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•	Fourth quarter 2017 financial results:

◦	Comparable distributable cash flow of $1.3 billion or $1.45 per common share reflecting only non-recoverable maintenance capital expenditures

•	For the year ended December 31, 2017:

◦	Comparable distributable cash flow of $5.0 billion or $5.69 per common share reflecting only non-recoverable maintenance capital expenditures

•	Fourth quarter highlights:

◦	Announced a 10.4 per cent increase in the quarterly common share dividend to $0.69 per common share for the quarter ending March 31, 2018

◦	NGTL placed approximately $0.6 billion of facilities in service during the fourth quarter bringing the total to $1.7 billion in 2017

◦	Placed Rayne XPress and Gibraltar into service in November, followed by Leach XPress on January 1, 2018

◦	Received FERC certificates for the WB XPress, Mountaineer XPress and Gulf XPress projects

◦	Completed the sale of our Ontario solar assets for $541 million

◦	Announced that we would no longer be pursuing Energy East and related projects

◦	Raised US$1.25 billion in 2-year floating and fixed rate senior debt on November 15, 2017

◦	Concluded open seasons for the Keystone and Marketlink pipeline systems and secured incremental long-term contractual commitments

◦	Received approval for a route through Nebraska for Keystone XL from the Nebraska Public Service Commission

◦	In January 2018, announced that we received commercial support for the Keystone XL project

◦	In February 2018, announced a new NGTL System expansion for 2021 of $2.4 billion

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NGTL System: In February 2018, we announced a $2.4 billion NGTL System expansion with expected in-service dates between 2019 and 2021 that includes approximately 375 km (233 miles) of 16-inch to 48-inch pipeline, four compression units and associated facilities. We anticipate incremental firm receipt contracts of 664 TJ/d (620 MMcf/d) and firm delivery contracts to our major border export and intra-basin delivery locations of 1.1 PJ/d (1.0 Bcf/d). With this expansion, NGTL now has a $7.2 billion growth capital program, excluding the $1.9 billion Merrick pipeline project. In 2017, we placed approximately $1.7 billion of facilities in service.

•	North Montney: In 2017, we filed an application with the NEB for a variance to the existing approvals for the North Montney Project on the NGTL System to remove the condition that the project could only proceed once a

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•	NGTL 2018 Revenue Requirement: NGTL's 2016-2017 Settlement, which established revenue requirements for the system, expired on December 31, 2017. We continue to work with interested parties towards a new revenue requirement arrangement for 2018 and longer. While these discussions are underway, NGTL is operating under interim tolls for 2018 that were approved by the NEB on November 24, 2017.

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Canadian Mainline Long-Term Fixed-Price Service: On November 1, 2017, we began offering the new Long-Term Fixed-Price service on the Canadian Mainline. This NEB-approved service enables WCSB producers to transport up to 1.5 PJ/d (1.4 Bcf/d) of natural gas at a simplified toll of $0.77/GJ from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The service is underpinned by ten-year contracts that have early termination rights after five years. Any early termination will result in an increased toll for the last two years of the contract.

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Canadian Mainline 2018-2020 Toll Review: Tolls for the Canadian Mainline were previously established for 2015 to 2017 in accordance with the terms of the 2015-2030 LDC Settlement. While the settlement specified tolls for 2015 to 2020, the NEB ordered a toll review halfway through the six-year period which must include costs, forecast volumes, contract levels, deferral balances and any other material changes. A Supplemental Agreement for the 2018 to 2020 period was executed on December 8, 2017 and filed for approval with the NEB on December 18, 2017. The Agreement proposes lower tolls, maintains an incentive arrangement that provides the opportunity for a 10.1 per cent or greater return on 40 per cent deemed equity and describes the revenue requirements and billing determinants for the 2018-2020 period. We anticipate the NEB will provide direction and process to adjudicate the application in first quarter 2018. Interim tolls for 2018 were filed at the level established by the agreement and subsequently approved by the NEB on December 19, 2017.

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

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

•	Leach XPress: Leach XPress was placed in service January 1, 2018. This Columbia Gas project transports approximately 1.6 PJ/d (1.5 Bcf/d) of Marcellus and Utica gas supply to delivery points along the system.

•	WB, Mountaineer and Gulf XPress: The FERC certificate for WB XPress was received in November 2017 and the FERC certificates for Mountaineer XPress and Gulf XPress projects were received on December 29, 2017.

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Tula: Construction of the Tula pipeline continues with completion revised to late 2019 due to delays experienced by the Secretary of Energy, the governmental department which conducts indigenous consultations in Mexico. Construction of the Tula pipeline was substantially completed in 2017 with the exception of approximately 90 km (56 miles) of the pipeline. The delay has been recognized by the CFE as a force majeure event and we are finalizing amending agreements to formalize the schedule and payment impacts. As a result of the delay and increased costs of land and permitting, estimated project costs have increased by US$0.1 billion from the original estimate.

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Villa de Reyes: Construction has commenced, however, delays due to archeological investigations by federal authorities have caused the in-service date of the project to be revised to late 2018. The delay has been recognized as a force majeure event by the CFE and we are finalizing amending agreements to formalize the schedule and payment impacts. As a result of the delay and increased costs of land and permitting, estimated project costs have increased by US$0.2 billion from the original estimate.

•	Sur de Texas: Construction on the pipeline is progressing toward an anticipated in-service date of late 2018, with approximately 60 per cent of the off-shore construction completed as of the end of 2017.

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Keystone XL: In February 2017, we filed an application with the Nebraska Public Service Commission (PSC) seeking approval for the Keystone XL pipeline route through that state and received approval for an alternate route on November 20, 2017. On December 27, 2017, opponents of the Keystone XL project, and intervenors in the Keystone XL Nebraska regulatory proceeding, filed an appeal of the November 20, 2017 PSC decision seeking to have that decision overturned. TransCanada supports the decision of the Nebraska PSC and will actively participate in the appeal process to defend that decision.

•	Keystone Pipeline System: In fourth quarter 2017, we concluded open seasons for the Keystone and Marketlink pipeline systems and secured incremental long-term contractual support.

•	Northern Courier: The $1 billion Northern Courier project achieved commercial in-service in November 2017.

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White Spruce: In first quarter 2018, we anticipate receiving a decision from the Alberta Energy Regulator on the regulatory permit to construct the $200 million White Spruce pipeline, which will transport crude oil from Canadian Natural Resources Limited's Horizon facility in northeast Alberta into the Grand Rapids pipeline. Due to the delay in the regulatory process, we expect the White Spruce pipeline to be in-service in 2019.

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Energy East and Related Projects: In September 2017, we requested the NEB suspend the review of the Energy East and Eastern Mainline project applications for 30 days to provide time for us to conduct a careful review of the NEB's changes, announced on August 23, 2017, regarding the list of issues and environmental assessment factors related to the projects and how these changes impact the projects' costs, schedules and viability. In October 2017, we announced that we would no longer be pursuing these projects. We reviewed the $1.3 billion carrying value of the projects, including AFUDC capitalized since inception, and recorded a $954 million after-tax non-cash charge in fourth quarter 2017. With Energy East’s inability to reach a regulatory decision, no recoveries of costs from third parties are forthcoming.

•	Napanee: Construction continues on our 900 MW natural gas-fired power plant. We expect to invest approximately $1.3 billion in the Napanee facility and commercial operations are expected to begin in fourth

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•	Ontario Solar: On October 24, 2017, we entered into an agreement to sell our Ontario solar assets comprised of eight facilities with a total generating capacity of 76 MWs. On December 19, 2017, we closed the sale for $541 million resulting in a pre-tax gain of $127 million ($136 million after-tax).

•	Monetization of U.S. Northeast power business: On December 22, 2017, we entered into an agreement to sell our U.S. power retail contracts as part of the continued wind down of our U.S. power marketing operations. The transaction is expected to close in the first quarter of 2018 subject to regulatory and other approvals.

•	Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.69 per share for the quarter ending March 31, 2018 on TransCanada's outstanding common shares. This represents an increase in the dividend of 10.4 per cent from the previous dividend and is equivalent to $2.76 per common share on an annualized basis.

•	Issuance of Senior Notes: On November 15, 2017, we raised US$700 million in Senior Unsecured Notes at a fixed interest rate of 2.125 per cent and US$550 million in Senior Unsecured Notes at a floating rate, both due in November 2019.

•	Dividend Reinvestment Plan (DRP): In 2017, the participation rate in our DRP was approximately 36 per cent of common share dividends, resulting in $790 million of common equity issued under the program.

•	ATM Equity Issuance Program: In fourth quarter 2017, 3.5 million common shares were issued through the corporate ATM program at an average price of $63.03 per share for gross proceeds of $218 million.

•	U.S. Tax Reform: As a result of changes to U.S. tax legislation resulting from the enactment of H.R. 1, the Tax Cuts and Jobs Act, in the fourth quarter we recorded an $804 million recovery of deferred income taxes, a $1,686 million increase in net regulatory liabilities and a $2,490 million decrease in net deferred income tax liabilities.

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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

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

•	expected capital expenditures and contractual obligations

•	expected operating and financial results

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

•	the expected impact of U.S. Tax Reform

•	expected industry, market and economic conditions.

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

•	inflation rates and commodity prices

•	nature and scope of hedging

•	regulatory decisions and outcomes

•	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

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•	outcomes of legal proceedings, including arbitration and insurance claims

•	performance and credit risk of our counterparties

•	changes in market commodity prices

•	changes in the political environment

•	changes in environmental and other laws and regulations

•	competitive factors in the pipeline and energy sectors

•	construction and completion of capital projects

•	costs for labour, equipment and materials

•	access to capital markets

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

•	weather

•	cyber security

•	technological developments

•	economic conditions in North America as well as globally.

•	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.

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

•	acquisition and integration costs.

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•	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

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•	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 $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 closing of the acquisition and $23 million of retention, severance and integration costs

•	an $18 million after-tax charge related to the maintenance and liquidation of Keystone XL assets which were 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 form 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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•	increased earnings from Liquids Pipelines primarily due to higher uncontracted volumes on the Keystone Pipeline System, liquids marketing activities, and the commencement of operations on Grand Rapids and Northern Courier

•	higher contribution from U.S. Natural Gas Pipelines due to lower operating costs including synergies achieved from the Columbia acquisition

•	higher AFUDC on our rate-regulated U.S. natural gas pipelines, partially offset by our decision not to proceed with the Energy East Pipeline

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

•	lower contribution from U.S. Power due to the monetization of our U.S. Northeast power generation assets in second quarter 2017 and the continued wind-down of our U.S. power marketing operations

•	an after-tax impairment charge in 2017 of $16 million related to obsolete Energy equipment.

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1	Leach XPress was placed in service in January 2018.

2	Reflects our proportionate share of costs related to Portland Xpress and various expansion projects.

3	Our proportionate share.

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4	Amount 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.

5	Reflects U.S./Canada foreign exchange rate of 1.25 at December 31, 2017.

1	Regulatory approvals have been obtained, additional commercial support is being pursued.

2	Our proportionate share.

3	Carrying value reflects amount remaining after impairment charge recorded in 2015.

4	Reflects U.S./Canada foreign exchange rate of 1.25 at December 31, 2017.

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1	Includes results from Foothills, Ventures LP, Great Lakes Canada, our share of equity income from our investment in TQM, and general and administration costs related to our Canadian Pipelines.

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1	Field receipt volumes for the NGTL System for the year ended December 31, 2017 were 4,224 Bcf (2016 – 4,117 Bcf). Average per day was 11.6 Bcf (2016 – 11.3 Bcf).

2	Canadian Mainline’s throughput volumes represent physical deliveries to domestic and export markets. Physical receipts originating at the Alberta border and in Saskatchewan for the year ended December 31, 2017 were 1,019 Bcf (2016 – 1,055 Bcf). Average per day was 2.8 Bcf (2016 – 2.9 Bcf).

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1	We completed the acquisition of Columbia on July 1, 2016. Results reflect our effective ownership in these assets from that date.

2

Results from Northern Border and Iroquois reflect our share of equity income from these investments. We acquired additional interests in Iroquois of 4.87 per cent on March 31, 2016 and 0.65 per cent on May 1, 2016. TC PipeLines, LP acquired 49.34 per cent of our 50 per cent interest in Iroquois on June 1, 2017. On January 1, 2016, we sold a 49.9 per cent direct interest in PNGTS to TC PipeLines, LP and its remaining 11.81 per cent interest to TC PipeLines, LP on June 1, 2017.

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

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

5	Includes our direct ownership in Iroquois and PNGTS (until June 1, 2017), our effective ownership in Millennium and Hardy Storage, and general and administrative costs related to U.S. natural gas assets.

6	Comparable EBITDA for the portions of TC PipeLines, LP, PNGTS (until June 1, 2017) and CPPL that we do not own. Effective February 17, 2017, we acquired the remaining publicly held units of CPPL.

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

•	incremental earnings from Mazatlán beginning December 2016

•	equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. The inter-affiliate loan interest is fully offset in interest income and other in the Corporate segment.

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1	Includes primarily liquids marketing and business development activities.

•	higher uncontracted volumes on the Keystone Pipeline System

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

•	a higher contribution from the liquids marketing business

•	higher business development activities, including advancement of Keystone XL

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

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

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

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

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

5	Includes a $21 million impairment charge in fourth quarter 2017 of obsolete equipment.

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•	a gain in 2017 of $127 million before tax related to the sale of our Ontario solar assets

•	a net gain in 2017 of $15 million before tax related to the monetization of our U.S. Northeast power assets which consisted primarily of insurance recoveries for a portion of repair costs incurred during an unplanned outage at Ravenswood prior to its sale

•	in 2016, a loss of $839 million before tax related to the sale of the U.S. Northeast power assets which included an $829 million pre-tax loss on the thermal and wind package and $10 million of pre-tax disposition costs

•	in 2016, a $92 million before tax loss on the transfer of environmental credits to the Balancing Pool upon final settlement of the Alberta PPA terminations

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

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

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

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

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

•	in 2017, a foreign exchange gain on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the project's financing. There is a corresponding foreign exchange loss included in interest income and other on the inter-affiliate loan receivable which fully offsets this gain

•	in 2016, pre-tax integration and acquisition costs associated with the acquisition of Columbia and restructuring costs.

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•	Canadian and U.S. dollar-denominated long-term debt and junior subordinated note issuances in 2017, net of maturities

•	retirement of the Columbia acquisition bridge facilities in June 2017

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

•	lower capitalized interest on Liquids Pipelines projects placed in-service in 2017.

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higher interest income along with a $64 million 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. Both currency-related amounts are excluded from comparable earnings

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

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

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

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1	The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties.

2	This income from equity investments relates to 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	The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties.

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1	The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties.

2	This income from equity investments relates to 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	The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as revenues in the segment providing the service, as expenses in the segment receiving the service and are eliminated on consolidation within the Corporate segment. Intersegment profit is recognized when the product or service has been provided to third parties.