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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 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 dividend growth

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

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

•	expected regulatory processes and outcomes

•	expected impact of regulatory outcomes

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

•	expected capital expenditures and contractual obligations

•	expected operating and financial results

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

•	expected industry, market and economic conditions.

•	inflation rates, commodity prices and capacity prices

•	nature and scope of hedging

•	regulatory decisions and outcomes

•	foreign exchange rates

•	interest rates

•	tax rates

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

•	integrity and reliability of our assets

•	access to capital markets

•	anticipated construction costs, schedules and completion dates.

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

•	the operating performance of our pipeline and energy assets

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

•	the availability and price of energy commodities

•	the amount of capacity payments and revenues 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 regulatory environment

•	changes in the political environment

•	changes in environmental and other laws and regulations

•	competitive factors in the pipeline and energy sectors

•	construction and completion of capital projects

•	costs for labour, equipment and materials

•	access to capital markets

•	interest, tax and foreign exchange rates

•	weather

•	cyber security

•	technological developments

•	economic conditions in North America as well as globally.

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•	comparable earnings

•	comparable earnings per common share

•	comparable EBITDA

•	comparable EBIT

•	funds generated from operations

•	comparable funds generated from operations

•	comparable distributable cash flow

•	comparable distributable cash flow per common share.

•	certain fair value adjustments relating to risk management activities

•	income tax refunds and adjustments and changes to enacted tax rates

•	gains or losses on sales of assets

•	legal, contractual and bankruptcy settlements

•	impact of regulatory or arbitration decisions relating to prior year earnings

•	restructuring costs

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

•	acquisition and integration costs.

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•	a $243 million after-tax net gain related to the monetization of our U.S. Northeast power business, which included a $440 million after-tax gain on the sale of TC Hydro, an incremental loss of $183 million after tax recorded on the sale of the thermal and wind package and $14 million year-to-date of after-tax disposition costs and income tax adjustments

•	an after-tax charge of $30 million in third quarter and $69 million year-to-date for integration-related costs associated with the acquisition of Columbia

•	an after-tax charge of $8 million in third quarter and $19 million year-to-date related to the maintenance of Keystone XL assets which is being expensed pending further advancement of the project

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

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

•	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 also 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 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 formed 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

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

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•	lower contribution from U.S. Power due to the monetization of our U.S. Northeast power generation assets in second quarter 2017

•	lower contribution from U.S. Natural Gas Pipelines primarily due to the timing of funding contributions to the Columbia Gas defined benefit pension plan, partially offset by higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016

•	higher AFUDC on our rate-regulated U.S. natural gas pipelines

•	lower interest expense mainly due to the repayment of the remaining bridge facilities that partially funded the acquisition of Columbia

•	higher interest income and other primarily due to realized gains in 2017 compared to realized losses in 2016 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income and income recognized on the termination of the PRGT project

•	higher contribution from Liquids Pipelines primarily due to higher volumes on Keystone and the commencement of operations on Grand Rapids

•	higher earnings from Bruce Power mainly due to improved results from contracting activities

•	higher contribution from Mexico Natural Gas Pipelines primarily due to earnings from Mazatlán beginning in December 2016, partially offset by the impairment of our equity investment in TransGas.

•	higher contribution from U.S. Natural Gas Pipelines due to incremental earnings resulting from the Columbia acquisition on July 1, 2016, higher ANR transportation revenues resulting from a FERC-approved rate settlement effective August 1, 2016, partially offset by the timing of funding contributions to the Columbia Gas defined benefit pension plan

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

•	higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlán beginning in December 2016, partially offset by the impairment of our equity investment in TransGas

•	higher earnings from Liquids Pipelines primarily due to higher volumes on Keystone and the commencement of operations on Grand Rapids

•	higher AFUDC on our rate-regulated U.S. natural gas pipelines, as well as the NGTL System, partially offset by the commercial in-service of Topolobampo and completion of Mazatlán construction

•	higher interest income and other due to income related to Coastal GasLink project costs and the termination of the PRGT project

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

•	lower contribution from U.S. Power due to the monetization of our U.S. Northeast power generation assets in second quarter 2017

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

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1	Beginning in second quarter 2017, near-term NGTL System capital projects are being reported by expected in-service dates.

2	Our proportionate share.

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

4	Reflects U.S./Canada foreign exchange rate of 1.25 at September 30, 2017.

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1	Our proportionate share.

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

3	Reflects U.S./Canada foreign exchange rate of 1.25 at September 30, 2017.

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

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1	Field receipt volumes for the NGTL System for the nine months ended September 30, 2017 were 3,111 Bcf (2016 – 3,080 Bcf). Average per day was 11.4 Bcf (2016 – 11.2 Bcf).

2	Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the nine months ended September 30, 2017 were 716 Bcf (2016 – 802 Bcf). Average per day was 2.6 Bcf (2016 – 2.9 Bcf).

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

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

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

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

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

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

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•	the timing of funding contributions to the Columbia Gas defined benefit pension plan. Under the current rate settlement for Columbia Gas, pension costs are reflected in expense as funding occurs and the full 2017 pension funding for this plan was recorded in third quarter 2017

•	increased revenue from Columbia Gas growth projects

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

•	the earnings contribution resulting from the Columbia acquisition for nine months in 2017 compared to only three months in 2016

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

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

2	Reflects results from our 46.5 per cent equity investment in TransGas. On August 25, 2017, TransGas transferred all of its pipeline assets to Transportadora de Gas Internacional S.A..

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

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

•	equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada

•	the impairment of our equity investment in TransGas. See Recent developments section for further detail.

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•	higher volumes on Keystone pipeline

•	higher contribution from liquids marketing activities

•	contribution from Grand Rapids pipeline, which was placed in service in late-August 2017

•	increased business development activities, including advancement of Keystone XL

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

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

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

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

4	Depreciation of U.S. Northeast power assets ceased effective November 2016 when classified as held for sale.

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•	in 2017, a net gain of $469 million before tax related to the monetization of our U.S. Northeast power business which included a $715 million gain on the sale of TC Hydro, a loss of $226 million on the sale of the thermal and wind package and $20 million (2016 - $5 million) of pre-tax disposition costs. See Recent developments section for more details

•	in 2016, 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, it was determined that the fair value of Ravenswood no longer exceeded its carrying value

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

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

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

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

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

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

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1	Represents our 48.4 per cent (2016 - 48.5 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation.

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

3	Calculation based on actual and deemed generation. Realized sales prices per MWh includes realized gains and losses from contracting activities and cost flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues.

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1	Reported in Income from equity investments on the condensed consolidated statement of income.

•	integration and acquisition costs associated with the acquisition of Columbia

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

•	in 2016, restructuring costs related to expected future losses under lease commitments.

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•	final repayment of the Columbia acquisition bridge facilities in June 2017

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

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

•	long-term debt and junior subordinated notes issuances, partially offset by Canadian and U.S. dollar-denominated debt maturities

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

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

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

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

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

•	$10 million of income recognized on the termination of the PRGT project, mainly related to the recovery of carrying costs. See Recent developments section for more information

•	interest income and foreign exchange impact related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The foreign exchange impact is offset in Corporate segmented losses and is excluded from comparable earnings

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

•	income of $20 million related to Coastal GasLink project costs incurred to date and $10 million recognized on the termination of the PRGT project, mainly related to the recovery of carrying costs. See Recent developments section for more information

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

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

•	interest income and foreign exchange impact related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The foreign exchange impact is offset in Corporate segmented losses and is excluded from comparable earnings

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

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•	our ability to generate cash flow from operations

•	our access to capital markets

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

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

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•	expansion of Columbia Gas and Columbia Gulf pipelines

•	expansion of the NGTL System

•	construction of Mexico pipelines

•	expansion of the Canadian Mainline

•	capital additions to our ANR pipeline

•	construction of the Napanee power generating facility.

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

2

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

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•	accounts receivable

•	the fair value of derivative assets

•	cash and cash equivalents.

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1	Fair values equal carrying values.

2	In the three and nine months ended September 30, 2017, condensed consolidated net income includes net realized gains of $1 million and $3 million, respectively, (2016 - gains of $1 million and $5 million, respectively) related to the interest component of cross-currency swap settlements which are reported within interest expense.

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

2	In the three and nine months ended September 30, 2017, there were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2016 - nil and a net loss of $42 million, respectively).

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

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

3	Reported within interest 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

•	short term revenues from available capacity not committed under long term contract, driven by changing short term market conditions.

•	weather

•	customer demand

•	market prices for natural gas and power

•	capacity prices and payments

•	planned and unplanned plant outages

•	acquisitions and divestitures

•	certain fair value adjustments

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

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•	an after-tax charge of $30 million for integration-related costs associated with the acquisition of Columbia

•	an after-tax charge of $12 million for post-closing and income tax adjustments related to the monetization of our U.S. Northeast power business

•	an after-tax charge of $8 million related to the maintenance of Keystone XL assets which is being expensed pending further advancement of the project.

•	a $265 million net after-tax gain related to the monetization of our U.S. Northeast power business which included a $441 million after-tax gain on the sale of TC Hydro and a loss of $176 million after tax on the sale of the thermal and wind package

•	an after-tax charge of $15 million for integration-related costs associated with the acquisition of Columbia

•	an after-tax charge of $4 million related to the maintenance of Keystone XL assets which are being expensed pending further advancement of the project.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•	an $86 million after-tax loss provision related to the sale of TC Offshore which closed 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 formed part of a restructuring initiative which commenced in 2015 to maximize the effectiveness and efficiency of our existing operations and reduce overall costs

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

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

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

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

2

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

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

2	Other comprehensive (loss)/income before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest losses of $68 million and losses of $1 million, respectively.

3	Other comprehensive (loss)/income before reclassifications on pension and OPEB plan adjustments includes a $27 million reduction on settlements and curtailments.

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 net of non-controlling interest losses of

3	Other comprehensive (loss)/income before reclassifications on pension and OPEB plan adjustments includes a $27 million reduction on settlements and curtailments.

4

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 $10 million ($7 million, net of tax) at September 30, 2017. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

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

2	These accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 10 for additional detail.

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1	Fair values equal carrying values.

2	In the three and nine months ended September 30, 2017, Net income includes net realized gains of $1 million and $3 million, respectively, (2016 - gains of $1 million and $5 million, respectively) related to the interest component of cross-currency swap settlements which are reported within Interest expense.

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

2

Net income for the three and nine months ended September 30, 2017 included unrealized gains of $1 million and $2 million, respectively, (2016 unrealized gains of $7 million and losses of $6 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of long-term debt at September 30, 2017 (December 31, 2016 - US$850 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

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

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

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

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

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1	Fair value equals carrying value.

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

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1	Fair value equals carrying value.

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

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

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

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

2	In the three and nine months ended September 30, 2017, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would not occur (2016 - nil and a net loss of $42 million, respectively).

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

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

3	Reported within Interest 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, 2017.

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1	There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2016.

1	For the three and nine months ended September 30, 2017, revenues include unrealized losses of $10 million and $14 million, respectively, attributed to derivatives in the Level III category that were still held at September 30, 2017 (2016 - gains of $1 million and $3 million, respectively).

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

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1.	I have reviewed this quarterly report on Form 6-K of TransCanada Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

1.	I have reviewed this quarterly report on Form 6-K of TransCanada Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.	The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the issuer’s most recent fiscal quarter (the issuer’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.	The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

1.	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

1.	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

•	Third quarter 2017 financial results

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•	Declared a quarterly dividend of $0.625 per common share for the quarter ending December 31, 2017

•	Placed the $0.9 billion Grand Rapids pipeline in service

•	Received approval from Canada's National Energy Board (NEB) to commence service on the Canadian Mainline long-term fixed price service effective November 1, 2017

•	After careful review of changed circumstances, announced the termination of Energy East and related projects and expect an estimated $1 billion after-tax non-cash charge will be recorded in fourth quarter 2017

•	In October, received $0.6 billion related to development costs and carrying charges on the Prince Rupert Gas Transmission (PRGT) project following Progress Energy's decision to terminate their agreement with us

•	Raised $1 billion in proceeds through a Canadian offering of Medium Term Notes maturing in 2028 and 2047

•	On October 25, announced an agreement to sell our Ontario solar portfolio for approximately $540 million with proceeds to be used to partially fund our near-term capital program. The transaction is expected to result in an estimated $100 million after-tax gain to be recognized upon closing

•	In November, the $1 billion Northern Courier pipeline achieved commercial in-service, and we placed the US$0.4 billion Rayne XPress pipeline and the US$0.3 billion Gibraltar project in service. We expect to bring the US$1.6 billion Leach XPress project in service in early January 2018

•	Advanced the Portland XPress and Buckeye XPress projects to move additional gas across our pipeline network

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Canadian Mainline: On September 21, 2017, the NEB approved the long-term fixed price (LTFP) service, as filed, with an effective date of November 1, 2017. This new service allows us to transport 1.5 PJ/d (1.4 Bcf/d) of natural gas at a simplified toll of $0.77/GJ for a ten year term from the Alberta / Saskatchewan border to the Dawn Hub in southern Ontario and provides shippers with toll certainty and improved market access.

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NGTL System: In March 2017, we filed an application with the NEB for a variance to the existing approvals for the North Montney project on the NGTL System to remove the condition that the project could only proceed once a positive final investment decision is made for the Pacific Northwest LNG project (PNW LNG). North Montney is now under-pinned by restructured, 20-year commercial contracts with shippers and is not dependent on the LNG project proceeding. On September 7, 2017, the NEB provided notice that a public hearing process would be used to consider our variance application. The NEB also stated it would consider the continued appropriateness and applicability of the tolling decisions and associated conditions of the original approval. On October 26, 2017, the NEB issued the Hearing Order indicating the oral portion of the hearing will begin the week of January 22, 2018 with a decision to follow within 12 weeks after the hearing conclusion.

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Prince Rupert Gas Transmission: In July 2017, we were notified that PNW LNG would not be proceeding with their proposed LNG project and that Progress Energy (Progress) would be terminating their agreement with us for development of the PRGT project, effective August 10, 2017. In accordance with the terms of the agreement, all project costs incurred to advance the project, including carrying charges, are fully recoverable upon termination. As a result, we received a payment of $0.6 billion from Progress in October 2017.

•	Rayne XPress: Rayne Xpress was placed in service November 2, 2017. This Columbia Gulf project will transport approximately 1.1 PJ/d (1.0 Bcf/d) of supply from an interconnect with the Leach XPress pipeline project, and another interconnect, to markets along the system and to the Gulf Coast.

•	Midstream: The Gibraltar Midstream project, a 1,000 TJ/d (934 MMcf/d) dry gas header pipeline in southwest Pennsylvania, was placed in service November 1, 2017.

•	Leach XPress: The Leach XPress project is expected to have a US$100 million increase in its capital project cost due to delays caused by weather on the project's construction schedule and the resulting increase in contractor costs. Leach XPress is expected to be placed in service in early January 2018.

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FERC Update: The FERC regained a quorum of three commissioners in August 2017 and two additional commissioners were approved by the U.S. Senate on November 2, 2017. The FERC has stated that it intends to expeditiously address the resulting backlog of pending applications. We expect the FERC certificates for the WB XPress, Mountaineer XPress and Gulf XPress projects to be received in fourth quarter 2017.

•	Mountaineer XPress: The Mountaineer XPress project is expected to have a US$600 million increase in its capital project cost due to increased construction cost estimates. As a result of a cost sharing mechanism, overall project returns are not anticipated to be materially affected. Mountaineer XPress is expected to be placed in service in fourth quarter 2018.

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Buckeye Xpress: The Buckeye XPress project (BXP) represents an up-sizing of an existing pipeline replacement project under our Columbia Gas modernization program. The US$0.2 billion cost to up-size the replacement pipe and install compressor upgrades will enable us to offer 290 TJ/d (275 MMcf/d) of incremental pipeline capacity to accommodate growing Appalachian production. We expect BXP to be placed in service in late 2020.

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Portland XPress Project: PNGTS has executed Precedent Agreements with several local distribution companies (LDCs) in New England and Atlantic Canada to re-contract certain system capacity set to expire in 2019, as well as expand the PNGTS system to bring its certificated capacity up to 280 TJ/d (265 MMcf/d). The approximately US$80 million Portland XPress Project (PXP) will proceed concurrently with upstream capacity expansions. The in-service dates of PXP are being phased-in over a three year period beginning November 1, 2018.

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Great Lakes impact from Canadian Mainline's LTFP: In conjunction with the Canadian Mainline's LTFP service, Great Lakes entered into a new 10-year gas transportation contract with the Canadian Mainline. This contract received NEB approval in September 2017 and became effective on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.

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Great Lakes Rate Case: On October 30, 2017, Great Lakes filed a rate settlement with the FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018. The 2017 Great Lakes Settlement, if approved by the FERC, will decrease Great Lakes’ maximum transportation rates by 27 per cent beginning October 1, 2017. Great Lakes expects that the impact from other changes, including the recent long-term transportation contract with the Canadian Mainline as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.

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Northern Border: Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with the FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement. Northern Border anticipates that the FERC will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term. At this time, we do not believe that the final outcome of the settlement will have a material impact on our consolidated results. We have a 13 per cent indirect ownership interest in Northern Border through TC PipeLines, LP.

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Energy East and Related Projects: On September 7, 2017, we requested the NEB suspend the review of the Energy East and Eastern Mainline project applications for 30 days to provide time for us to conduct a careful review of the NEB's changes, announced on August 23, 2017, regarding the list of issues and environmental assessment factors related to the projects and how these changes impact the projects' costs, schedules and viability.

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Keystone XL: Given the passage of time since the Keystone XL Presidential Permit application was previously denied in November 2015, we are updating the shipping contracts and anticipate the core contract shipper group will be modified with the introduction of new shippers and reductions in volume commitments by other shippers. We anticipate commercial support for the project to be substantially similar to that which existed when we first applied for a Keystone XL pipeline permit.

•	Grand Rapids: In late August 2017, the Grand Rapids pipeline, jointly owned by TransCanada and PetroChina Canada Ltd., was placed in service. The 460 km (287 mile) pipeline plays a key role in connecting producing areas northwest of Fort McMurray, Alberta, to terminals in the Edmonton / Heartland region.

•	Northern Courier: Northern Courier, a 90 km (56 mile) pipeline which transports bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal located north of Fort McMurray, Alberta, achieved commercial in-service on November 1, 2017.

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Sale of Ontario Solar Assets: On October 24, 2017, we entered into an agreement to sell our Ontario Solar portfolio, comprised of eight facilities with a total generating capacity of 76 MWs, to Axium Infinity Solar LP for approximately $540 million. The sale is expected to close by the end of 2017, subject to certain regulatory and other approvals, and will include customary closing adjustments. The transaction is expected to result in an estimated gain of $130 million before tax ($100 million after tax) to be recognized upon closing.

•	Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.625 per share for the quarter ending December 31, 2017 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.50 per common share on an annualized basis.

•	Medium Term Note Issuance: In September 2017, TransCanada issued $1 billion of Medium Term Notes comprised of $300 million of 10.5-year notes at an interest rate of 3.39 per cent and $700 million of 30-year notes at an interest rate of 4.33 per cent.

•	Dividend Reinvestment Plan (DRP): To date in 2017, the participation rate in our DRP has been approximately 36 per cent of common share dividends, resulting in $594 million of common equity issued under the program year-to-date.

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

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