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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, including the economic benefit of asset drop downs to TC PipeLines, LP

•	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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an after-tax loss of $5 million year-to-date related to our U.S. Northeast power marketing contracts which included an after-tax loss of $11 million in second quarter and an after-tax gain of $6 million in first quarter primarily due to income recognized 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 will continue to run-off through to mid-2020.

•	a $255 million after-tax net 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 in second quarter, an incremental loss of $176 million after tax recorded in second quarter on the sale of the thermal and wind package and $10 million year-to-date of after-tax disposition costs

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•	an after-tax charge of $15 million in second quarter and $39 million year-to-date for integration-related costs associated with the acquisition of Columbia

•	an after-tax charge of $4 million in second quarter and $11 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, higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities

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

•	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 U.S. Power mainly due to the sale of the U.S. Northeast power generation assets in second quarter 2017

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

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

•	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, higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities

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

•	higher interest income and other primarily resulting from realized gains in 2018 compared to realized losses in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

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

•	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

•	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 Section 4 filing to reduce its rates by the reduction in its cost-of-service shown in its FERC Form No. 501-G. For any pipeline electing this option, FERC guarantees a three-year moratorium on Natural Gas Act 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 accumulated deferred income tax balance used for rate-making purposes. In situations where the accumulated deferred income tax 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.

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

2	Reflects increased costs required to bring facility into service in fourth quarter 2018.

3	Reflects our proportionate share of the remaining capital costs that Bruce Power expects to incur on its life extension investment programs in advance of the Unit 6 major refurbishment outage which is expected to begin in 2020.

4	Includes non-recoverable maintenance capital expenditures from all segments and is primarily comprised of Bruce Power cash calls and other Energy amounts.

5	Reflects U.S./Canada foreign exchange rate of 1.31 at June 30, 2018.

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

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 U.S./Canada foreign exchange rate of 1.31 at June 30, 2018.

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•	improved earnings from additional contract sales and lower expenses 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.

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1	Includes results from Foothills, Ventures LP, Great Lakes Canada, our share of equity income from our investment in TQM, 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 June 30, 2018, our ownership interest in TC PipeLines, LP was 25.5 per cent compared to 26.3 per cent for the same period in 2017. Our ownership interest for the six months ended June 30, 2018 ranged from 25.7 to 25.5 per cent compared to a range of 26.5 to 26.3 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 in Midstream

•	increased earnings due to the amortization of the net regulatory liabilities recognized in 2017 as a result of U.S. Tax Reform.

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1	Represents equity income from our 60 per cent interest.

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1	Includes primarily liquids marketing and business development activities.

•	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 gains in 2018 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

•	higher contracted and spot volumes on the Keystone Pipeline System

•	a higher contribution from liquids marketing activities

•	lower business development costs as a result of capitalizing Keystone XL expenditures

•	a weaker U.S. dollar which had a negative 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 loss of $7 million year-to-date related to our U.S. Northeast power marketing contracts which included a loss of $15 million in second quarter and a gain of $8 million in first quarter primarily due to income recognized 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 will continue to run-off through to mid-2020

•	a net gain of $492 million and $481 million before tax for the three and six months ended June 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 sale of the U.S. Northeast power generation assets in second quarter 2017

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

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

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

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

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 gains and losses 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 losses and gains included in Interest income and other on the inter-affiliate loan receivable which fully offset these amounts

•	in 2017, pre-tax integration and acquisition 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 construction of Grand Rapids and Northern Courier in 2017

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

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

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interest income partially offset by the foreign exchange loss related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange gain are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. The offsetting currency-related 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

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

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

•	income of $18 million related to reimbursement of Coastal GasLink project costs recorded in 2017.

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•	our ability to generate cash flow from operations

•	our access to capital markets

•	approximately $9.3 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 maintenance capital expenditures for our equity investments. Expenditures are primarily related to contributions to Bruce Power to fund our proportionate share of their maintenance capital expenditures.

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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 six months ended June 30, 2018, Net income includes net realized gains of nil and $1 million, respectively (2017 - $1 million and $2 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 six months ended June 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.

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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•	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.

•	an after-tax gain 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 business, 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 business 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.

•	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 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.

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•	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.

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

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

•	$28 million of income tax recoveries related to the realized loss on a third-party sale of Keystone XL plant and equipment. A provision for the expected loss on these assets was 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 were 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.

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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 from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. 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 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 from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. 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 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 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 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	Comprised of deferred revenue recorded in Accounts payable and other on the Condensed consolidated balance sheet. During the six months ended June 30, 2018, $17 million of revenue was recognized that was included in the contract liability at the beginning of the period.

3	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.

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 income/(loss) before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest gains of $38 million and nil, respectively.

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

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

2	Other comprehensive income/(loss) before reclassifications on currency translation adjustments and cash flow hedges is net of non-controlling interest gains of $95 million and $7 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 $21 million ($15 million, net of tax) at June 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 $3 million and $1 million, respectively.

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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 11, Employee post-retirement benefits, for further information.

3	Amounts reclassified from AOCI on cash flow hedges and equity investments is net of non-controlling interest gains of $2 million and nil, respectively for the three months ended June 30, 2018 (2017 - nil and nil) and $3 million and $1 million, respectively for the six months ended June 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 six months ended June 30, 2018, Net income includes net realized gains of nil and $1 million, respectively (2017 – $1 million and $2 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$1.3 billion (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 six months ended June 30, 2018 includes unrealized losses of $1 million and unrealized gains of $4 million, respectively, (2017 – losses of $1 million and gains of $1 million, respectively) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$1.3 billion of long-term debt at June 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 June 30, 2018 and December 31, 2017, adjustments for discontinued hedging relationships included in the balance 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 six months ended June 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 income/(loss) 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 income/(loss) 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 six months ended June 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 six months ended June 30, 2018, Revenues include unrealized gains of $50 million and $44 million, respectively, attributed to derivatives in the Level III category that were still held at June 30, 2018 (2017 – unrealized losses of $1 million and unrealized gains of $1 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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•	Second quarter 2018 financial results

◦	Comparable distributable cash flow of $1.3 billion or $1.46 per common share reflecting only non-recoverable maintenance capital expenditures

•	Declared a quarterly dividend of $0.69 per common share for the quarter ending September 30, 2018

•	Received National Energy Board (NEB) approval for the NGTL System's 2018-2019 Settlement with customers

•	Received approval from the Federal government for the $1.6 billion North Montney project

•	Raised US$2.5 billion in 10, 20 and 30-year fixed-rate senior debt in May 2018

•	Issued $1 billion of 10 and 30-year fixed-rate medium-term notes in July 2018

•	Replenished the capacity available under the Corporate ATM program by $1 billion

•	Announced the sale of our interests in Cartier Wind for approximately $630 million in August 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, higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities

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

•	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 U.S. Power mainly due to the sale of the U.S. Northeast power generation assets in second quarter 2017

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

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

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NGTL System: On June 19, 2018, the NEB approved the 2018-2019 Settlement, as filed, for final 2018 tolls and revised interim 2018 tolls. The 2018-2019 Settlement fixes return on equity (ROE) at 10.1 per cent on 40 per cent deemed equity and increases the composite depreciation rate from 3.18 per cent to 3.45 per cent. OM&A costs are fixed at $225 million for 2018 and $230 million for 2019 with a 50/50 sharing mechanism for any variances between the fixed amounts and actual OM&A costs. All other costs are treated as flow-through expenses.

•

North Montney: On May 23, 2018, the NEB issued a report recommending the Federal government approve a variance to the existing North Montney project approvals to remove the condition requiring a positive Final Investment Decision (FID) for the Pacific Northwest LNG project prior to commencement of construction. The Federal government approved the recommendation on June 22, 2018 and on July 2, 2018 the NEB issued an amending order for the project.

•

Nixon Ridge: On June 7, 2018, a natural gas pipeline rupture on Columbia Gas occurred on Nixon Ridge in Marshall County, West Virginia. Emergency response procedures were enacted and the segment of impacted pipeline was isolated shortly after. There were no injuries and no material damage to surrounding structures. The pipeline was placed back in service on July 15, 2018. The preliminary investigation, as noted in the PHMSA Proposed Safety Order, suggests that the rupture was a result of land subsidence. The investigation remains ongoing and we are fully cooperating with PHMSA to determine the root cause of the incident. We do not expect this event to have a significant impact on our financial results.

•

Topolobampo: On June 29, 2018, the Topolobampo pipeline was placed in service. The 560 km (348 miles) pipeline provides capacity of 720 TJ/d (670 MMcf/d), receiving natural gas from upstream pipelines near El Encino, in the state of Chihuahua, and delivering it to points along the pipeline route including our Mazatlán pipeline at El Oro, in the state of Sinaloa. Under the force majeure terms of the TSA, we began collecting and recognizing revenue from the original TSA service commencement date of July 2016.

•	Sur de Texas: Offshore construction was completed in May 2018 and the project continues to progress toward an anticipated in-service date of late 2018.

•	Tula and Villa de Reyes: We continue to work toward finalizing amending agreements for both of these pipelines with the Comisión Federal de Electricidad (CFE) to formalize the schedule and payments resulting from their respective force majeure events. The CFE has commenced payments on both pipelines in accordance with the TSAs.

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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 hear the appeal case against the PSC’s alternative route itself. We expect the Nebraska Supreme Court, as the final arbiter, could reach a decision by late 2018 or first quarter 2019.

•

Cartier Wind: On August 1, 2018, we entered into an agreement to sell our interests in the Cartier Wind power facilities in Québec to Innergex Renewable Energy Inc. for gross proceeds of $630 million before closing adjustments. The sale is expected to be completed in fourth quarter 2018 subject to certain regulatory and other approvals and result in an estimated gain of $175 million ($130 million after tax) which will be recorded upon closing of the transaction.

•	Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.69 per share for the quarter ending September 30, 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 second quarter 2018, TCPL issued US$1 billion of Senior Unsecured Notes due in May 2028 bearing interest at a fixed rate of 4.25 per cent, US$500 million of Senior Unsecured Notes due in May 2038 bearing interest at a fixed rate of 4.75 per cent and US$1 billion of Senior Unsecured Notes due in May 2048 bearing interest at a fixed rate of 4.875 per cent.

•	Dividend Reinvestment Plan: In second quarter 2018, the DRP participation rate amongst common shareholders was approximately 33 per cent, resulting in $208 million reinvested in common equity under the program. Year-to-date in 2018, the participation rate amongst common shareholders has been approximately 36 per cent, resulting in $442 million of dividends reinvested.

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•	ATM Equity Issuance Program: In second quarter 2018, 8.1 million common shares were issued under our Corporate ATM program at an average price of $54.63 per common share for gross proceeds of $443 million. In the six months ended June 30, 2018, 13.9 million common shares have been issued under the program at an average price of $55.42 per common share for gross proceeds of $772 million.

•

Comparable Distributable Cash Flow: Beginning in second quarter 2018, our determination of comparable distributable cash flow has been revised to exclude the deduction of maintenance capital expenditures for assets for which we have the ability to recover costs in pipeline tolls. We believe that including only non-recoverable maintenance capital expenditures in the calculation of distributable cash flow presents the best depiction of the cash available for reinvestment or distribution to shareholders. For our rate-regulated Canadian and U.S. natural gas pipelines, we have the opportunity to recover and earn a return on maintenance capital expenditures through current and future tolls. Tolling arrangements in our liquids pipelines provide for the recovery of maintenance capital expenditures. Therefore, we have not deducted the recoverable maintenance capital expenditures for these businesses in the calculation of comparable distributable cash flow.

•

2018 FERC Actions: In December 2016, the Federal Energy Regulatory Commission (FERC) issued a Notice of Inquiry (NOI) seeking comment on how to address the issue of whether its existing policies resulted in a ‘double recovery’ of income taxes in a pass-through entity such as a master limited partnership (MLP). This NOI was in response to a decision by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in United Airlines, Inc., et al. v. FERC (the United case), directing FERC to address the issue.

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