begin until a positive Final Investment Decision (FID) has been made on the Pacific Northwest LNG (PNW LNG) Project. NGTL continues to work with our customers and stakeholders to be ready to initiate construction of the North Montney facilities, however, the in-service date will be finalized once a FID has been made.

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Canadian Mainline Tolling Option: On October 13, 2016, we launched an open season on the Canadian Mainline seeking binding commitments on a new long-term, fixed-price proposal to transport WCSB supply from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The contract term for this service is ten years with tolls ranging from $0.75/GJ to $0.82/GJ depending on the shippers’ contract volume commitments. Early termination rights are provided and can be exercised following the initial five years of service upon payment of a premium fee. Subject to a successful Open Season that closes November 10, 2016 and to NEB regulatory approval, the new service is targeted to begin November 1, 2017.

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Columbia Capital Projects: As part of the Columbia acquisition, we are progressing a US$7.4 billion capital expansion and modernization program across the Columbia system for facilities planned to be in-service from 2016 to 2020. We also expect to invest approximately US$0.3 billion to construct the Gibraltar Pipeline project, an approximate 1 MMDth/d dry gas header pipeline in southwest Pennsylvania.

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ANR Section 4 Rate Case Settlement: On September 16, 2016, ANR filed with FERC an unopposed settlement agreement with its customers for approval. Effective August 1, 2016, transmission reservation rates increased by 34.8 percent with storage rates largely remaining unchanged. The settlement includes a moratorium on further rate changes until August 1, 2019. ANR may file for new rates after that date if it has spent more than US$0.8 billion in capital additions but must file for new rates with an effective date of no later than August 1, 2022.

•	Topolobampo Pipeline: In July, we began collecting revenue on the US$1 billion Topolobampo project under a force majeure provision in the 25-year contract with the Comisión Federal de Electricidad. The physical in-service date is expected to be delayed into 2017 due to right-of-way acquisition delays.

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•	Prince Rupert Gas Transmission: On September 27, 2016, PNW LNG received an environmental certificate from the Government of Canada for a proposed LNG plant at Prince Rupert, B.C. PNW LNG has indicated they will conduct a total project review over the coming months prior to announcing next steps for the project.

•	Coastal GasLink: On July 11, 2016, the LNG Canada joint venture participants announced a delay to their FID 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 we are working with LNG Canada to determine the appropriate pacing of the Coastal GasLink development schedule and work activities.

•	Houston Lateral and Terminal: In August 2016, the Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline System to Houston, Texas went into service. The terminal has an initial storage capacity of 700,000 barrels of crude oil.

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Energy East Pipeline: On August 8, 2016, the NEB commenced the first of a series of community panel sessions held along the pipeline route in New Brunswick. Panel sessions scheduled for the week of August 29, 2016 in Montréal, Québec were subsequently canceled as three NEB panelists announced their decision to recuse themselves from continuing to sit on the panel to review the project due to allegations of reasonable apprehension of bias. The Chair of the NEB and the Vice Chair, who is also a panel member, have recused themselves of any further duties related to the project. As a result, all hearings for the project were adjourned until further notice as we wait on the federal government to appoint new NEB members and then for the NEB to establish a new panel to hear our applications. The new panel members will then determine how the review process is to be re-initiated. As a result of these actions, we expect a delay in the NEB review process.

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Bécancour Tolling Agreement: In August 2015, we executed an agreement with Hydro Québec (HQ) allowing HQ to dispatch up to 570 MW of peak winter capacity from our Bécancour facility for a term of 20 years commencing in December 2016. The regulator in Québec, Régie de l'énergie (the Régie), initially accepted this agreement for implementation but in July 2016, the Régie reversed its initial decision. HQ continues to advocate for the contract on its economic merit as part of their strategy to meet the winter peak capacity needs of the province and is pursuing regulatory options for our agreement to be reinstated. We expect the project need and potential timing will be reassessed in the recently released review of HQ's ten year supply plan.

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