TransCanada Reports Record Financial Results for 2018

CBJ Newsmakers

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

    three months ended
December 31
  year ended
December 31
(millions of $, except per share amounts)     2018       2017       2018       2017  
                 
Income                
Revenues     3,904       3,617       13,679       13,449  
Net income attributable to common shares     1,092       861       3,539       2,997  
per common share – basic   $1.19     $0.98     $3.92     $3.44  
                                 – diluted   $1.19     $0.98     $3.92     $3.43  
Comparable EBITDA     2,453       1,903       8,563       7,377  
Comparable earnings     946       719       3,480       2,690  
per common share   $1.03     $0.82     $3.86     $3.09  
                 
Cash flows                
Net cash provided by operations     2,039       1,390       6,555       5,230  
Comparable funds generated from operations     1,881       1,450       6,522       5,641  
Comparable distributable cash flow     1,727       1,272       5,885       4,963  
per common share   $1.89     $1.45     $6.52     $5.69  
Capital spending1     3,438       2,552       10,929       9,210  
Proceeds from sales of assets, net of transaction costs     614       536       614       4,683  
Reimbursement of costs related to capital projects in development     470       634       470       634  
                 
Dividends declared                
Per common share   $0.69     $0.625     $2.76     $2.50  
Basic common shares (millions)                
– weighted average for the period     915       877       902       872  
– issued and outstanding at end of period     918       881       918       881  

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.

The following table identifies our non-GAAP measures and their most directly comparable GAAP measures.

Non-GAAP measure GAAP measure
   
comparable EBITDA segmented earnings
comparable EBIT segmented earnings
comparable earnings net income attributable to common shares
comparable earnings per common share net income per common share
comparable funds generated from operations net cash provided by operations
comparable distributable cash flow net cash provided by operations

Comparable EBITDA and comparable EBIT
Comparable EBITDA represents segmented earnings adjusted for certain specific items, excluding non-cash charges for depreciation and amortization. We use comparable EBITDA as a measure of our earnings from ongoing operations as it is a useful indicator of our performance and is also presented on a consolidated basis. Comparable EBIT represents segmented earnings adjusted for specific items. Comparable EBIT is an effective tool for evaluating trends in each segment. Refer to the Reconciliation of non-GAAP measures section for a reconciliation to segmented earnings.

Comparable earnings and comparable earnings per common share
Comparable earnings represents earnings or losses attributable to common shareholders on a consolidated basis adjusted for specific items. Comparable earnings is comprised of segmented earnings, interest expense, AFUDC, interest income and other, income taxes, non-controlling interests and preferred share dividends adjusted for specific items. Refer to the Reconciliation of net income to comparable earnings section.

Funds generated from operations and comparable funds generated from operations
Funds generated from operations reflects net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. Comparable funds generated from operations is adjusted for the cash impact of specific items noted above. Refer to the Cash provided by operating activities section for a reconciliation to net cash provided by operations.

Comparable distributable cash flow and comparable distributable cash flow per common share
We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. Comparable distributable cash flow is defined as comparable funds generated from operations less preferred share dividends, distributions to non-controlling interests and non-recoverable maintenance capital expenditures. Refer to the Cash provided by operating activities section for a reconciliation to net cash provided by operations.

Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability, and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. We have the opportunity to recover effectively all of our pipeline maintenance capital expenditures in Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Liquids Pipelines through tolls. Canadian natural gas pipelines maintenance capital expenditures are included in rate bases, on which we earn a regulated return and subsequently recover in tolls. Our U.S. natural gas pipelines can recover maintenance capital expenditures through tolls under current rate settlements, or have the ability to recover such expenditures through tolls established in future rate cases or settlements. Tolling arrangements in our liquids pipelines provide for the recovery of maintenance capital expenditures. As such, in 2018 our presentation of comparable distributable cash flow and comparable distributable cash flow per common share only includes a reduction for non-recoverable maintenance capital expenditures in their respective calculations. We have adjusted our comparable distributable cash flow and comparable distributable cash flow per common share for 2017 to reflect the amended presentation format which we believe provides better information for readers.

Consolidated results – fourth quarter 2018

We operate in three core businesses – Natural Gas Pipelines, Liquids Pipelines and Energy. In order to provide information that is aligned with how management decisions about our businesses are made and how performance of our businesses is assessed, our results are reflected in five operating segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. We also have a Corporate segment, consisting of corporate and administrative functions that provide governance and other support to our operational business segments.

    three months ended
December 31
  year ended
December 31
(millions of $, except per share amounts)     2018       2017       2018       2017  
                 
Segmented earnings/(losses)                
Canadian Natural Gas Pipelines     450       333       1,250       1,236  
U.S. Natural Gas Pipelines     (34 )     461       1,700       1,760  
Mexico Natural Gas Pipelines     128       93       510       426  
Liquids Pipelines     532       (932 )     1,579       (251 )
Energy     315       472       779       1,552  
Corporate     23       63       (54 )     (39 )
Total segmented earnings     1,414       490       5,764       4,684  
Interest expense     (603 )     (541 )     (2,265 )     (2,069 )
Allowance for funds used during construction     161       140       526       507  
Interest income and other     (215 )     (9 )     (76 )     184  
Income before income taxes     757       80       3,949       3,306  
Income tax (expense)/recovery     (38 )     870       (432 )     89  
Net income     719       950       3,517       3,395  
Net loss/(income) attributable to non-controlling interests     414       (49 )     185       (238 )
Net income attributable to controlling interests     1,133       901       3,702       3,157  
Preferred share dividends     (41 )     (40 )     (163 )     (160 )
Net income attributable to common shares     1,092       861       3,539       2,997  
Net income per common share — basic   $1.19     $0.98     $3.92     $3.44  
                                                      — diluted   $1.19     $0.98     $3.92     $3.43  

Net income attributable to common shares increased by $231 million or $0.21 per common share for the three months ended December 31, 2018 compared to the same period in 2017 primarily due to changes in net income described below, as well as the dilutive impact 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
  • $25 million of after-tax income recognized on the Bison contract terminations
  • a $140 million after-tax impairment charge on Bison
  • a $15 million after-tax goodwill impairment charge on Tuscarora
  • an after-tax net loss of $7 million related to our U.S. Northeast power marketing contracts.

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
  • a $64 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets
  • 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.

Net income in both periods included unrealized gains and losses from changes in risk management activities, which we exclude, along with the above noted items, to arrive at comparable earnings.

A reconciliation of net income attributable to common shares to comparable earnings is shown in the following table.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS

    three months ended
December 31
  year ended
December 31
(millions of $, except per share amounts)     2018       2017       2018       2017  
                 
Net income attributable to common shares     1,092       861       3,539       2,997  
Specific items (net of tax):                
Gain on sale of Cartier Wind power facilities     (143 )           (143 )      
MLP regulatory liability write-off     (115 )           (115 )      
U.S. Tax Reform     (52 )     (804 )     (52 )     (804 )
Net gain on sales of U.S. Northeast power generation assets     (27 )     (64 )     (27 )     (307 )
Bison contract terminations     (25 )           (25 )      
Bison asset impairment     140             140        
Tuscarora goodwill impairment     15             15        
U.S. Northeast power marketing contracts     7             4        
Gain on sale of Ontario solar assets           (136 )           (136 )
Energy East impairment charge           954             954  
Keystone XL asset costs           9             28  
Keystone XL income tax recoveries                       (7 )
Integration and acquisition related costs – Columbia                       69  
Risk management activities1     54       (101 )     144       (104 )
Comparable earnings     946       719       3,480       2,690  
Net income per common share   $1.19     $0.98     $3.92     $3.44  
Specific items (net of tax):                
Gain on sale of Cartier Wind power facilities     (0.16 )           (0.16 )      
MLP regulatory liability write-off     (0.13 )           (0.13 )      
U.S. Tax Reform     (0.06 )     (0.92 )     (0.06 )     (0.92 )
Net gain on sales of U.S. Northeast power generation assets     (0.03 )     (0.08 )     (0.03 )     (0.34 )
Bison contract terminations     (0.03 )           (0.03 )      
Bison asset impairment     0.16             0.16        
Tuscarora goodwill impairment     0.02             0.02        
U.S. Northeast power marketing contracts     0.01             0.01        
Gain on sale of Ontario solar assets           (0.16 )           (0.16 )
Energy East impairment charge           1.09             1.09  
Keystone XL asset costs           0.01             0.03  
Keystone XL income tax recoveries                       (0.01 )
Integration and acquisition related costs – Columbia                       0.08  
Risk management activities1     0.06       (0.10 )     0.16       (0.12 )
Comparable earnings per common share   $1.03     $0.82     $3.86     $3.09  

1   Risk management activities   three months ended
December 31
  year ended
December 31
    (millions of $)   2018     2017     2018     2017  
                     
    Liquids marketing   81     15     71      
    Canadian Power       6     3     11  
    U.S. Power   20     136     (11 )   39  
    Natural Gas Storage   (5 )   7     (11 )   12  
    Interest rate               (1 )
    Foreign exchange   (169 )   (1 )   (248 )   88  
    Income tax attributable to risk management activities   19     (62 )   52     (45 )
    Total unrealized (losses)/gains from risk management activities   (54 )   101     (144 )   104  


COMPARABLE EBITDA TO COMPARABLE EARNINGS

Comparable EBITDA represents segmented earnings adjusted for certain aspects of the specific items described above and excludes non-cash charges for depreciation and amortization.

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Comparable EBITDA   2,453     1,903     8,563     7,377  
Adjustments:                
Depreciation and amortization   (681 )   (516 )   (2,350 )   (2,048 )
Interest expense included in comparable earnings   (603 )   (541 )   (2,265 )   (2,068 )
Allowance for funds used during construction   161     140     526     507  
Interest income and other included in comparable earnings   11     56     177     159  
Income tax expense included in comparable earnings   (268 )   (234 )   (693 )   (839 )
Net income attributable to non-controlling interests included in comparable earnings   (86 )   (49 )   (315 )   (238 )
Preferred share dividends   (41 )   (40 )   (163 )   (160 )
Comparable earnings   946     719     3,480     2,690  


Comparable EBITDA and comparable earnings – 2018 versus 2017

Comparable EBITDA increased by $550 million for the three months ended December 31, 2018 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 as a result of higher rates 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 increased by $227 million or $0.21 per common share for the three months ended December 31, 2018 compared to the same period in 2017 and was primarily the net effect of:

  • 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 earnings per common share for the three months ended December 31, 2018 also reflect the dilutive impact of common shares issued in 2017 and 2018 under our DRP and our Corporate ATM program.

2018 FERC Actions and U.S. Tax Reform

In fourth quarter 2018, the following significant developments with respect to 2018 FERC Actions and U.S. Tax Reform took place:

  • On November 15, 2018, FERC issued a Policy Statement on the Accounting and Ratemaking Treatment of Accumulated Deferred Income Taxes (ADIT) and Treatment Following the Sale or Retirement of an Asset, a policy statement (Excess ADIT Policy Statement) addressing certain issues raised in the Notice of Inquiry (NOI) issued on March 15, 2018. The Excess ADIT Policy Statement clarifies FERC accounts in which pipelines should record amortization of excess and/or deficient ADIT for FERC reporting and ratemaking purposes. The Excess ADIT Policy Statement also addresses how to disclose reversals of ADIT account balances in FERC’s annual financial report filings
  • In accordance with the Form 501-G filings and settlements reached with customers in response to the 2018 FERC Actions, the ADIT balances for all pipelines held wholly or in part by TC PipeLines, LP were eliminated from their respective rate bases. Therefore, regulatory liabilities recorded for these assets pursuant to U.S. Tax Reform were written off, resulting in a deferred income tax recovery of $115 million in fourth quarter 2018
  • All of our FERC-regulated natural gas pipelines and storage assets have now either filed a Form 501-G or an uncontested rate settlement with FERC as directed. There has been no significant incremental impact from our third quarter 2018 disclosures regarding the effect of 2018 FERC Actions on future earnings and cash flows
  • Upon finalizing the 2017 annual tax returns for our U.S. businesses and clarifying the impact of U.S. Tax Reform on our deferred income tax liability at December 31, 2017, and as permitted by the SEC during the one-year measurement period, it was determined that an adjustment was required to the estimate originally recorded. Accordingly, a deferred income tax recovery of $52 million was recognized in fourth quarter 2018 to adjust our net regulatory liability and ADIT balances.

Capital Program

We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flows.

Our $57 billion capital program consists of approximately $36.6 billion of secured projects and approximately $20.7 billion of projects under development. Our secured projects include commercially supported, committed projects that are either under construction or are in or preparing to commence the permitting stage, but are not yet fully approved. Our projects under development are commercially supported except where noted, but have greater uncertainty with respect to timing and estimated project costs and are subject to certain approvals.

Three years of maintenance capital expenditures for our businesses are included in the secured projects table. Maintenance capital expenditures on our regulated Canadian and U.S. natural gas pipeline businesses are added to rate base on which we have the opportunity to earn a return and recover these expenditures through current or future tolls, which is similar to our capacity capital projects on these pipelines. Tolling arrangements in our liquids pipelines business provide for the recovery of maintenance capital expenditures.

All projects are subject to cost adjustments due to weather, market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits, among other factors. Amounts presented in the following tables exclude capitalized interest and AFUDC.

Secured projects

    Expected
in-service date
  Estimated
project cost1
  Carrying value at
December 31, 2018
(billions of $)
             
Canadian Natural Gas Pipelines            
Canadian Mainline   2019-2021   0.3      
NGTL System   2019   2.8     1.4  
    2020   1.7     0.2  
    2021   2.8      
    2022   1.3      
Coastal GasLink2,3   2023   6.2     0.1  
Regulated maintenance capital expenditures   2019-2021   1.8      
U.S. Natural Gas Pipelines            
Columbia Gas            
Mountaineer XPress   2019   US 3.2     US 2.9  
Modernization II   2019-2020   US 1.1     US 0.5  
Columbia Gulf            
Gulf XPress   2019   US 0.6     US 0.5  
Other capacity capital   2019-2022   US 0.9     US 0.1  
Regulated maintenance capital expenditures   2019-2021   US 2.0      
Mexico Natural Gas Pipelines            
Sur de Texas4   2019   US 1.5     US 1.4  
Villa de Reyes4   2019   US 0.8     US 0.6  
Tula4   2020   US 0.7     US 0.6  
Liquids Pipelines            
White Spruce   2019   0.2     0.1  
Other capacity capital   2020   0.1      
Recoverable maintenance capital expenditures   2019-2021   0.1      
Energy            
Napanee   2019   1.7     1.6  
Bruce Power – life extension5   2019-2023   2.2     0.6  
Other            
Non-recoverable maintenance capital expenditures6   2019-2021   0.7     0.2  
        32.7     10.8  
Foreign exchange impact on secured projects7       3.9     2.4  
Total secured projects (Cdn$)       36.6     13.2  

1 Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets and assets held through TC PipeLines, LP.
2 Represents 100 per cent of required capital prior to potential joint venture partners or project financing.
3 Carrying value is net of fourth quarter 2018 receipts from the LNG Canada participants for the reimbursement of approximately $0.5 billion of pre-FID costs pursuant to project agreements.
4 The CFE has recognized force majeure events for these pipelines and approved the payment of fixed capacity charges in accordance with their respective TSAs. Payments will be recognized as revenue when the pipelines are placed in service.
5 Reflects our proportionate share of the Unit 6 Major Component Replacement program costs, expected to be in service in 2023, and amounts to be invested under the Asset Management program through 2023.
6 Includes non-recoverable maintenance capital expenditures from all segments and is primarily comprised of our proportionate share of maintenance capital expenditures for Bruce Power and other Energy assets.
7 Reflects U.S./Canada foreign exchange rate of 1.36 at December 31, 2018.

Projects under development
The costs provided in the table below reflect the most recent estimates for each project as filed with the various regulatory authorities or as otherwise determined by management.

    Estimated
project cost1
  Carrying value at
December 31, 2018
(billions of $)
         
Canadian Natural Gas Pipelines        
NGTL System – Merrick   1.9      
Liquids Pipelines        
Keystone XL2   US 8.0     US 0.6  
Heartland and TC Terminals3   0.9     0.1  
Grand Rapids Phase II3   0.7      
Keystone Hardisty Terminal3   0.3     0.1  
Energy        
Bruce Power – life extension4   6.0      
    17.8     0.8  
Foreign exchange impact on projects under development5   2.9     0.2  
Total projects under development (Cdn$)   20.7     1.0  

1 Amounts reflect our proportionate share of joint venture costs where applicable.
2 Carrying value reflects amount remaining after impairment charge recorded in 2015, along with additional amounts capitalized from January 1, 2018.
3 Regulatory approvals have been obtained and additional commercial support is being pursued.
4 Reflects our proportionate share of Major Component Replacement program costs for Units 3, 4, 5, 7 and 8, and the remaining Asset Management program costs beyond 2023.
5 Reflects U.S./Canada foreign exchange rate of 1.36 at December 31, 2018.

Canadian Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
NGTL System   313     274     1,197     996  
Canadian Mainline   481     269     1,073     1,043  
Other Canadian pipelines1   24     26     109     105  
Comparable EBITDA   818     569     2,379     2,144  
Depreciation and amortization   (368 )   (236 )   (1,129 )   (908 )
Comparable EBIT and segmented earnings   450     333     1,250     1,236  

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

Canadian Natural Gas Pipelines segmented earnings increased by $117 million for the three months ended December 31, 2018 compared to the same period in 2017 and are equivalent to comparable EBIT.

Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are primarily affected by our approved ROE, our investment base, our level of deemed common equity and incentive earnings. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis.

NET INCOME AND AVERAGE INVESTMENT BASE

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Net Income                
NGTL System   109     91     398     352  
Canadian Mainline   61     50     182     199  
Average investment base                
NGTL System           9,669     8,385  
Canadian Mainline           3,828     4,184  

Net income for the NGTL System increased by $18 million for the three months ended December 31, 2018 compared to the same period in 2017 mainly due to a higher average investment base as a result of continued system expansions and higher OM&A incentive earnings. In June 2018, the NEB approved NGTL’s 2018-2019 Settlement which is effective from January 1, 2018 to December 31, 2019. It includes an ROE of 10.1 per cent on 40 per cent deemed common equity, a mechanism for sharing variances above and below a fixed annual OM&A amount, flow-through treatment of all other costs and an increase in composite depreciation rates from 3.18 per cent to 3.45 per cent.

Net income for the Canadian Mainline increased by $11 million for the three months ended December 31, 2018 compared to the same period in 2017 primarily due to higher incentive earnings. In December 2018, an NEB decision was received for the 2018-2020 Tolls Review (NEB 2018 Decision) and, as such, incentive earnings for the full year of 2018 were recorded in fourth quarter 2018. The NEB 2018 Decision also included an accelerated amortization of the December 31, 2017 LTAA balance and an increase to the composite depreciation rate from 3.2 per cent to 3.9 per cent.

COMPARABLE EBITDA
Comparable EBITDA increased by $249 million for the three months ended December 31, 2018 compared to the same period in 2017 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 flow-through taxes and incentive earnings. The full year impact of higher depreciation, flow-through taxes and incentive earnings as a result of the Canadian Mainline NEB 2018 Decision was reflected in fourth quarter 2018.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $132 million for the three months ended December 31, 2018 compared to the same period in 2017 mainly due to the increase in depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as NGTL System facilities that were placed in service in 2018.

U.S. Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

    three months ended
December 31
  year ended
December 31
(millions of US$, unless noted otherwise)   2018     2017     2018     2017  
                 
Columbia Gas   236     177     873     623  
ANR   138     99     508     400  
TC PipeLines, LP1,2   36     31     138     118  
Midstream   21     23     122     93  
Columbia Gulf   30     21     120     76  
Great Lakes2,3   23     15     97     64  
Other U.S. pipelines1,2,4   18     16     68     80  
Non-controlling interests5   111     93     415     359  
Comparable EBITDA   613     475     2,341     1,813  
Depreciation and amortization   (131 )   (113 )   (511 )   (453 )
Comparable EBIT   482     362     1,830     1,360  
Foreign exchange impact   155     99     541     410  
Comparable EBIT (Cdn$)   637     461     2,371     1,770  
Specific item:                
Bison asset impairment6   (722 )       (722 )    
Tuscarora goodwill impairment6   (79 )       (79 )    
Bison contract terminations6   130         130      
Integration and acquisition related costs – Columbia               (10 )
Segmented (losses)/earnings (Cdn$)   (34 )   461     1,700     1,760  

1 Results reflect our earnings from TC PipeLines, LP’s ownership interests in GTN, Great Lakes, Iroquois, Northern Border, Bison, Portland, North Baja and Tuscarora, as well as general and administrative costs related to TC PipeLines, LP. Results from Northern Border and Iroquois reflect our share of equity income from these investments. TC PipeLines, LP acquired 49.34 per cent of our 50 per cent interest in Iroquois on June 1, 2017. On June 1, 2017, we sold the remaining 11.81 per cent of Portland to TC PipeLines, LP.
2 TC PipeLines, LP periodically conducted at-the-market equity issuances which decreased our ownership in TC PipeLines, LP. Effective March 2018, this program ceased to be utilized. At December 31, 2018 our ownership interest in TC PipeLines, LP was 25.5 per cent compared to 25.7 per cent at December 31, 2017.
3 Represents our 53.6 per cent direct interest in Great Lakes. The remaining 46.4 per cent is held by TC PipeLines, LP.
4 Results reflect earnings from our direct ownership interests in Crossroads, as well as Iroquois and Portland until June 1, 2017, our effective ownership in Millennium and Hardy Storage, and general and administrative and business development costs related to U.S. natural gas pipelines.
5 Results reflect earnings attributable to portions of TC PipeLines, LP, Portland (until June 1, 2017) and Columbia Pipeline Partners LP (CPPL) (until February 17, 2017) that we do not own.
6 These amounts were recorded in TC PipeLines, LP. The pre-tax impact to us is 25.5 per cent of these amounts net of non-controlling interests.

U.S. Natural Gas Pipelines segmented earnings decreased by $495 million for the three months ended December 31, 2018 compared to the same period in 2017.

Segmented earnings for the three months ended December 31, 2018 included:

  • a $722 million non-cash asset impairment charge related to Bison
  • a $79 million non-cash goodwill impairment charge related to Tuscarora
  • $130 million of termination payments received on two of Bison’s transportation contracts which was recorded in Revenues.

The amounts for each of these specified items are pre-tax and before reduction for the 74.5 per cent non-controlling interests in TC PipeLines, LP and have been excluded from our calculation of comparable EBIT. A stronger U.S. dollar in fourth quarter 2018 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same period in 2017.

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$138 million for the three months ended December 31, 2018 compared to the same period in 2017 and was primarily the net effect of:

  • increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service and additional contract sales on ANR and Great Lakes
  • increased earnings due to the amortization of the net regulatory liabilities that were recorded at the end of 2017, partially offset by a reduction in certain rates on Columbia Gas as a result of U.S. Tax Reform.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$18 million for the three months ended December 31, 2018 compared to the same period in 2017 mainly due to new projects placed in service.

Mexico Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

    three months ended
December 31
  year ended
December 31
(millions of US$, unless noted otherwise)   2018     2017     2018     2017  
                 
Topolobampo   44     38     172     157  
Tamazunchale   31     27     127     112  
Mazatlán   20     16     78     65  
Guadalajara   18     17     71     68  
Sur de Texas1   2     (6 )   16     8  
Other       (1 )   4     (11 )
Comparable EBITDA   115     91     468     399  
Depreciation and amortization   (19 )   (18 )   (75 )   (72 )
Comparable EBIT   96     73     393     327  
Foreign exchange impact   32     20     117     99  
Comparable EBIT and segmented earnings (Cdn$)   128     93     510     426  

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

Mexico Natural Gas Pipelines segmented earnings increased by $35 million for the three months ended December 31, 2018 compared to the same period in 2017 and are equivalent to comparable EBIT.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$24 million for the three months ended December 31, 2018 compared to the same period in 2017 primarily due to:

  • higher revenues from operations as a result of changes in timing of revenue recognition
  • 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 interest expense on this inter-affiliate loan is fully offset in Interest income and other in the Corporate segment
  • incremental earnings from a CRE tariff increase.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization remained largely consistent for the three months ended December 31, 2018 compared to the same period in 2017.

Liquids Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Keystone Pipeline System   401     346     1,443     1,283  
Intra-Alberta pipelines   38     29     160     33  
Liquids marketing and other   99     26     246     32  
Comparable EBITDA   538     401     1,849     1,348  
Depreciation and amortization   (87 )   (81 )   (341 )   (309 )
Comparable EBIT   451     320     1,508     1,039  
Specific items:                
Energy East impairment charge       (1,256 )       (1,256 )
Keystone XL asset costs       (11 )       (34 )
  Risk management activities   81     15     71      
Segmented earnings/(losses)   532     (932 )   1,579     (251 )
                 
Comparable EBIT denominated as follows:                
Canadian dollars   92     80     370     255  
U.S. dollars   271     188     876     604  
Foreign exchange impact   88     52     262     180  
    451     320     1,508     1,039  

Liquids Pipelines segmented earnings increased by $1,464 million for the three months ended December 31, 2018 compared to the same period in 2017 and included the following specific items:

  • a $1,256 million pre-tax impairment charge in 2017 for the Energy East pipeline and related projects 
  • $11 million of pre-tax costs in 2017 related to Keystone XL for the maintenance and liquidation of project assets which were expensed pending further advancement of the project
  • unrealized gains from changes in the fair value of derivatives related to our liquids marketing business.

Comparable EBITDA for Liquids Pipelines increased by $137 million for the three months ended December 31, 2018 compared to the same period in 2017 primarily due to:

  • higher contracted and uncontracted volumes on the Keystone Pipeline System
  • higher contribution from liquids marketing activities from improved margins and volumes
  • incremental contributions from intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017
  • lower business development costs as a result of capitalizing Keystone XL expenditures in 2018
  • a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent earnings from our U.S. operations.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $6 million for the three months ended December 31, 2018 compared to the same period in 2017 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar.

Energy
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

    three months ended
December 31
  year ended
December 31
(millions of Canadian $, unless noted otherwise)   2018     2017     2018     2017  
                 
Western and Eastern Power1   99     115     428     444  
Bruce Power1   66     120     311     434  
U.S. Power (US$)2       (8 )       100  
Foreign exchange impact on U.S. Power       (4 )       30  
Natural Gas Storage and other   6     15     27     55  
Business Development3   (4 )   (24 )   (14 )   (33 )
Comparable EBITDA   167     214     752     1,030  
Depreciation and amortization   (27 )   (33 )   (119 )   (151 )
Comparable EBIT   140     181     633     879  
Specific items:                
Gain on sale of Cartier Wind power facilities   170         170      
U.S. Northeast power marketing contracts   (10 )       (5 )    
Net gain on sales of U.S. Northeast power generation assets       15         484  
Gain on sale of Ontario solar assets       127         127  
Risk management activities   15     149     (19 )   62  
Segmented earnings   315     472     779     1,552  

1 Includes our share of equity income from our investments in Portlands Energy and Bruce Power.
2 In second quarter 2017, we completed the sales of our U.S. Northeast power generation assets.
3 Includes a $21 million impairment charge in 2017 related to obsolete equipment.

Energy segmented earnings were $157 million lower in the three months ended December 31, 2018 compared to the same period in 2017 and included the following specific items:

  • a pre-tax gain in 2018 of $170 million related to the sale of our interests in the Cartier Wind power facilities
  • a pre-tax net loss of $10 million related to our U.S. Northeast power marketing contracts. These results have been excluded from Energy’s comparable earnings in 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020
  • a pre-tax gain in 2017 of $127 million related to the sale of our Ontario solar assets
  • a pre-tax net gain of $15 million in 2017 related to the monetization of our U.S. Northeast power generation assets
  • unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks, as noted in the table below.
Risk management activities   three months ended
December 31
  year ended
December 31
(millions of $, pre-tax)   2018     2017     2018     2017  
                 
Canadian Power       6     3     11  
U.S. Power   20     136     (11 )   39  
Natural Gas Storage   (5 )   7     (11 )   12  
Total unrealized gains/(losses) from risk management activities   15     149     (19 )   62  

Comparable EBITDA for Energy decreased by $47 million for the three months ended December 31, 2018 compared to the same period in 2017 primarily due to the net effect of:

  • decreased earnings from Bruce Power primarily due to lower volumes resulting from higher outage days. Additional financial and operating information on Bruce Power is provided below
  • decreased Western and Eastern Power results due to the sales of our Cartier Wind power facilities in October 2018 and our Ontario solar assets in December 2017, partially offset by higher Western Power realized margins on higher generation volumes
  • lower Natural Gas Storage results primarily due to pipeline constraints in the Alberta natural gas market which limited our ability to access our storage facilities and resulted in lower realized natural gas storage price spreads.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization decreased by $6 million for the three months ended December 31, 2018 compared to the same period in 2017 primarily due to the cessation of depreciation on our Cartier Wind power facilities upon classification as held for sale at June 30, 2018.

BRUCE POWER
The following reflects our proportionate share of the components of comparable EBITDA and comparable EBIT.

    three months ended
December 31
  year ended
December 31
(millions of $, unless noted otherwise)     2018       2017       2018       2017  
                 
Equity income included in comparable EBITDA and EBIT comprised of:                
Revenues1     373       414       1,526       1,626  
Operating expenses     (212 )     (208 )     (852 )     (846 )
Depreciation and other     (95 )     (86 )     (363 )     (346 )
Comparable EBITDA and EBIT2     66       120       311       434  
Bruce Power other information                
Plant availability3     83 %     92 %     87 %     90 %
Planned outage days     100       43       280       221  
Unplanned outage days     15       10       92       49  
Sales volumes (GWh)2     5,676       6,275       23,486       24,368  
Realized sales price per MWh4   $68     $67     $67     $67  

1 Net of amounts recorded to reflect operating cost efficiencies shared with the IESO.
2 Represents our 48.3 per cent (2017 – 48.4 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation.
3 The percentage of time the plant was available to generate power, regardless of whether it was running.
4 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.

Planned maintenance on Unit 8 began and was completed in fourth quarter 2018. Planned maintenance on Unit 3 began in fourth quarter 2018 and is scheduled to be completed in first quarter 2019.

Corporate

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the most directly comparable GAAP measure).

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Comparable EBITDA and EBIT   (34 )   (1 )   (59 )   (21 )
Specific items:                
Foreign exchange gain – inter-affiliate loan1   57     64     5     63  
Integration and acquisition related costs – Columbia               (81 )
Segmented earnings/(losses)   23     63     (54 )   (39 )

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

Corporate segmented earnings decreased by $40 million for the three months ended December 31, 2018 compared to the same period in 2017 and included the following specific items:

  • foreign exchange gains 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.

Comparable EBITDA decreased by $33 million for the three months ended December 31, 2018 compared to the same period in 2017, primarily due to increased general and administrative costs.

OTHER INCOME STATEMENT ITEMS
Interest expense

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Interest on long-term debt and junior subordinated notes                
Canadian dollar-denominated   (142 )   (138 )   (549 )   (494 )
U.S. dollar-denominated   (344 )   (315 )   (1,325 )   (1,269 )
Foreign exchange impact   (111 )   (86 )   (394 )   (379 )
    (597 )   (539 )   (2,268 )   (2,142 )
Other interest and amortization expense   (41 )   (25 )   (121 )   (99 )
Capitalized interest   35     23     124     173  
Interest expense included in comparable earnings   (603 )   (541 )   (2,265 )   (2,068 )
Specific Item:                
  Risk management activities               (1 )
Interest expense   (603 )   (541 )   (2,265 )   (2,069 )

Interest expense increased by $62 million for the three months ended December 31, 2018 compared to the same period in 2017 and primarily reflects the net effect of:

  • long-term debt and junior subordinated note issuances in 2018 and 2017, net of maturities
  • higher capitalized interest primarily due to ongoing construction at Napanee and the recommencement of capitalization of Keystone XL costs in 2018, partially offset by the completion of Northern Courier in fourth quarter 2017
  • higher levels of short-term borrowing
  • foreign exchange impact on translation of U.S. dollar-denominated interest.

Allowance for funds used during construction

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Allowance for funds used during construction                
Canadian dollar-denominated   35     25     103     174  
U.S. dollar-denominated   96     91     326     259  
Foreign exchange impact   30     24     97     74  
Allowance for funds used during construction   161     140     526     507  

AFUDC increased by $21 million for the three months ended December 31, 2018 compared to the same period in 2017.

The increase in Canadian dollar-denominated AFUDC is primarily due to higher capital expenditures on the NGTL System.

The increase in U.S. dollar-denominated AFUDC is primarily due to continued investment in Mexico projects and additional investment in and higher AFUDC rates on Columbia Gas growth projects.

Interest income and other

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Interest income and other included in comparable earnings   11     56     177     159  
Specific items:                
Foreign exchange loss – inter-affiliate loan   (57 )   (64 )   (5 )   (63 )
Risk management activities   (169 )   (1 )   (248 )   88  
Interest income and other   (215 )   (9 )   (76 )   184  

Interest income and other decreased by $206 million for the three months ended December 31, 2018 compared to the same period in 2017 and was primarily the net effect of:

  • higher unrealized losses on risk management activities in 2018 compared to 2017, reflecting the strengthening of the U.S. dollar at the end of 2018. These amounts have been excluded from comparable earnings
  • realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income
  • higher interest income combined with a lower foreign exchange loss related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange gain are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. The offsetting currency-related gain and loss amounts are excluded from comparable earnings.

Income tax (expense)/recovery

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Income tax expense included in comparable earnings   (268 )   (234 )   (693 )   (839 )
Specific items:                
MLP regulatory liability write-off   115         115      
U.S. Tax Reform   52     804     52     804  
Bison asset impairment   44         44      
Sales of U.S. Northeast power generation assets   27     49     27     (177 )
Tuscarora goodwill impairment   5         5      
U.S. Northeast power marketing contracts   3         1      
Gain on sale of Cartier Wind power facilities   (27 )       (27 )    
Bison contract terminations   (8 )       (8 )    
Energy East impairment charge       302         302  
Gain on sale of Ontario solar assets       9         9  
Keystone XL asset costs       2         6  
Integration and acquisition related costs – Columbia               22  
Keystone XL income tax recoveries               7  
Risk management activities   19     (62 )   52     (45 )
Income tax (expense)/recovery   (38 )   870     (432 )   89  

Income tax expense included in comparable earnings increased by $34 million for the three months ended December 31, 2018 compared to the same period in 2017. This was primarily due to higher comparable earnings before income taxes and higher flow-through income taxes in Canadian rate-regulated pipelines offset by lower income tax rates as a result of U.S. Tax Reform.

Net loss/(income) attributable to non-controlling interests

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Net income attributable to non-controlling interests included in comparable earnings   (86 )   (49 )   (315 )   (238 )
Specific items:                
Bison impairment   538         538      
Tuscarora goodwill impairment   59         59      
Bison contract terminations   (97 )       (97 )    
Net loss/(income) attributable to non-controlling interests   414     (49 )   185     (238 )

Net loss/(income) attributable to non-controlling interests decreased by $463 million for the three months ended December 31, 2018 compared to the same period in 2017 primarily due to the net effect of:

  • a $538 million charge related to the non-controlling interests portion of a $722 million Bison asset impairment charge recorded by TC PipeLines, LP
  • a $59 million charge related to the non-controlling interests portion of a $79 million Tuscarora goodwill impairment charge recorded by TC PipeLines, LP
  • $97 million in income related to the non-controlling interests portion of Bison contract termination payments of $130 million received from certain customers and recorded by TC PipeLines, LP.

On consolidation, we recorded the non-controlling interests’ 74.5 per cent of these transactions. These items have been excluded in the calculation of comparable earnings.

Net income attributable to non-controlling interests included in comparable earnings increased by $37 million for the three months ended December 31, 2018 compared to the same period in 2017 primarily due to higher earnings in TC PipeLines, LP.

Preferred share dividends

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Preferred share dividends   (41 )   (40 )   (163 )   (160 )

Preferred share dividends remained largely consistent for the three months ended December 31, 2018 compared to the same period in 2017.

Cash Provided by Operating Activities

    three months ended
December 31
  year ended
December 31
(millions of $, except per share amounts)     2018       2017       2018       2017  
                 
Net cash provided by operations     2,039       1,390       6,555       5,230  
(Decrease)/increase in operating working capital     (28 )     49       102       273  
Funds generated from operations     2,011       1,439       6,657       5,503  
Specific items:                
Bison contract terminations     (122 )           (122 )      
Net (gain)/loss on sales of U.S. Northeast power generation assets     (14 )           (14 )     20  
U.S. Northeast power marketing contracts     6             1        
Keystone XL asset costs           11             34  
Integration and acquisition related costs – Columbia                       84  
Comparable funds generated from operations     1,881       1,450       6,522       5,641  
Dividends on preferred shares     (40 )     (39 )     (158 )     (155 )
Distributions to non-controlling interests     (51 )     (68 )     (225 )     (283 )
Non-recoverable maintenance capital expenditures     (63 )     (71 )     (254 )     (240 )
Comparable distributable cash flow     1,727       1,272       5,885       4,963  
Comparable distributable cash flow per common share   $1.89     $1.45     $6.52     $5.69  

COMPARABLE FUNDS GENERATED FROM OPERATIONS
Comparable funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our operations by excluding the timing effects of working capital changes as well as the cash impact of our specific items.

Comparable funds generated from operations increased by $431 million for the three months ended December 31, 2018 compared to the same period in 2017. Approximately half of this increase was the result of reflecting the full year impact of recovering higher depreciation and flow-through taxes as well as the recognition of incentive earnings for the Canadian Mainline in fourth quarter 2018 upon receiving the Canadian Mainline NEB 2018 Decision in December 2018. The remainder of the increase is primarily due to higher comparable earnings (excluding Income from equity investments) adjusted for the cash impact of specific items, and higher distributions from our equity investments, partially offset by higher interest expense.

COMPARABLE DISTRIBUTABLE CASH FLOW
Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation.

The increase in comparable distributable cash flow for the three months ended December 31, 2018 compared to the same period in 2017 reflects higher comparable funds generated from operations, as described above. Comparable distributable cash flow per common share for the three months ended December 31, 2018 also reflects the dilutive impact of common shares issued under the Corporate ATM program and DRP in 2017 and 2018.

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

Reconciliation of non-GAAP measures

    three months ended
December 31
  year ended
December 31
(millions of $)   2018     2017     2018     2017  
                 
Comparable EBITDA                
Canadian Natural Gas Pipelines   818     569     2,379     2,144  
U.S. Natural Gas Pipelines   812     604     3,035     2,357  
Mexico Natural Gas Pipelines   152     116     607     519  
Liquids Pipelines   538     401     1,849     1,348  
Energy   167     214     752     1,030  
Corporate   (34 )   (1 )   (59 )   (21 )
Comparable EBITDA   2,453     1,903     8,563     7,377  
Depreciation and amortization   (681 )   (516 )   (2,350 )   (2,048 )
Comparable EBIT   1,772     1,387     6,213     5,329  
Specific items:                
Bison asset impairment   (722 )       (722 )    
Tuscarora goodwill impairment   (79 )       (79 )    
U.S. Northeast power marketing contracts   (10 )       (5 )    
Gain on sale of Cartier Wind power facilities   170         170      
Bison contract terminations   130         130      
Foreign exchange gain – inter-affiliate loan   57     64     5     63  
Energy East impairment charge       (1,256 )       (1,256 )
Keystone XL asset costs       (11 )       (34 )
Gain on sale of Ontario solar assets       127         127  
Net gain on sales of U.S. Northeast power generation assets       15         484  
Integration and acquisition related costs – Columbia               (91 )
Risk management activities   96     164     52     62  
Segmented earnings   1,414     490     5,764     4,684  

Condensed consolidated statement of income

    three months ended
December 31
  year ended
December 31
(unaudited – millions of Canadian $, except per share amounts)     2018       2017       2018       2017  
                 
Revenues                
Canadian Natural Gas Pipelines     1,266       968       4,038       3,693  
U.S. Natural Gas Pipelines     1,326       900       4,314       3,584  
Mexico Natural Gas Pipelines     159       138       619       570  
Liquids Pipelines     753       599       2,584       2,009  
Energy     400       1,012       2,124       3,593  
      3,904       3,617       13,679       13,449  
Income from Equity Investments     222       246       714       773  
Operating and Other Expenses                
Plant operating costs and other     1,011       944       3,591       3,906  
Commodity purchases resold     249       671       1,488       2,382  
Property taxes     140       127       569       569  
Depreciation and amortization     681       516       2,350       2,055  
Goodwill and other asset impairment charges     801       1,257       801       1,257  
      2,882       3,515       8,799       10,169  
Gain on Sales of Assets     170       142       170       631  
Financial Charges                
Interest expense     603       541       2,265       2,069  
Allowance for funds used during construction     (161 )     (140 )     (526 )     (507 )
Interest income and other     215       9       76       (184 )
      657       410       1,815       1,378  
Income before Income Taxes     757       80       3,949       3,306  
Income Tax Expense/(Recovery)                
Current     146       21       315       149  
Deferred     59       (87 )     284       566  
Deferred – U.S. Tax Reform and 2018 FERC Actions     (167 )     (804 )     (167 )     (804 )
      38       (870 )     432       (89 )
Net Income     719       950       3,517       3,395  
Net (loss)/income attributable to non-controlling interests     (414 )     49       (185 )     238  
Net Income Attributable to Controlling Interests     1,133       901       3,702       3,157  
Preferred share dividends     41       40       163       160  
Net Income Attributable to Common Shares     1,092       861       3,539       2,997  
Net Income per Common Share                
Basic   $1.19     $0.98     $3.92     $3.44  
Diluted   $1.19     $0.98     $3.92     $3.43  
Dividends Declared per Common Share   $0.69     $0.625     $2.76     $2.50  
Weighted Average Number of Common Shares (millions)                
Basic     915       877       902       872  
Diluted     915       879       903       874  

Condensed consolidated statement of cash flows

    three months ended
December 31
  year ended
December 31
(unaudited – millions of Canadian $)   2018     2017     2018     2017  
                 
Cash Generated from Operations                
Net income   719     950     3,517     3,395  
Depreciation and amortization   681     516     2,350     2,055  
Goodwill and other asset impairment charges   801     1,257     801     1,257  
Deferred income taxes   59     (87 )   284     566  
Deferred income taxes – U.S. Tax Reform and 2018 FERC Actions   (167 )   (804 )   (167 )   (804 )
Income from equity investments   (222 )   (246 )   (714 )   (773 )
Distributions received from operating activities of equity investments   224     227     985     970  
Employee post-retirement benefits funding, net of expense   (13 )       (35 )   (64 )
Gain on sale of assets   (170 )   (142 )   (170 )   (631 )
Equity allowance for funds used during construction   (113 )   (113 )   (374 )   (362 )
Unrealized losses/(gains) on financial instruments   100     (163 )   220     (149 )
Other   112     44     (40 )   43  
Decrease/(increase) in operating working capital   28     (49 )   (102 )   (273 )
Net cash provided by operations   2,039     1,390     6,555     5,230  
Investing Activities                
Capital expenditures   (2,944 )   (2,000 )   (9,418 )   (7,383 )
Capital projects in development   (257 )   (11 )   (496 )   (146 )
Contributions to equity investments   (237 )   (541 )   (1,015 )   (1,681 )
Proceeds from sales of assets, net of transaction costs   614     536     614     4,683  
Reimbursement of costs related to capital projects in development   470     634     470     634  
Other distributions from equity investments           121     362  
Deferred amounts and other   (373 )   (81 )   (295 )   (168 )
Net cash used in investing activities   (2,727 )   (1,463 )   (10,019 )   (3,699 )
Financing Activities                
Notes payable (repaid)/issued, net   (1,089 )   (194 )   817     1,038  
Long-term debt issued, net of issue costs   1,879     1,675     6,238     3,643  
Long-term debt repaid   (284 )   (1,570 )   (3,550 )   (7,085 )
Junior subordinated notes issued, net of issue costs               3,468  
Dividends on common shares   (417 )   (357 )   (1,571 )   (1,339 )
Dividends on preferred shares   (40 )   (39 )   (158 )   (155 )
Distributions to non-controlling interests   (51 )   (68 )   (225 )   (283 )
Common shares issued, net of issue costs   9     232     1,148     274  
Partnership units of TC PipeLines, LP issued, net of issue costs       63     49     225  
Common units of Columbia Pipeline Partners LP acquired               (1,205 )
Net cash provided by/(used in) financing activities   7     (258 )   2,748     (1,419 )
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents   26     (4 )   73     (39 )
(Decrease)/increase in Cash and Cash Equivalents   (655 )   (335 )   (643 )   73  
Cash and Cash Equivalents                
Beginning of period   1,101     1,424     1,089     1,016  
Cash and Cash Equivalents                
End of period   446     1,089     446     1,089  

Condensed consolidated balance sheet

    December 31,     December 31,  
(unaudited – millions of Canadian $)     2018     2017  
         
ASSETS        
Current Assets        
Cash and cash equivalents   446     1,089  
Accounts receivable   2,535     2,522  
Inventories   431     378  
Assets held for sale   543      
Other   1,180     691  
    5,135     4,680  
Plant, Property and Equipment net of accumulated depreciation of $25,834 and $23,734, respectively   66,503     57,277  
Equity Investments   7,113     6,366  
Regulatory Assets   1,548     1,376  
Goodwill   14,178     13,084  
Loan Receivable from Affiliate   1,315     919  
Intangible and Other Assets   1,921     1,484  
Restricted Investments   1,207     915  
    98,920     86,101  
LIABILITIES        
Current Liabilities        
Notes payable   2,762     1,763  
Accounts payable and other   5,408     4,057  
Dividends payable   668     586  
Accrued interest   646     605  
Current portion of long-term debt   3,462     2,866  
    12,946     9,877  
Regulatory Liabilities   3,930     4,321  
Other Long-Term Liabilities   1,008     727  
Deferred Income Tax Liabilities   6,026     5,403  
Long-Term Debt   36,509     31,875  
Junior Subordinated Notes   7,508     7,007  
    67,927     59,210  
EQUITY        
Common shares, no par value   23,174     21,167  
Issued and outstanding: December 31, 2018 – 918 million shares        
  December 31, 2017 – 881 million shares        
Preferred shares   3,980     3,980  
Additional paid-in capital   17      
Retained earnings   2,773     1,623  
Accumulated other comprehensive loss   (606 )   (1,731 )
Controlling Interests   29,338     25,039  
Non-controlling interests   1,655     1,852  
    30,993     26,891  
    98,920     86,101  

Segmented information

three months ended
December 31, 2018
  Canadian
Natural
Gas
Pipelines
    U.S.
Natural
Gas
Pipelines
    Mexico
Natural
Gas
Pipelines
    Liquids
Pipelines
             
(unaudited – millions of Canadian $)                   Energy     Corporate1     Total  
                             
Revenues   1,266     1,326     159     753     400         3,904  
Intersegment revenues       41             6     (47 ) 2  
    1,266     1,367     159     753     406     (47 )   3,904  
Income from equity investments   3     68     2     14     78     57   3 222  
Plant operating costs and other   (385 )   (443 )   (9 )   (124 )   (63 )   13   2 (1,011 )
Commodity purchases resold                   (249 )       (249 )
Property taxes   (66 )   (50 )       (24 )           (140 )
Depreciation and amortization   (368 )   (175 )   (24 )   (87 )   (27 )       (681 )
Goodwill and other asset impairment charges       (801 )                   (801 )
Gain on sale of assets                   170         170  
Segmented earnings/(losses)   450     (34 )   128     532     315     23     1,414  
Interest expense   (603 )
Allowance for funds used during construction   161  
Interest income and other3   (215 )
Income before income taxes   757  
Income tax expense   (38 )
Net income   719  
Net loss attributable to non-controlling interests   414  
Net income attributable to controlling interests   1,133  
Preferred share dividends   (41 )
Net income attributable to common shares   1,092  

1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
3 Income from equity investments includes foreign exchange gains on the Company’s inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company’s proportionate share of long-term debt financing for this joint venture.

three months ended
December 31, 2017
  Canadian
Natural
Gas
Pipelines
    U.S.
Natural
Gas
Pipelines
    Mexico
Natural
Gas
Pipelines
    Liquids
Pipelines
             
(unaudited – millions of Canadian $)                   Energy     Corporate1     Total  
                             
Revenues   968     900     138     599     1,012         3,617  
Intersegment revenues       20                 (20 ) 2  
    968     920     138     599     1,012     (20 )   3,617  
Income/(loss) from equity investments   2     65     (9 )   (6 )   130     64   3 246  
Plant operating costs and other   (342 )   (336 )   (13 )   (186 )   (86 )   19   2 (944 )
Commodity purchases resold                   (671 )       (671 )
Property taxes   (59 )   (45 )       (22 )   (1 )       (127 )
Depreciation and amortization   (236 )   (143 )   (23 )   (81 )   (33 )       (516 )
Goodwill and other asset impairment charges               (1,236 )   (21 )       (1,257 )
Gain on sale of assets                   142         142  
Segmented earnings/(losses)   333     461     93     (932 )   472     63     490  
Interest expense   (541 )
Allowance for funds used during construction   140  
Interest income and other3   (9 )
Income before income taxes   80  
Income tax recovery   870  
Net income   950  
Net income attributable to non-controlling interests   (49 )
Net income attributable to controlling interests   901  
Preferred share dividends   (40 )
Net income attributable to common shares   861  

1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
3 Income/(loss) from equity investments includes foreign exchange gains on the Company’s inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company’s proportionate share of long-term debt financing for this joint venture.

year ended
December 31, 2018
  Canadian
Natural
Gas
Pipelines
    U.S.
Natural
Gas
Pipelines
    Mexico
Natural Gas
Pipelines
    Liquids
Pipelines
             
(unaudited – millions of Canadian $)                   Energy     Corporate1     Total  
                             
Revenues   4,038     4,314     619     2,584     2,124         13,679  
Intersegment revenues       162             56     (218 ) 2  
    4,038     4,476     619     2,584     2,180     (218 )   13,679  
Income from equity investments   12     256     22     64     355     5   3 714  
Plant operating costs and other   (1,405 )   (1,368 )   (34 )   (630 )   (313 )   159   2 (3,591 )
Commodity purchases resold                   (1,488 )       (1,488 )
Property taxes   (266 )   (199 )       (98 )   (6 )       (569 )
Depreciation and amortization   (1,129 )   (664 )   (97 )   (341 )   (119 )       (2,350 )
Goodwill and other asset impairment charges       (801 )                   (801 )
Gain on sale of assets                   170         170  
Segmented earnings/(losses)   1,250     1,700     510     1,579     779     (54 )   5,764  
Interest expense   (2,265 )
Allowance for funds used during construction   526  
Interest income and other3   (76 )
Income before income taxes   3,949  
Income tax expense   (432 )
Net income   3,517  
Net loss attributable to non-controlling interests   185  
Net income attributable to controlling interests   3,702  
Preferred share dividends   (163 )
Net income attributable to common shares   3,539  

1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
3 Income from equity investments includes foreign exchange gains on the Company’s inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company’s proportionate share of long-term debt financing for this joint venture.

year ended
December 31, 2017
  Canadian
Natural
Gas
Pipelines
    U.S.
Natural
Gas
Pipelines
    Mexico
Natural Gas
Pipelines
    Liquids
Pipelines
             
(unaudited – millions of Canadian $)                   Energy     Corporate1     Total  
                             
Revenues   3,693     3,584     570     2,009     3,593         13,449  
Intersegment revenues       51                 (51 ) 2  
    3,693     3,635     570     2,009     3,593     (51 )   13,449  
Income/(loss) from equity investments   11     240     (9 )   (3 )   471     63   3 773  
Plant operating costs and other   (1,300 )   (1,340 )   (42 )   (623 )   (550 )   (51 ) 2 (3,906 )
Commodity purchases resold                   (2,382 )       (2,382 )
Property taxes   (260 )   (181 )       (89 )   (39 )       (569 )
Depreciation and amortization   (908 )   (594 )   (93 )   (309 )   (151 )       (2,055 )
Goodwill and other asset impairment charges               (1,236 )   (21 )       (1,257 )
Gain on sale of assets                   631         631  
Segmented earnings/(losses)   1,236     1,760     426     (251 )   1,552     (39 )   4,684  
Interest expense   (2,069 )
Allowance for funds used during construction   507  
Interest income and other3   184  
Income before income taxes   3,306  
Income tax recovery   89  
Net income   3,395  
Net income attributable to non-controlling interests   (238 )
Net income attributable to controlling interests   3,157  
Preferred share dividends   (160 )
Net income attributable to common shares   2,997  

1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
3 Income/(loss) from equity investments includes foreign exchange gains on the Company’s inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company’s proportionate share of long-term debt financing for this joint venture.

TOTAL ASSETS BY SEGMENT

(unaudited – millions of Canadian $)   December 31, 2018     December 31, 2017  
         
Canadian Natural Gas Pipelines   18,407     16,904  
U.S. Natural Gas Pipelines   44,115     35,898  
Mexico Natural Gas Pipelines   7,058     5,716  
Liquids Pipelines   17,352     15,438  
Energy   8,475     8,503  
Corporate   3,513     3,642  
    98,920     86,101  

 

Recommended