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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.

2	Includes capital expenditures, capital projects in development and contributions to equity investments.

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•	planned changes in our business

•	our financial and operational performance, including the performance of our subsidiaries

•	expectations or projections about strategies and goals for growth and expansion

•	expected cash flows and future financing options available to us

•	expected dividend growth

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

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

•	expected regulatory processes and outcomes, including the expected impact of the 2018 FERC Actions

•	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 impact of U.S. Tax Reform

•	expected industry, market and economic conditions.

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•	continued wind-down of our U.S. Northeast power marketing business

•	inflation rates and commodity prices

•	nature and scope of hedging activities

•	regulatory decisions and outcomes, including those related to the 2018 FERC Actions

•	interest, tax and foreign exchange rates, including the impact of U.S. Tax Reform

•	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 from our energy business

•	regulatory decisions and outcomes, including those related to the 2018 FERC Actions

•	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, including the impact of U.S. Tax Reform

•	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 or assets held for sale

•	legal, contractual and bankruptcy settlements

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

•	restructuring costs

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

•	acquisition and integration costs.

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after-tax income of $8 million and $3 million for the three and nine months ended September 30, 2018 related to our U.S. Northeast power marketing contracts primarily due to income recognized on the sale of our retail contracts in first quarter and earnings from the remaining contracts. These amounts have been excluded from Energy's comparable earnings effective January 1, 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020.

•

a $12 million after-tax loss and a $243 million after-tax gain, for the three and nine months ended September 30, 2017, related to the monetization of our U.S. Northeast power generation assets. This 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

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•	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 was expensed in 2017 pending further advancement of the project. In 2018, Keystone XL expenditures are being capitalized

•	a $7 million income tax recovery in first quarter related to the realized loss on a third-party sale of Keystone XL project assets.

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•	higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and the amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform

•	higher contribution from Liquids Pipelines primarily due to earnings from intra-Alberta pipelines placed in service in the second half of 2017, increased earnings from liquids marketing activities, and higher volumes on the Keystone Pipeline System

•	lower income tax expense primarily due to lower income tax rates as a result of U.S. Tax Reform

•	higher revenues from our Mexico operations as a result of changes in timing of revenue recognition

•	higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities, and lower capitalized interest.

•	higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform

•	higher contribution from Liquids Pipelines primarily due to earnings from intra-Alberta pipelines placed in service in the second half of 2017, increased earnings from liquids marketing activities, and higher volumes on the Keystone Pipeline System

•	lower income tax expense primarily due to lower income tax rates as a result of U.S. Tax Reform

•	higher revenues from our Mexico operations as a result of changes in timing of revenue recognition

•	increased Western Power results due to higher realized margins on higher generation volumes

•	lower earnings from U.S. Power mainly due to the sales of the U.S. Northeast power generation assets in second quarter 2017 combined with the U.S. Northeast Power marketing results being excluded from comparable earnings in 2018

•	higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities, and lower capitalized interest, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017

•	lower earnings from Bruce Power primarily due to lower volumes resulting from increased outage days and lower earnings from contracting activities

•	lower Eastern Power results mainly due to the sale of our Ontario solar assets in December 2017.

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make a limited Natural Gas Act (NGA) Section 4 filing to reduce its rates by the reduction in its cost-of-service shown in its FERC Form 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s FERC Form 501-G shows the pipeline’s estimated ROE as being 12 per cent or less. Under the Final Rule, and notwithstanding the Revised Policy Statement discussed above, a pipeline organized as an MLP is not required to eliminate its income tax allowance, but instead can reduce its rates to reflect the reduction in the maximum corporate tax rate. Alternatively, the MLP pipeline can eliminate its tax allowance along with its ADIT used for rate-making purposes. In situations where the ADIT balance is a liability, this elimination would have the effect of increasing the pipeline’s rate base for rate-making purposes

•	commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. If the pipeline commits to file either by December 31, 2018, FERC will not initiate a Section 5 investigation of its rates prior to that date

•	file a statement explaining its rationale for why it does not believe the pipeline's rates must change; or

•	take no other action. FERC will consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate filing or committed to file a general Section 4 rate case.

•	Millennium Pipeline filed its Form 501-G October 11, 2018

•	ANR, ANR Storage, Columbia Gas, Columbia Gulf and Crossroads are scheduled to file their respective Form 501-Gs on December 6, 2018 unless new uncontested rate settlements are filed

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•	Hardy Storage and Blue Lake Storage have reached rate settlements in principle. We expect to file the settlement agreements with FERC in fourth quarter 2018. As outlined in 2018 FERC Actions, pipeline and storage assets that file an uncontested settlement will be relieved of their obligations to file a Form 501-G.

•	PNGTS filed its Form 501-G with FERC along with an explanation why no rate change is needed

•	North Baja elected to make a limited NGA Section 4 filing and reduce its recourse rates by approximately 11 per cent, which is the percentage reduction in the cost of service per the FERC Form 501-G

•	Iroquois requested a waiver of its requirement to file a Form 501-G from FERC based on its existing moratorium precluding rate changes prior to September 2020

•	Bison is scheduled to file its response by November 8, 2018 and Northern Border, Great Lakes and Tuscarora are scheduled to file by December 6, 2018.

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1	Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets and assets held through TC PipeLines, LP.

2	Represents 100 per cent of required capital prior to potential joint venture partners or project financing.

3	Carrying value excludes the reduction for the fourth quarter 2018 elections made to date by certain LNG Canada participants to reimburse approximately $0.4 billion of pre-development costs pursuant to project agreements. Refer to the Recent Developments section for additional details.

4	The CFE has recognized force majeure events for these pipelines and approved the payment of fixed capacity charges in accordance with their respective TSAs. These payments will begin to be recognized as revenue when the pipelines are placed in service.

5	Reflects our proportionate share of the Unit 6 Major Component Replacement program costs, expected to be in service in 2023, and amounts to be invested under the Asset Management program through 2023.

6	Includes non-recoverable maintenance capital expenditures from all segments and is primarily comprised of our proportionate share of maintenance capital expenditures for Bruce Power and other Energy amounts.

7	Reflects U.S./Canada foreign exchange rate of 1.29 at September 30, 2018.

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1	Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets.

2	Regulatory approvals have been obtained.

3	Additional commercial support is being pursued.

4	Carrying value reflects amount remaining after impairment charge recorded in 2015, along with additional amounts capitalized from January 1, 2018.

5	Reflects our proportionate share of Major Component Replacement program costs for Units 3, 4, 5, 7 and 8, and the remaining Asset Management program costs beyond 2023.

6	Reflects U.S./Canada foreign exchange rate of 1.29 at September 30, 2018.

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•	improved earnings from additional contract sales in U.S. Natural Gas Pipelines

•	higher contracted and uncontracted volumes on the Keystone Pipeline System as well as higher contributions from liquids marketing activities

•	increased revenues in Mexico Natural Gas Pipelines

•	increased benefit from and better visibility into the impacts of U.S. Tax Reform

•	the sale of our 62 per cent share of the Cartier Wind power facilities.

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1	Includes results from Foothills, Ventures LP, Great Lakes Canada, and our share of equity income from our investment in TQM as well as general and administrative and business development costs related to our Canadian Natural Gas Pipelines.

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1	Results reflect our earnings from TC PipeLines, LP’s ownership interests in GTN, Great Lakes, Iroquois, Northern Border, Bison, PNGTS, North Baja and Tuscarora, as well as general and administrative costs related to TC PipeLines, LP.

2

TC PipeLines, LP periodically conducts ATM equity issuances which decrease our ownership in TC PipeLines, LP. For the three months ended September 30, 2018, our ownership interest in TC PipeLines, LP was 25.5 per cent compared to 26.0 per cent for the same period in 2017. Our ownership interest for the nine months ended September 30, 2018, was 25.5 per cent compared to a range of 26.5 to 26.0 per cent for the same period in 2017.

3	TC PipeLines, LP acquired 49.34 per cent of our 50 per cent interest in Iroquois and our remaining 11.81 per cent interest in PNGTS on June 1, 2017.

4	Results reflect our 53.55 per cent direct interest in Great Lakes. The remaining 46.45 per cent is held by TC PipeLines, LP.

5	Results reflect earnings from our direct ownership interests in Crossroads, as well as Iroquois and PNGTS until June 1, 2017, and our effective ownership in Millennium and Hardy Storage, as well as general and administrative and business development costs related to our U.S. natural gas pipelines.

6	Results reflect earnings attributable to portions of TC PipeLines, LP, PNGTS (until June 1, 2017) and CPPL (until February 17, 2017) that we do not own.

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•	increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and improved commodity prices and throughput volumes in Midstream

•	increased earnings due to the amortization of the net regulatory liabilities recognized in 2017, partially offset by a reduction in certain rates on Columbia Gas, as a result of U.S. Tax Reform

•	a US$10 million refund from GTN to its recourse rate customers as per the 2018 GTN Settlement. Refer to the 2018 FERC Actions section for additional details.

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1	Represents equity income from our 60 per cent interest.

•	higher revenues from operations as a result of changes in timing of revenue recognition

•	the impairment of our equity investment in TransGas in third quarter 2017.

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•	pre-tax charges related to the maintenance of Keystone XL assets which were expensed in 2017 pending further advancement of the project. In 2018, Keystone XL expenditures are being capitalized

•	unrealized losses from changes in the fair value of derivatives related to our liquids marketing business.

•	contributions from intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017

•	a higher contribution from liquids marketing activities

•	higher contracted and uncontracted volumes on the Keystone Pipeline System

•	foreign exchange impact on the Canadian dollar equivalent earnings from our U.S. operations.

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

2	In second quarter 2017, we completed the sales of our U.S. Northeast power generation assets.

•

a gain of $12 million and $5 million for the three and nine months ended September 30, 2018 related to our U.S. Northeast power marketing contracts. The year-to-date amount includes a gain in first quarter 2018 on the sale of our retail contracts. These amounts have been excluded from Energy's comparable earnings effective January 1, 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020

•	a net loss of $12 million and a net gain of $469 million before tax for the three and nine months ended September 30, 2017 related to the monetization of our U.S. Northeast power generation assets

•	unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks, as noted in the table below.

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•	lower earnings from U.S. Power mainly due to the sales of the U.S. Northeast power generation assets in second quarter 2017

•	decreased Bruce Power year-to-date earnings primarily due to lower volumes resulting from higher outage days and lower results from contracting activities. Additional financial and operating information on Bruce Power is provided below

•	lower Eastern Power results due to the sale of our Ontario solar assets in December 2017

•	increased Western Power results due to higher realized margins on higher generation volumes

•	decreased Natural Gas Storage results primarily due to lower realized natural gas storage price spreads.

1	Represents our 48.3 per cent (2017 – 48.4 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 in our Corporate segment.

•	foreign exchange losses and gains on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the affiliate's project financing. There are corresponding foreign exchange gains and losses included in Interest income and other on the inter-affiliate loan receivable which fully offset these amounts

•	in 2017, integration-related costs associated with the acquisition of Columbia.

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

•	lower capitalized interest primarily due to the completion of Grand Rapids and Northern Courier in the second half of 2017, partially offset by ongoing construction at Napanee and the recommencement of capitalization of Keystone XL costs in 2018

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•	final repayment of the Columbia acquisition bridge facilities in June 2017 resulting in lower interest and debt amortization expense

•	foreign exchange impact on translation of U.S. dollar-denominated interest.

•

higher interest income and a $60 million foreign exchange gain compared to a $7 million loss in 2017 related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange loss are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. The offsetting currency-related gain and loss amounts are excluded from comparable earnings

•	higher unrealized gains on risk management activities in 2018 compared to 2017. These amounts have been excluded from comparable earnings

•	realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

•	income of $10 million recognized in 2017 on termination of the PRGT project, related to the recovery of carrying costs.

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higher interest income and a $52 million foreign exchange gain related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange loss are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. The offsetting currency-related gain and loss amounts are excluded from comparable earnings

•	unrealized losses on risk management activities in 2018 compared to unrealized gains in 2017. These amounts have been excluded from comparable earnings

•	income of $20 million related to reimbursement of Coastal GasLink (CGL) project costs in 2017

•	income of $10 million recognized in 2017, on termination of the PRGT project, related to the recovery of carrying costs.

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•	our ability to generate cash flow from operations

•	our access to capital markets

•	approximately $9.5 billion of unutilized, unsecured credit facilities.

1	See the Non-GAAP measures section of 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.

2	Includes non-recoverable maintenance capital expenditures from all segments including cash contributions to fund our proportionate share of maintenance capital expenditures for our equity investments which are primarily related to contributions to Bruce Power.

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1	Includes draws and repayments on unsecured loan facility by TC PipeLines, LP.

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•	cash and cash equivalents

•	accounts receivable

•	available-for-sale assets

•	the fair value of derivative assets

•	loans receivable.

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1	Excludes interest expense on our inter-affiliate loan with Sur de Texas which is offset in Interest income and other.

2	Effective January 1, 2018, U.S. Power is no longer included in comparable EBIT.

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1	Fair values equal carrying values.

2	No amounts have been excluded from the assessment of hedge effectiveness.

3	In the three and nine months ended September 30, 2018, Net income includes net realized gains of nil and $1 million, respectively (2017 – $1 million and $3 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 on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively.

2	In the three and nine months ended September 30, 2018 and 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.

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1	Amounts presented are pre-tax. 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 expense on the Condensed consolidated statement of income.

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•	pattern of revenue recognition within a contract, based on whether the performance obligation is satisfied at a point in time versus over time

•	term of the contract

•	amount of variable consideration associated with a contract and timing of the associated revenue recognition.

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•	regulators' decisions

•	negotiated settlements with shippers

•	acquisitions and divestitures

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service.

•	regulatory decisions

•	developments outside of the normal course of operations

•	newly constructed assets being placed in service

•	demand for uncontracted transportation services

•	liquids marketing activities

•	certain fair value adjustments.

•	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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•	after-tax income of $8 million related to our U.S. Northeast power marketing contracts. These were excluded from Energy's comparable earnings effective January 1, 2018 as the wind-down of these contracts is not considered part of our underlying operations.

•	an after-tax loss of $11 million related to our U.S. Northeast power marketing contracts. These were excluded from Energy's comparable earnings effective January 1, 2018 as the wind-down of these contracts is not considered part of our underlying operations.

•	after-tax income of $6 million related to our U.S. Northeast power marketing contracts, primarily due to income recognized on the sale of our retail contracts. These were excluded from Energy's comparable earnings effective January 1, 2018 as the wind-down of these contracts is not considered part of our underlying operations.

•	an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform

•	a $136 million after-tax gain related to the sale of our Ontario solar assets

•	a $64 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets, which included an incremental after-tax loss of $7 million recorded on the sale of the thermal and wind package, $23 million of after-tax third-party insurance proceeds related to a 2017 Ravenswood outage and income tax adjustments

•	a $954 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications

•	a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets which were expensed pending further advancement of the project.

•	an incremental net loss of $12 million related to the monetization of our U.S. Northeast power generation assets, which included an incremental loss of $7 million after tax on the sale of the thermal and wind package and $14 million of after-tax disposition costs and income tax adjustments

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

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

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•	a $265 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets, which included a $441 million after-tax gain on the sale of TC Hydro and an additional 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 were 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 generation business

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

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

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

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

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

•	an after-tax charge of $18 million related to Keystone XL costs for the maintenance and liquidation of project assets which were 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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•	pattern of revenue recognition within a contract, based on whether the performance obligation is satisfied at a point in time versus over time

•	term of the contract

•	amount of variable consideration associated with a contract and timing of the associated revenue recognition.

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1	Includes intersegment eliminations.

2

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

3	Income/(loss) from equity investments includes foreign exchange losses on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange gains on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture.

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1	Includes intersegment eliminations.

2

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

3	Income/(loss) from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture.

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1	Includes intersegment eliminations.

2

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

3	Income/(loss) from equity investments includes foreign exchange losses on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange gains on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture.

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1	Includes intersegment eliminations.

2

The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.

3	Income/(loss) from equity investments includes foreign exchange losses on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange gains on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of debt financing for this joint venture.

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1

Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 12, Risk management and financial instruments, for further information on income from financial instruments.

2	Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 7, Income taxes, for further information.

1

Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements within each operating segment. Income from lease arrangements includes certain long term PPAs, as well as certain liquids pipelines capacity and transportation arrangements. These arrangements are not in the scope of the new guidance, therefore, revenues related to these contracts are excluded from revenues from contracts with customers. Refer to Note 12, Risk management and financial instruments, for further information on income from financial instruments.

2	Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 7, Income taxes, for further information.

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1	Adjustment relates to contract assets previously included in Accounts receivable.

2	Adjustment relates to contract liabilities previously included in Accounts receivable.

1	Recorded as part of Other current assets on the Condensed consolidated balance sheet.

2	Recorded as part of Intangibles and other assets on the Condensed consolidated balance sheet.

3	Comprised of deferred revenue recorded in Accounts payable and other on the Condensed consolidated balance sheet. During the nine months ended September 30, 2018, $17 million of revenue was recognized that was included in the contract liability at the beginning of the period.

4	Comprised of deferred revenue recorded in Other long-term liabilities on the Condensed consolidated balance sheet.

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1)	The original expected duration of the contract is one year or less.

2)	The Company recognizes revenue from the contract that is equal to the amount invoiced, where the amount invoiced represents the value to the customer of the service performed to date. This is referred to as the "right to invoice" practical expedient.

3)

The variable revenue generated from the contract is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation in a series. A single performance obligation in a series occurs when the promises under a contract are a series of distinct services that are substantially the same and have the same pattern of transfer to the customer over time.

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1	Included in Accounts payable and other on the Condensed consolidated balance sheet.

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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 are net of non-controlling interest losses of $34 million and gains of $1 million, respectively.

3	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $1 million and $1 million, respectively.

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 are net of non-controlling interest gains of $61 million and $8 million, respectively.

3

Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $16 million ($11 million after tax) at September 30, 2018. 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.

4	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $4 million and $2 million, respectively.

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

2	These AOCI components are included in the computation of net benefit cost. Refer to Note 11, Employee post-retirement benefits, for further information.

3	Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest gains of $1 million and $1 million, respectively, for the three months ended September 30, 2018 (2017 – nil and nil) and $4 million and $2 million, respectively, for the nine months ended September 30, 2018 (2017 – nil and nil).

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1	Service cost and other components of net benefit cost are included in Plant operating costs and other in the Condensed consolidated statement of income.

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1	Fair value equals carrying value.

2	No amounts have been excluded from the assessment of hedge effectiveness.

3	In the three and nine months ended September 30, 2018, Net income includes net realized gains of nil and $1 million, respectively (2017 – $1 million and $3 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$700 million (December 31, 2017 – US$1.1 billion) that is attributed to hedged risk and recorded at fair value.

2

Net income for the three and nine months ended September 30, 2018 includes unrealized losses of $1 million and unrealized gains of $3 million, respectively, (2017 – gains of $1 million and $2 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$700 million of long-term debt at September 30, 2018 (December 31, 2017 – US$1.1 billion). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

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

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

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	Gains and losses on other restricted investments are included in Interest income and other.

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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.

1	At September 30, 2018 and December 31, 2017, adjustments for discontinued hedging relationships included in these balances were nil.

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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 on a net basis in Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in Interest expense and Interest income and other, respectively.

2	In the three and nine months ended September 30, 2018 and 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.

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

1	Refer to Note 10, Other comprehensive (loss)/income and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.

2	There are no amounts recognized in earnings that were excluded from effectiveness testing.

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1	Refer to Note 10, Other comprehensive (loss)/income and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests.

2	There are no amounts recognized in earnings that were excluded from effectiveness testing.

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, 2018.

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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, 2017.

1	For the three and nine months ended September 30, 2018, Revenues include unrealized losses of $16 million and $2 million, respectively, attributed to derivatives in the Level III category that were still held at September 30, 2018 (2017 – unrealized losses of $10 million and $14 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.

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•	Third quarter 2018 financial results

◦	Comparable distributable cash flow of $1.4 billion or $1.56 per common share reflecting only non-recoverable maintenance capital expenditures

•	Declared a quarterly dividend of $0.69 per common share for the quarter ending December 31, 2018

•	Announced that we will proceed with construction of the $6.2 billion Coastal GasLink pipeline project

•	Announced $1.5 billion NGTL 2022 Expansion Program

•	Bruce Power submitted a final estimate for the Unit 6 Major Component Replacement (MCR) program to the Independent Electricity System Operator (IESO) in September 2018; we expect to invest approximately $2.2 billion in this and the ongoing Asset Management program through 2023

•	Issued $1.0 billion of 10- and 30-year fixed-rate medium-term notes in July 2018

•	Raised US$1.4 billion of 10- and 30-year fixed-rate senior notes in October 2018

•	Completed the sale of our interests in Cartier Wind for approximately $630 million in October 2018

•	Expect to be reimbursed for $399 million of Coastal GasLink pre-development costs in fourth quarter 2018.

•	higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes and the amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform

•	higher contribution from Liquids Pipelines primarily due to earnings from intra-Alberta pipelines placed in service in the second half of 2017, increased earnings from liquids marketing activities, and higher volumes on the Keystone Pipeline System

•	lower income tax expense primarily due to lower income tax rates as a result of U.S. Tax Reform

•	higher revenues from our Mexico operations as a result of changes in timing of revenue recognition

•	higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities, and lower capitalized interest.

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•

Coastal GasLink Pipeline (CGL) Project: On October 2, 2018, we announced that we will proceed with construction of the CGL pipeline project following the LNG Canada joint venture participants' announcement that they have reached a positive Final Investment Decision (FID) to build the LNG Canada natural gas liquefaction facility in Kitimat, BC. CGL will provide the natural gas supply to the LNG Canada facility and is underpinned by 25-year transportation services agreements (with additional renewal provisions) with the LNG Canada participants. CGL is a 670 km (420 miles) pipeline with an initial capacity of approximately 2.2 PJ/d (2.1 Bcf/d) with potential expansion capacity up to 5.4 PJ/d (5.0 Bcf/d). All necessary regulatory permits have been received to allow us to proceed with construction activities which are expected to begin in January 2019, with a planned in-service date in 2023. CGL has signed project and community agreements with all 20 elected Indigenous bands along the pipeline route, confirming strong support from Indigenous communities across the province of B.C.

•

NGTL System: On October 31, 2018, we announced the NGTL 2022 Expansion Program to meet capacity requirements for incremental firm receipt and intra-basin delivery services to commence in November 2021 and April 2022. This $1.5 billion expansion of the NGTL System consists of approximately 197 km (122 miles) of new pipeline, three compressor units, meter stations and associated facilities. Applications for approvals to construct and operate the facilities are expected to be filed with the NEB in second quarter 2019 and, pending receipt of regulatory approvals, construction would start as early as third quarter 2020.

•	Canadian Mainline: On October 9, 2018, we concluded the written hearing process for the Canadian Mainline 2018-2020 toll review with the filing of our reply evidence to the NEB. We have requested a decision by December 31, 2018.

•	WB XPress: The Western Build of the WB XPress (WBX) project was placed into service on October 5, 2018. The Eastern Build of WBX remains to be completed, as planned, in fourth quarter 2018.

•

2018 FERC Actions: On March 15, 2018, the Federal Energy Regulatory Commission (FERC) issued (1) a Revised Policy Statement to address the treatment of income taxes for rate-making purposes for master limited partnerships; (2) a Notice of Proposed Rulemaking (NOPR) proposing natural gas pipeline and storage entities file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the Revised Policy Statement on each entity's return on equity assuming a single-issue adjustment to an

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•	Rate Settlements: In October 2018, Gas Transmission Northwest LLC (GTN) filed with FERC an uncontested settlement with its customers. Please refer to our MD&A in the 2018 FERC Actions section for additional detail.

•	Sur de Texas: Offshore construction was completed in May 2018 and the project continues to progress toward an anticipated in-service date at the end of 2018. An amending agreement has been signed with the Comisión Federal de Electricidad (CFE) that recognizes force majeure events and the commencement of payments of fixed capacity charges beginning October 31, 2018.

•	Tula and Villa de Reyes: The CFE has approved the recognition of force majeure events for both of these pipelines, including the continuation of the payment of fixed capacity charges to us that began in first quarter 2018. Construction of the Villa de Reyes project is ongoing and it is anticipated to be in service by the second half of 2019.

•

Keystone XL: In December 2017, an appeal to Nebraska's Court of Appeals was filed by intervenors after the Nebraska Public Service Commission (PSC) issued an approval of an alternative route for the Keystone XL project in November 2017. In March 2018, the Nebraska Supreme Court, on its own motion, agreed to bypass the Court of Appeals and directly hear the appeal case against the PSC’s alternative route. Legal briefs on the appeal were submitted in May 2018. Oral argument before the Nebraska Supreme Court has been set for November 1, 2018. We expect the Nebraska Supreme Court, as the final arbiter, could reach a decision by first quarter 2019.

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•	Cartier Wind: On October 24, 2018, we completed the sale of our interests in the Cartier Wind power facilities in Québec to Innergex Renewable Energy Inc. for gross proceeds of approximately $630 million before closing adjustments resulting in an estimated gain of $170 million ($135 million after tax) to be recorded in fourth quarter 2018.

•

Bruce Power - Life Extension: On September 28, 2018, Bruce Power submitted its final cost and schedule duration estimate (basis of estimate) for the Unit 6 MCR program to the IESO. The IESO has up to three months to review and verify the basis of estimate. As the cost and schedule duration are both less than the thresholds defined in the program's life extension and refurbishment agreement, no further approvals from the IESO or government are required to proceed with the Unit 6 MCR outage in early 2020. The Unit 6 MCR outage is expected to be completed in late 2023.

•

Napanee: Construction continues on our 900 MW natural gas-fired power plant at Ontario Power Generation's (OPG) Lennox site in eastern Ontario in the town of Greater Napanee. We expect our total investment in the Napanee facility will be approximately $1.6 billion and commercial operations are expected to begin in first quarter 2019. Costs have increased due to delays in the construction schedule. Once in service, production from the facility is fully contracted with the IESO for a 20-year period.

•	Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.69 per share for the quarter ending December 31, 2018 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $2.76 per common share on an annualized basis.

•	Issuance of Long-term Debt: In October 2018, TCPL issued US$1.0 billion of Senior Unsecured Notes due in March 2049 bearing interest at a fixed rate of 5.10 per cent and US$400 million of Senior Unsecured Notes due in May 2028 bearing interest at a fixed rate of 4.25 per cent.

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•	Dividend Reinvestment Plan: In third quarter 2018, the DRP participation rate amongst common shareholders was approximately 34 per cent, resulting in $213 million reinvested in common equity under the program. Year-to-date in 2018, the participation rate amongst common shareholders has been approximately 35 per cent, resulting in $655 million of dividends reinvested.

•

ATM Equity Program: In third quarter 2018, 6.1 million common shares were issued under our Corporate ATM program at an average price of $57.75 per common share for proceeds of $351 million, net of related commissions and fees of approximately $3 million. In the nine months ended September 30, 2018, 20.0 million common shares have been issued under our Corporate ATM program at an average price of $56.13 per common share for proceeds of $1.1 billion, net of approximately $10 million of related commissions and fees.

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