TransCanada Reports Record Financial Results for 2018

Increases Common Share Dividend for Nineteenth Consecutive Year

CALGARY, Alberta, Feb. 14, 2019 (GLOBE NEWSWIRE) — TransCanada Corporation (TSX, NYSE: TRP) (TransCanada or the Company) today announced net income attributable to common shares for fourth quarter 2018 of $1.1 billion or $1.19 per share compared to net income of $0.9 billion or $0.98 per share for the same period in 2017. For the year ended December 31, 2018, net income attributable to common shares was $3.5 billion or $3.92 per share compared to net income of $3.0 billion or $3.44 per share in 2017. Comparable earnings for fourth quarter 2018 were $946 million or $1.03 per common share compared to $719 million or $0.82 per share for the same period in 2017. For the year ended December 31, 2018, comparable earnings were $3.5 billion or $3.86 per common share compared to $2.7 billion or $3.09 per share in 2017. TransCanada’s Board of Directors also declared a quarterly dividend of $0.75 per common share for the quarter ending March 31, 2019, equivalent to $3.00 per common share on an annualized basis, an increase of 8.7 per cent. This is the nineteenth consecutive year the Board of Directors has raised the dividend.

“We are very pleased with the performance of our diversified portfolio of high-quality, long-life energy infrastructure assets which produced record financial results again in 2018,” said Russ Girling, TransCanada’s president and chief executive officer. “Comparable earnings per share increased twenty-five per cent compared to 2017 while comparable funds generated from operations of $6.5 billion were sixteen per cent higher than last year. The increases reflect the strong performance of our legacy assets, contributions from approximately $4 billion of growth projects that were placed into service and the positive impact of U.S. Tax Reform.”

“With our existing asset base expected to benefit from supportive market fundamentals and $36 billion of secured growth projects currently underway, approximately $9 billion of which is commissioning or nearing completion, earnings and cash flow are forecast to continue to rise. This is expected to support annual dividend growth of eight to ten per cent through 2021,” added Girling. “We have invested $13 billion in these projects to date and are well positioned to fund the remainder of our secured growth program through significant and growing internally generated cash flow, access to capital markets and further portfolio management activities. As outlined in the third quarter, we view the issuance of common shares under our At-The-Market equity program as being complete and will continue to evaluate the use of our Dividend Reinvestment Program on a quarterly basis. We also continue to progress various portfolio management activities, including the recently announced sale of our Coolidge generating station which is expected to close by mid-year. This will allow us to prudently fund our capital program in a manner that is consistent with achieving targeted leverage metrics in 2019.”

“Looking ahead, we will also continue to carefully advance more than $20 billion of projects under development including Keystone XL and the Bruce Power life extension program. Success in advancing these and other growth initiatives that are expected to emanate from TransCanada’s five operating businesses across North America could extend our growth outlook well into the next decade,” concluded Girling.

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

• Fourth quarter 2018 financial results
  • Net income attributable to common shares of $1.1 billion or $1.19 per common share
  • Comparable earnings of $946 million or $1.03 per common share
  • Comparable earnings before interest, taxes, depreciation and amortization of $2.5 billion
  • Net cash provided by operations of $2.0 billion
  • Comparable funds generated from operations of $1.9 billion
  • Comparable distributable cash flow of $1.7 billion or $1.89 per common share
• For the year ended December 31, 2018
  • Net income attributable to common shares of $3.5 billion or $3.92 per common share
  • Comparable earnings of $3.5 billion or $3.86 per common share
  • Comparable earnings before interest, taxes, depreciation and amortization of $8.6 billion
  • Net cash provided by operations of $6.6 billion
  • Comparable funds generated from operations of $6.5 billion
  • Comparable distributable cash flow of $5.9 billion or $6.52 per common share
• Fourth quarter highlights
  • TransCanada’s Board approved an 8.7 per cent increase in the quarterly common share dividend to $0.75 per common share for the quarter ending March 31, 2019
  • Announced that we will proceed with construction of the $6.2 billion Coastal GasLink pipeline project
  • Announced $1.5 billion NGTL 2022 Expansion Program
  • Secured transportation contracts for the North Bay Junction Long Term Fixed Price service on the Canadian Mainline
  • Completed the sale of our interests in the Cartier Wind power facilities for approximately $630 million
  • Entered into an agreement to sell our Coolidge generating station for approximately US$465 million with closing expected to occur in mid-2019
  • Reimbursed for $470 million of Coastal GasLink pre-Final Investment Decision costs
  • In January 2019, announced planned name change to TC Energy subject to shareholder and regulatory approval

Net income attributable to common shares increased by $231 million or $0.21 per share to $1.1 billion or $1.19 per share for the three months ended December 31, 2018 compared to the same period last year primarily due to changes in net income described below, as well as the dilutive effect of common shares issued in 2017 and 2018 under our DRP and Corporate ATM program. Fourth quarter 2018 results included a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities; a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions; a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform; a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets; and $25 million of income after tax and after non-controlling interests recognized on the Bison contract terminations. These items were partially offset by a $140 million impairment charge on Bison after tax and after non-controlling interests; a $15 million goodwill impairment charge on Tuscarora after tax and after non-controlling interests; and an after-tax net loss of $7 million related to our U.S. Northeast power marketing contracts. 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, 2018 was $3.5 billion or $3.92 per share compared to $3.0 billion or $3.44 per share in 2017 due to the changes in net income described below, as well as the dilutive effect of common shares issued in 2017 and 2018 under our DRP and Corporate ATM program. Results in 2018 include the items highlighted for fourth quarter 2018 with a full year after-tax net loss related to our U.S. Northeast power marketing contracts of $4 million. All of these specific items, as well as unrealized gains and losses from changes in risk management activities, are excluded from comparable earnings.

Comparable EBITDA for fourth quarter 2018 increased by $550 million to $2.5 billion compared to the same period in 2017 primarily due to the net effect of the following:

• higher contribution from Canadian Natural Gas Pipelines primarily due to the recovery of increased depreciation approved in both the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher flow-through taxes and incentive earnings
• 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 higher volumes on the Keystone Pipeline System, increased earnings from liquids marketing activities and earnings from intra-Alberta pipelines placed in service in the second half of 2017
• higher revenues from Mexico Natural Gas Pipelines as a result of changes in timing of revenue recognition
• lower earnings from Bruce Power primarily due to lower volumes resulting from higher outage days.

Comparable earnings for fourth quarter 2018 were $946 million or $1.03 per common share compared to $719 million or $0.82 per share for the same period in 2017, an increase of $227 million or $0.21 per share which was primarily the net result of the following:

• changes in comparable EBITDA described above
• higher depreciation primarily in Canadian Natural Gas Pipelines due to increased depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement (these amounts are fully recovered as reflected in the increase in comparable EBITDA described above, having no net impact on comparable earnings) as well as higher depreciation related to new projects placed in service in 2017 and 2018
• higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities
• lower interest income and other as a result of realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Comparable EBITDA in 2018 increased by $1.2 billion to $8.6 billion compared to 2017 primarily due to the net effect of the following:

• 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 higher volumes on the Keystone Pipeline System, increased earnings from liquids marketing activities and earnings from intra-Alberta pipelines placed in service in the second half of 2017
• higher contribution from Canadian Natural Gas Pipelines primarily due to the recovery of increased depreciation as a result of higher rates approved in both the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher overall pre-tax rate base earnings, partially offset by lower incentive earnings and flow-through income taxes
• lower earnings from U.S. Power mainly due to the sales of our U.S. Northeast power generation assets in second quarter 2017
• lower earnings from Bruce Power primarily due to lower volumes resulting from higher outage days and lower results from contracting activities.

Comparable earnings in 2018 of $3.5 billion or $3.86 per common share were $790 million or $0.77 per share higher than in 2017. The 2018 increase was primarily the net result of the following:

• changes in comparable EBITDA described above
• higher depreciation primarily in Canadian Natural Gas Pipelines due to increased depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement (these amounts are fully recovered as reflected in the increase in comparable EBITDA described above, having no net impact on comparable earnings) as well as higher depreciation related to new projects placed in service in 2017 and 2018
• higher interest expense primarily as a result of additional long-term debt issuances in 2018 and the full year impact of long-term debt and junior subordinated notes issuances in 2017, net of maturities, as well as lower capitalized interest, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017
• lower income tax expense primarily due to reduced income tax rates resulting from U.S. Tax Reform and lower flow-through income taxes in Canadian rate-regulated pipelines.

Notable recent developments include:

Canadian Natural Gas Pipelines:

• Coastal GasLink Pipeline Project: In October 2018, we announced that we are proceeding with construction of the Coastal GasLink pipeline project following the LNG Canada joint venture participants’ announcement that they had reached a positive Final Investment Decision (FID) to build the LNG Canada natural gas liquefaction facility in Kitimat, B.C. Coastal GasLink will provide the natural gas supply to the LNG Canada facility and is underpinned by 25-year TSAs (with additional renewal provisions) with each of the five LNG Canada participants. Coastal GasLink will be a 670 km (416 miles) pipeline with an initial capacity of approximately 2.2 PJ/d (2.1 Bcf/d) with potential expansion capacity up to 5.4 PJ/d (5.0 Bcf/d). All necessary regulatory permits have been received to allow us to proceed with construction activities which began in December 2018, with a planned in-service date in 2023. Coastal GasLink has signed project and community agreements with all 20 elected Indigenous bands along the pipeline route, confirming strong support from Indigenous communities across the province of B.C.

  In July 2018, an individual asked the National Energy Board (NEB) to consider whether the Coastal GasLink pipeline should be federally regulated by the NEB. In October 2018, the NEB advised that it would consider the question of jurisdiction, granted Coastal GasLink standing in the matter, and reserved the right to decide on the participation of all other potentially interested parties, including the individual who raised the question. In December 2018, the NEB issued a process letter addressing participation and set the schedule which is expected to conclude in the second half of 2019, with a decision to follow.

  The Coastal GasLink capital cost estimate is $6.2 billion with the majority of the construction spend occurring in 2020 and 2021. Subject to terms and conditions, differences between the estimated capital cost and final cost of the project will be recovered in future pipeline tolls. As part of the Coastal GasLink funding plan, we are exploring joint venture partners and project financing.

  The total capital cost includes pre-FID costs incurred of $470 million. In accordance with provisions in the agreements with the LNG Canada joint venture participants, all five parties elected to reimburse us for their share of pre-FID costs, totaling $470 million, in November 2018. In addition, in January 2019, all five partners elected to make cash payments throughout the construction period with respect to carrying charges on costs incurred.

• NGTL System: In October 2018, we announced the NGTL System 2022 Expansion Program to meet capacity requirements for incremental firm receipt and intra-basin delivery services to commence in November 2021 and April 2022. This $1.5 billion expansion of the NGTL System consists of approximately 197 km (122 miles) of new pipeline, three compressor units, meter stations and associated facilities. Applications for approvals to construct and operate the facilities are expected to be filed with the NEB in second quarter 2019 and, pending receipt of regulatory approvals, construction would start as early as third quarter 2020. The NGTL capital program, excluding maintenance capital expenditures, is now approximately $8.6 billion.
• Canadian Mainline: In December 2018, we announced the North Bay Junction Long Term Fixed Price service (NBJ LTFP) which includes 670 TJ/d (625 MMcf/d) of new natural gas transportation contracts from the Western Canadian Sedimentary Basin (WCSB) on the Canadian Mainline. Upon NEB approval of the NBJ LTFP service, incremental volumes under these long-term, fixed-priced contracts will reach markets in Ontario, Québec, New Brunswick, Nova Scotia and the Northeastern U.S. using existing capacity on the Canadian Mainline as well as new compression facilities. Customers have executed 15-year precedent agreements to proceed with the project with an estimated capital cost of $96 million. We filed an application for approval of the NBJ LTFP with the NEB in January 2019 and expect a decision in third quarter 2019.

  In October 2018, we concluded the written hearing process for the Canadian Mainline 2018-2020 toll review with the filing of our reply evidence to the NEB. In December 2018, the NEB 2018 Decision was issued approving all elements of the application, including our cost and volume forecasts, higher depreciation rates and continuation of pricing discretion, with the exception of the amortization period for the Long Term Adjustment Account (LTAA), which is now to be amortized over 2018 to 2020. The impact of the decision was reflected in lower tolls effective February 1, 2019. As directed by the NEB, we filed a compliance filing in January 2019, the outcome of which is expected in first quarter 2019.

U.S. Natural Gas Pipelines:

• WB XPress: The WB XPress project, a Columbia Gas project designed to transport approximately 1.4 PJ/d (1.3 Bcf/d) of Marcellus gas supply westbound to the Gulf Coast and eastbound to Mid-Atlantic Markets, was placed in service in October 2018 and November 2018 for the Western Build and Eastern Build, respectively.
• Mountaineer XPress and Gulf XPress: Mountaineer XPress (MXP), a Columbia Gas project, is designed to transport supply from the Marcellus and Utica shale plays to points along the system and to the Leach interconnect with Columbia Gulf. Approximately 45 per cent of this project was placed in service on January 18, 2019, with the remainder to be placed in service in February and March 2019, along with Gulf XPress, a Columbia Gulf project. Total estimated MXP project costs have been revised upwards to US$3.2 billion reflecting the impact of delays of various regulatory approvals from FERC and other agencies, increased contractor construction costs due to unusually high demand for construction resources in the region, unusually high instances of inclement weather throughout construction, and modifications to contractor work plans to mitigate construction delays associated with these impacts.
• Louisiana XPress: In November 2018, we sanctioned the Louisiana XPress project which will connect supply directly to Gulf Coast LNG export markets with the addition of three greenfield mid-point compressor stations along Columbia Gulf. The anticipated in-service date is in 2022 and estimated project costs are US$0.4 billion.
• Bison contract terminations and asset impairment: In the second half of 2018, two customers on Bison elected to pay out the remainder of their future contracted revenues and terminate their associated TSAs. The termination of these agreements was agreed to following the receipt of US$97 million in 2018, which was recorded in Revenues, as the terminations released us from providing any future services. This development, coupled with the persistence of unfavourable market conditions which have inhibited system flows on the pipeline, led us to determine that the asset’s remaining carrying value was no longer recoverable and a non-cash impairment charge of US$537 million was recorded in our U.S. Natural Gas Pipelines segment. As Bison is a TC PipeLines, LP asset, in which we have a 25.5 per cent interest, this impairment charge impacts our net income by $140 million after tax and non-controlling interests, but is excluded from comparable earnings. We continue to explore alternative transportation-related options for Bison.
• Tuscarora goodwill impairment: In fourth quarter 2018, Tuscarora finalized its regulatory approach in response to the 2018 FERC Actions, resulting in a reduction in its recourse rates. In connection with its annual goodwill impairment analysis, we evaluated Tuscarora’s future revenues as well as changes to other assumptions responsive to Tuscarora’s commercial environment. In doing so, we incorporated the outcome of a settlement-in-principle reached with its customers in January 2019. As a result of these developments, we determined that the fair value of Tuscarora did not exceed its carrying value, including goodwill, and recorded a goodwill impairment charge of US$59 million within the U.S. Natural Gas Pipelines segment. The remaining goodwill balance related to Tuscarora at December 31, 2018 was US$23 million. As Tuscarora is a TC PipeLines, LP asset, in which we have a 25.5 per cent interest, this impairment charge impacts our net income by $15 million after tax and non-controlling interests, but is excluded from comparable earnings.

Mexico Natural Gas Pipelines:

• Sur de Texas: Offshore construction was completed in May 2018 and the project continues to progress toward an anticipated in-service date in early second quarter 2019. An amending agreement was signed with the CFE that recognizes force majeure events and the commencement of payments of fixed capacity charges began on October 31, 2018.

Liquids Pipelines:

• Keystone XL: We have secured commercial support for all available Keystone XL project capacity and commenced certain pre-construction activities. We continue to address outstanding legal challenges regarding the project. The South Dakota Supreme Court dismissed an appeal against the certification of the project. We expect the Nebraska Supreme Court to reach a decision in the first quarter of 2019 regarding a challenge to the Nebraska Public Service Commission’s route approval. We continue to participate, together with the U.S. Department of Justice, in lawsuits commenced in Montana to defend legal challenges to the U.S. Presidential Permit and the exhaustive environmental assessments that support the U.S. President’s actions.

Energy:

• Cartier Wind: In October 2018, we completed the sale of our interests in the Cartier Wind power facilities in Québec to Innergex Renewable Energy Inc. for gross proceeds of approximately $630 million before closing adjustments, resulting in a gain of $170 million ($143 million after tax).
• Coolidge Generating Station: On December 14, 2018, we entered into an agreement to sell our Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC, for approximately US$465 million, subject to timing of the close and related adjustments. Salt River Project Agriculture Improvement and Power District, the PPA counterparty, exercised its contractual right of first refusal on a sale to a third party in January 2019. The sale will result in an estimated gain of approximately $65 million ($50 million after tax) to be recognized upon closing of the sale transaction which is expected to occur mid-2019.
• Napanee: Construction is substantially complete and commissioning activities are continuing at our 900 MW natural gas-fired power plant in eastern Ontario in the town of Greater Napanee. We expect our total investment in the Napanee facility will be approximately $1.7 billion with commercial operations expected to begin in second quarter 2019.

Corporate:

• Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.75 per share for the quarter ending March 31, 2019 on TransCanada’s outstanding common shares. This represents an increase in the dividend of 8.7 per cent from the previous dividend and is equivalent to $3.00 per common share on an annualized basis.
• Issuance of Long-term Debt: In fourth quarter 2018, TCPL issued US$1.0 billion of Senior Unsecured Notes due in March 2049 bearing interest at a fixed rate of 5.10 per cent and US$400 million of Senior Unsecured Notes due in May 2028 bearing interest at a fixed rate of 4.25 per cent.

  The net proceeds of the debt issuances were used for general corporate purposes, to fund our capital program and to pre-fund early 2019 senior note maturities.

• Dividend Reinvestment Plan: In 2018, the DRP participation rate by common shareholders was approximately 35 per cent, resulting in $870 million reinvested in common equity under the program.
• ATM Equity Program: In 2018, 20 million common shares were issued under the Corporate ATM program at an average price of $56.13 per common share for proceeds of $1.1 billion, net of approximately $10 million of related commissions and fees. We view the issuance of common shares under this program as being complete.
• Proposed Name Change: On January 9, 2019, we announced our intention to change our name to TC Energy to better reflect the scope of the company’s operations as a leading North American energy infrastructure company. The name change is subject to shareholder and regulatory approval and would be effective immediately following the Annual and Special Meeting of Shareholders in the second quarter of 2019.
• Management Changes: Karl Johannson and Kristine Delkus will be retiring from the Company in the first and second quarters of 2019, respectively. Effective January 1, 2019, Tracy Robinson was appointed Executive Vice-President and President, Canadian Natural Gas Pipelines and Francois Poirier was appointed to the expanded role of President of the Energy and Mexico Natural Gas Pipelines business units in addition to his role as Executive Vice-President, Strategy and Corporate Development.

Teleconference and Webcast:

We will hold a teleconference and webcast on Thursday, February 14, 2019 to discuss our fourth quarter 2018 and year-end financial results. Russ Girling, 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. (MT) / 4 p.m. (ET).

Members of the investment community and other interested parties are invited to participate by calling 800.273.9672 or 416.340.2216 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com or via the following URL: www.gowebcasting.com/9855.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on February 21, 2019. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 4856336#.

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 92,600 kilometres (57,500 miles), connecting major gas supply basins to markets across 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 more than 6,600 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 www.transcanada.com to learn more, or connect with us on social media.

Forward Looking Information:

This release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as “anticipate”, “expect”, “believe”, “may”, “will”, “should”, “estimate”, “intend” or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management’s assessment of TransCanada’s and its subsidiaries’ future plans and financial outlook. All forward-looking statements reflect TransCanada’s beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to the Quarterly Report to Shareholders dated February 13, 2019 and the 2018 Annual Report filed under TransCanada’s profile on SEDAR at www.sedar.com and with the U.S. Securities and Exchange Commission at www.sec.gov.

Non-GAAP Measures:

This news release contains references to non-GAAP measures, including comparable earnings, comparable earnings per common share, comparable EBITDA, comparable distributable cash flow, comparable distributable cash flow per common share and comparable funds generated from operations, that do not have any standardized meaning as prescribed by U.S. GAAP and therefore are unlikely to be comparable to similar measures presented by other companies. These non-GAAP measures are calculated on a consistent basis from period to period except as otherwise described in the MD&A included in our Quarterly Report to Shareholders dated February 13, 2019 and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada’s Quarterly Report to Shareholders dated February 13, 2019.

Media Enquiries:
Grady Semmens
403.920.7859 or 800.608.7859

Investor & Analyst Enquiries:    
David Moneta / Duane Alexander
403.920.7911 or 800.361.6522

Fourth quarter 2018

Financial highlights

¹ Includes capital expenditures, capital projects in development and contributions to equity investments.

FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and potential investors understand management’s assessment of our future plans and financial outlook, and our future prospects overall.

Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.

Forward-looking statements in this news release include information about the following, among other things:

• our financial and operational performance, including the performance of our subsidiaries
• expectations about strategies and goals for growth and expansion
• expected cash flows and future financing options available, including portfolio management
• expected dividend growth
• expected future credit ratings
• expected costs and schedules for planned projects, including projects under construction and in development
• expected capital expenditures and contractual obligations
• expected regulatory processes and outcomes, including the impact of the 2018 FERC Actions
• expected outcomes with respect to legal proceedings, including arbitration and insurance claims
• the expected impact of future accounting changes, commitments and contingent liabilities
• expected industry, market and economic conditions.

Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this news release.

Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:

Assumptions

• regulatory decisions and outcomes, including final outcomes of the 2018 FERC Actions
• planned and unplanned outages and the use of our pipeline and energy assets
• integrity and reliability of our assets
• anticipated construction costs, schedules and completion dates
• access to capital markets, including portfolio management
• expected industry, market and economic conditions
• inflation rates and commodity prices
• interest, tax and foreign exchange rates
• nature and scope of hedging.

Risks and uncertainties

• our ability to successfully implement our strategic priorities and whether they will yield the expected benefits
• our ability to implement a capital allocation strategy aligned with maximizing shareholder value
• the operating performance of our pipeline and energy assets
• amount of capacity sold and rates achieved in our pipeline businesses
• the amount of capacity payments and revenues from our energy business due to plant availability
• production levels within supply basins
• construction and completion of capital projects
• costs for labour, equipment and materials
• the availability and market prices of commodities
• access to capital markets on competitive terms
• interest, tax and foreign exchange rates
• performance and credit risk of our counterparties
• regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims
• changes in environmental and other laws and regulations
• competition in the pipeline and energy sectors
• unexpected or unusual weather
• acts of civil disobedience
• cyber security and technological developments
• economic conditions in North America as well as globally
• our ability to effectively anticipate and assess changes to government policies and regulations.

You can read more about these factors in other reports we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2018 Annual Report.

As actual results could vary significantly from the forward-looking information, you should not put undue reliance on forward-looking information and should not use future-oriented information or financial outlooks for anything other than their intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are required to by law.

FOR MORE INFORMATION
You can also find more information about TransCanada in our Annual Information Form (AIF) and other disclosure documents, which are available on SEDAR (www.sedar.com).

NON-GAAP MEASURES
This news release references the following non-GAAP measures:

• comparable EBITDA
• comparable EBIT
• comparable earnings
• comparable earnings per common share
• funds generated from operations
• comparable funds generated from operations
• comparable distributable cash flow
• comparable distributable cash flow per common share.

These measures do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar measures presented by other entities.

Comparable measures
We calculate comparable measures by adjusting certain GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Except as otherwise described herein, these comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.

Our decision not to adjust for a specific item is subjective and made after careful consideration. Specific items may include:

• certain fair value adjustments relating to risk management activities
• income tax refunds and adjustments 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.

We exclude the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.

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