TransCanada Reports Record Financial Results for 2017

10.4% Dividend Increase Supported by Strong Outlook for Future Growth

CALGARY, Alberta, Feb. 15, 2018  — TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today announced net income attributable to common shares for fourth quarter 2017 of $861 million or $0.98 per share compared to a net loss of $358 million or $0.43 per share for the same period in 2016. For the year ended December 31, 2017, net income attributable to common shares was $3.0 billion or $3.44 per share compared to net income of $124 million or $0.16 per share in 2016. Comparable earnings for fourth quarter 2017 were $719 million or $0.82 per common share compared to $626 million or $0.75 per share for the same period last year. For the year ended December 31, 2017, comparable earnings were $2.7 billion or $3.09 per common share compared to $2.1 billion or $2.78 per share in 2016. TransCanada’s Board of Directors also declared a quarterly dividend of $0.69 per common share for the quarter ending March 31, 2018, equivalent to $2.76 per common share on an annualized basis, an increase of 10.4 per cent. This is the eighteenth consecutive year the Board of Directors has raised the dividend.

“We are pleased that our vision of becoming one of North America’s leading energy infrastructure companies is becoming a reality. In 2017, we advanced a number of strategic initiatives and delivered record financial performance following the successful integration of Columbia into our operations,” said Russ Girling, TransCanada’s president and chief executive officer. “Comparable earnings per share increased eleven per cent compared to 2016 while comparable funds generated from operations of $5.6 billion were nine per cent higher than last year. The increases reflect the strong performance of our existing assets and approximately $5 billion of growth projects that were completed and placed into service during 2017. They included expansions of our NGTL and Canadian Mainline systems in our Canadian natural gas pipelines business, the Gibraltar and Rayne XPress projects in U.S. natural gas pipelines and the Grand Rapids and Northern Courier liquids pipelines in Alberta.”

“Looking forward, we will continue to advance a $23 billion near-term capital program, including an additional $2.4 billion on NGTL. This program is expected to generate significant additional growth in earnings and cash flow and support continued annual dividend growth at the upper end of an eight to ten per cent range through 2020 and an additional eight to ten per cent in 2021,” added Girling. “We have invested approximately $8 billion into these projects to date and are well positioned to fund the remainder of this capital program through our strong and growing internally generated cash flow and access to capital markets on compelling terms.”

“In addition, we continue to advance more than $20 billion of medium to longer-term projects including Keystone XL, Coastal GasLink and the Bruce Power life extension program. Progress on Keystone XL continues following the Nebraska Public Service Commission approval of a viable route through the state, which we support, and the receipt of commercial commitments for the project. At the same time we expect to secure additional organic growth associated with our extensive North American footprint in natural gas pipelines, liquids pipelines and power generation as evidenced by ongoing expansions of the NGTL System. These initiatives highlight the strong competitive position of our asset base and our proven ability to continuously replenish our growth portfolio with attractive, strategic, low-risk investment opportunities. Success in advancing these and other projects into construction and operation could extend our dividend growth outlook beyond 2021,” concluded Girling.

Highlights

(All financial figures are unaudited and in Canadian dollars unless noted otherwise)

Fourth quarter 2017 financial results:

• Net income attributable to common shares of $861 million or $0.98 per share
• Comparable earnings of $719 million or $0.82 per common share
• Comparable earnings before interest, taxes, depreciation and amortization of $1.9 billion
• Net cash provided by operations of $1.4 billion
• Comparable funds generated from operations of $1.5 billion
• 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:

• Net income attributable to common shares of $3.0 billion or $3.44 per share
• Comparable earnings of $2.7 billion or $3.09 per common share
• Comparable earnings before interest, taxes, depreciation and amortization of $7.4 billion
• Net cash provided by operations of $5.2 billion
• Comparable funds generated from operations of $5.6 billion
• 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

Net income attributable to common shares increased by $1.2 billion or $1.41 per share to $861 million or $0.98 per share for the three months ended December 31, 2017 compared to the same period last year. Fourth quarter 2017 results included 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 and a $64 million after-tax net gain related to the monetization of our U.S. Northeast power business. These gains were partially offset by 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 and 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. All of these specific items, as well as unrealized gains and losses from changes in risk management activities, are excluded from comparable earnings.

Net income attributable to common shares for the year ended December 31, 2017 was $3.0 billion or $3.44 per share compared to $124 million or $0.16 per share in 2016. Net income per common share includes the dilutive effect of issuing 161 million common shares in 2016 and common shares issued under our DRP and corporate ATM program in 2017. Results in 2017 included an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform, a $307 million after-tax net gain related to the monetization of our U.S. Northeast power business and a $136 million after-tax gain related to the sale of our Ontario solar assets. These items were partially offset by 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 $69 million after-tax charge for integration-related costs associated with the acquisition of Columbia, a $28 million after-tax charge related to the maintenance and liquidation of Keystone XL assets which were expensed pending further advancement of the project and a $7 million income tax recovery in first quarter related to the realized loss on a third party sale of Keystone XL project assets. All of these specific items, as well as unrealized gains and losses from changes in risk management activities, are excluded from comparable earnings.

Comparable earnings for fourth quarter 2017 were $719 million or $0.82 per share compared to $626 million or $0.75 per share for the same period in 2016, an increase of $93 million or $0.07 per share. The increase in fourth quarter comparable earnings was primarily due to the net effect of a higher contribution from U.S. Natural Gas Pipelines due to lower operating costs including synergies achieved from the Columbia acquisition, a higher contribution from Liquids Pipelines primarily due to higher volumes on Keystone, the commencement of operations on Northern Courier and Grand Rapids and liquids marketing activities, higher earnings from Bruce Power mainly due to higher volumes resulting from fewer outage days, and higher AFUDC on our rate-regulated U.S. natural gas pipelines, partially offset by our decision not to proceed with the Energy East pipeline, a 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 and an after-tax impairment charge in 2017 related to obsolete Energy equipment.

Comparable earnings for the year ended December 31, 2017 of $2.7 billion or $3.09 per share were $582 million or $0.31 per common share higher than in 2016 and includes the dilutive effect of issuing 161 million common shares in 2016 and common shares issued under our DRP and corporate ATM program in 2017. The 2017 increase in comparable earnings was primarily the net result of a higher contribution from U.S. Natural Gas Pipelines due to incremental earnings from Columbia following the July 2016 acquisition and higher ANR transportation revenue resulting from a FERC-approved rate settlement, increased earnings from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, liquids marketing activities and the commencement of operations on Grand Rapids and Northern Courier, higher earnings from Bruce Power mainly due to higher volumes resulting from fewer outage days, a higher contribution from Mexico Natural Gas Pipelines due to earnings from Topolobampo beginning in July 2016 and Mazatlan beginning in December 2016, higher AFUDC on our rate-regulated U.S. natural gas pipelines, the NGTL System, Tula and Villa de Reyes, partially offset by the commercial in-service of Topolobampo and completion of Mazatlan construction, and higher interest income and other due to income related to Coastal GasLink project costs and the termination of the PRGT project. These items were partially offset by lower contributions from U.S. Power due to the sales of our U.S. Northeast power generation assets in second quarter 2017 and the wind-down of our U.S. power marketing operations, as well as higher interest expense as a result of debt assumed in the acquisition of Columbia on July 1, 2016 and long-term debt and junior subordinated note issuances in 2017, net of maturities.

Notable recent developments include:

Canadian Natural Gas Pipelines:

• 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.On December 28, 2017, the NEB approved the Sundre Crossover Project on the NGTL System. The approximate $100 million project will increase delivery of 245 TJ/d (229 MMcf/d) to the Alberta / British Columbia border to connect with TransCanada downstream pipelines. In-service is planned for April 1, 2018.
• 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 positive final investment decision was made for the Pacific Northwest LNG project. The North Montney project is now underpinned by restructured 20-year commercial contracts and is not dependent on the LNG project proceeding. A hearing on the matter began the week of January 22, 2018 and a decision from the NEB is anticipated in second quarter 2018.
• 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.
• 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.
• 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.

U.S. Natural Gas Pipelines:

• 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.

Mexico Natural Gas Pipelines:

• 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.
• 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.

Liquids Pipelines:

• 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.In January 2018, TransCanada announced that we secured approximately 500,000 barrels per day of firm, 20- year commitments, following an open season in 2017, positioning the proposed project to proceed. The Company will look to continue to secure additional long-term contracted volumes. We are also continuing an outreach program in the communities where the pipeline will be constructed and are working collaboratively with landowners in an open and transparent way to obtain the necessary easements for the approved route. Construction preparation has commenced and will increase as the permitting process advances throughout 2018. Primary construction is expected to begin in 2019 and will take approximately two years to complete.
• 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.On November 16, 2017, the Keystone pipeline was temporarily shut down after a leak was detected in Marshall County, South Dakota. On November 29, 2017, the pipeline was repaired and returned to service at a reduced pressure in the affected section of the pipeline. Further investigative activities and corrective measures required by the Pipeline and Hazardous Materials Safety Administration (PHMSA) are planned for 2018. This shutdown did not have a significant impact on our 2017 earnings.
• Northern Courier: The $1 billion Northern Courier project achieved commercial in-service in November 2017.
• 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.
• 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.

Energy:

• 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 quarter 2018. Costs have increased due to delays in the construction schedule. Once in service, production from the facility is fully contracted with Ontario’s Independent Electricity System Operator for a 20-year period.
• 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.

Corporate:

• Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.69per 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.

Teleconference and Webcast:

We will hold a teleconference and webcast on Thursday, February 15, 2018 to discuss our fourth quarter 2017 and year-end financial results. Russ Girling, TransCanada President and Chief Executive Officer, and Don Marchand, Executive Vice-President and Chief Financial Officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 2 p.m. (MST) / 4 p.m. (EST).

Members of the investment community and other interested parties are invited to participate by calling 800.273.9672 or 416.340.2216 (Toronto area). No pass code is required. Please dial in 10 minutes prior to the start of the call. A live webcast of the teleconference will be available at www.transcanada.com.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EST) on February 22, 2018. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 2578190#.

The audited annual Consolidated Financial Statements and Management’s Discussion and Analysis (MD&A) are available under TransCanada’s profile on SEDAR at www.sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website at www.transcanada.com.

With more than 65 years’ experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and gas storage facilities. TransCanada operates one of the largest natural gas transmission networks that extends more than 91,900 kilometres (57,100 miles), tapping into virtually all major gas supply basins in North America. TransCanada is a leading provider of gas storage and related services with 653 billion cubic feet of storage capacity. A large independent power producer, TransCanada currently owns or has interests in approximately 6,100 megawatts of power generation in Canada and the United States. TransCanada is also the developer and operator of one of North America’s leading liquids pipeline systems that extends approximately 4,900 kilometres (3,000 miles) connecting growing continental oil supplies to key markets and refineries. TransCanada’s common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit TransCanada.com to learn more, or connect with us on social media and 3BL Media.

Media Enquiries:

Mark Cooper / Grady Semmens
1.403.920.7859
1.800.608.7859Toll-Free (North America)

TransCanada Investor & Analyst Enquiries:

David Moneta / Stuart Kampel
1.403.920.7911
1.800.361.6522Toll-Free (North America)

NT4