U.S. Markets closed

TransCanada Reports Record First Quarter Financial Results

Declares Quarterly Dividend of $0.75 per Common Share

CALGARY, Alberta, May 03, 2019 (GLOBE NEWSWIRE) -- TransCanada Corporation (TSX, NYSE: TRP) (TransCanada or the Company) today announced net income attributable to common shares for first quarter 2019 of $1.004 billion or $1.09 per share compared to net income of $734 million or $0.83 per share for the same period in 2018. Comparable earnings for first quarter 2019 were $987 million or $1.07 per common share compared to $864 million or $0.98 per common share for the same period in 2018. TransCanada's Board of Directors also declared a quarterly dividend of $0.75 per common share for the quarter ending June 30, 2019, equivalent to $3.00 per common share on an annualized basis.

"We are very pleased with the performance of our diversified and irreplaceable portfolio of high-quality, long-life energy infrastructure assets which continued to produce record financial results through the first quarter of 2019,” said Russ Girling, TransCanada’s president and chief executive officer. “Comparable earnings per share increased nine per cent compared to the same period last year while comparable funds generated from operations of $1.8 billion were eleven per cent higher. The increases reflect the strong performance of our legacy assets along with contributions from approximately $5.3 billion of growth projects that were placed into service in first quarter 2019."

"With the demand for our existing assets driving historically high utilization rates and $30 billion of secured growth projects underway, approximately $7 billion of which are expected to be completed by the end of the year, earnings and cash flow are forecast to continue to rise. These projects are supported by regulated or long-term contracted business models that are expected to support annual dividend growth of eight to ten per cent through 2021,” added Girling. “We have invested $10 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 and access to capital markets. We also continue to progress various portfolio management activities, including the 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, including debt-to-EBITDA in the high four times area, in 2019 and thereafter and deliver ongoing growth as measured on a per-share basis."

"Looking ahead, we continue to methodically advance more than $20 billion of projects under development including Keystone XL and the Bruce Power life extension program. Success in progressing these and other growth initiatives that are expected to emanate from our 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)

  • First quarter 2019 financial results
    • Net income attributable to common shares of $1.004 billion or $1.09 per common share
    • Comparable earnings of $987 million or $1.07 per common share
    • Comparable earnings before interest, taxes, depreciation and amortization of $2.4 billion
    • Net cash provided by operations of $1.9 billion
    • Comparable funds generated from operations of $1.8 billion
    • Comparable distributable cash flow of $1.6 billion or $1.76 per common share
  • Declared a quarterly dividend of $0.75 per common share for the quarter ending June 30, 2019
  • Placed approximately $5.3 billion of projects in service including Mountaineer XPress, Gulf XPress and certain NGTL System expansions
  • Continued pre-construction activities on Coastal GasLink pipeline project
  • Received new Presidential Permit for Keystone XL
  • Completed commissioning on White Spruce pipeline
  • Issued $1.0 billion of 30-year fixed-rate medium-term notes in April 2019.

Net income attributable to common shares increased by $270 million or $0.26 per common share to $1.004 billion or $1.09 per share for the three months ended March 31, 2019 compared to the same period last year. Per share results reflect the dilutive impact of common shares issued under our DRP in 2018 and 2019 and our Corporate ATM program in 2018. First quarter 2019 and 2018 results included an after-tax loss of $12 million and an after-tax gain of $6 million, respectively, related to our U.S. Northeast power marketing contracts. These specific items, as well as unrealized gains and losses from changes in risk management activities, are excluded from comparable earnings.

Comparable EBITDA increased by $320 million for the three months ended March 31, 2019 compared to the same period in 2018 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
  • higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities
  • higher contribution from Canadian Natural Gas Pipelines mainly due to the recovery of increased depreciation in 2019 as a result of higher rates approved in both the Canadian Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement and higher incentive earnings for the Canadian Mainline
  • lower contribution from Power and Storage primarily due to the sale of our interests in the Cartier Wind power facilities in 2018 and costs related to Napanee's delayed in-service
  • foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. operations.

Comparable earnings increased by $123 million or $0.09 per common share for the three months ended March 31, 2019 compared to the same period in 2018 and was primarily the net effect of:

  • changes in comparable EBITDA described above
  • higher depreciation largely in Canadian Natural Gas Pipelines, which is fully recovered in tolls as reflected in the increase in comparable EBITDA described above, therefore having no impact on comparable earnings. In addition, higher depreciation reflects new projects placed in service
  • higher interest expense primarily as a result of long-term debt issuances, net of maturities, and the foreign exchange impact on translation of U.S. dollar-denominated interest
  • higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials
  • lower interest income and other due to realized losses in 2019 compared to realized gains in 2018 on derivatives used to manage exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income
  • higher AFUDC due to increased capital expenditures for our NGTL System and Mexico projects.

Comparable earnings per common share for the three months ended March 31, 2019 also reflects the dilutive impact of common shares issued under our DRP in 2018 and 2019 and our Corporate ATM program in 2018.

Notable recent developments include:

Canadian Natural Gas Pipelines:

  • Coastal GasLink Pipeline Project: Following the October 2018 positive Final Investment Decision (FID) by LNG Canada, pre-construction activities continue at many locations along the pipeline route.

    The NEB process considering regulatory jurisdiction continues with all evidence now submitted. A final hearing is scheduled for second quarter 2019 with a decision expected in third quarter 2019.

    TransCanada continues to advance funding plans for the $6.2 billion pipeline project through a combination of the sale of up to 75 per cent ownership interest and potential project financing.
  • NGTL System: In first quarter 2019, we placed approximately $250 million of projects in service which included the Gordondale Lateral Loop and the Boundary Lake North projects.

    On March 14, 2019, we filed the NGTL System Rate Design and Services Application with the NEB which includes a settlement agreement negotiated between NGTL and members of its Tolls, Tariff, Facilities and Procedures (TTFP) committee, which represents stakeholders. The settlement is supported by a majority of members of the TTFP committee. The Application addresses rate design, terms and conditions of service for the NGTL System and a tolling methodology for the North Montney Mainline. Given the complexity of the issues raised in the Application, the NEB decided to hold a public hearing. Application to participate and comments on the Application were due April 12, 2019 and reply comments were submitted by NGTL on April 18, 2019.

U.S. Natural Gas Pipelines:

  • Mountaineer XPress and Gulf XPress: The Mountaineer XPress project, a Columbia Gas project designed to transport supply from the Marcellus and Utica shale plays to points along the system and the Leach interconnect with Columbia Gulf, was phased into service over first quarter 2019 along with Gulf XPress, a Columbia Gulf project.

  • Grand Chenier XPress: In February 2019, we approved the Grand Chenier XPress project, an ANR Pipeline project which will connect supply directly to Gulf Coast LNG export markets through the addition of a mid-point compressor station and incremental compression capability at existing facilities. Subject to a positive customer FID, the anticipated in-service dates are in 2021 and 2022 for Phase I and II, respectively, with estimated project costs of US$0.2 billion.

Mexico Natural Gas Pipelines:

  • Sur de Texas: The Sur de Texas project has experienced force majeure events that have delayed in-service. Some events are subject to potential dispute and we have taken measures to protect our interests under the contract. Construction and commissioning activities are progressing such that we anticipate mechanical completion in May with an expected June 2019 in-service.

  • Villa de Reyes and Tula: Construction of the Villa de Reyes project is ongoing with a phased in-service anticipated to commence in the second half of 2019. Commencement of construction of the central segment of the Tula project has been delayed due to a lack of progress by the Secretary of Energy, the governmental department responsible for Indigenous consultations. Project completion has been revised to the end of 2020. We have negotiated separate CFE contracts that would allow certain segments of Tula and Villa de Reyes to be placed in service when facilities are complete and gas is available.

Liquids Pipelines:

  • Keystone Pipeline System: In January 2019, we entered into an agreement with Motiva Enterprises LLC (Motiva) to construct a pipeline connection between the Keystone Pipeline system and Motiva’s 630,000 Bbl/d refinery in Port Arthur, Texas. The connection is targeted to be operational in second quarter 2020.

  • Keystone XL: A decision from the Nebraska Supreme Court on the appeal of the Nebraska Public Service Commission route approval remains pending. We expect the decision to be issued in second quarter 2019.

    In September 2018, two U.S. Native American communities filed a lawsuit in Montana challenging the Keystone XL Presidential Permit. We, along with the U.S. Government, have filed to have the lawsuit dismissed. In December 2018, we applied to the U.S. District Court in Montana for a stay of its various decisions affecting the issuance of the 2017 Keystone XL Presidential Permit and the extensive environmental assessments made in support of its issuance. The stay application was denied by the U.S. District Court in February 2019. In February 2019, we applied to the Ninth Circuit Court of Appeals (Ninth Circuit) for a stay of the U.S. District Court decisions. On March 16, 2019, the Ninth Circuit denied our stay application and declined to further limit the scope of the preliminary injunction which prevents us from conducting certain pre-construction activities.

    On March 29, 2019, U.S. President Trump issued a new Presidential Permit for the Keystone XL Project, which superseded the 2017 permit. Subsequently, we filed a motion with the Ninth Circuit requesting the court vacate the U.S. District Court decisions, dissolve the injunctions, and direct the U.S. District Court to dismiss the pending cases. A lawsuit was filed challenging the validity of the new Presidential Permit. We are not named in the lawsuit.

  • White Spruce: Commissioning has been completed on the White Spruce pipeline, which transports crude oil from Canadian Natural Resources Limited's Horizon facility in northeast Alberta to the Grand Rapids pipeline with commercial in-service achieved in May 2019.

Power and Storage (previously Energy):

  • Napanee: In March 2019, we experienced an equipment failure while progressing commissioning activities at our 900 MW natural gas-fired power plant in Napanee, Ontario. We continue to expect that our total investment in the Napanee facility will be approximately $1.7 billion, however, commencement of commercial operations will be delayed into the second half of 2019 as we repair the damaged equipment.

  • Coolidge Generating Station: In December 2018, we entered into an agreement to sell our Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC (SWG). Salt River Project Agriculture Improvement and Power District (SRP), the PPA counterparty, subsequently exercised its contractual right of first refusal on a sale to a third party. On March 20, 2019, we terminated the agreement with SWG after entering into an agreement with SRP to sell the Coolidge generating station for approximately US$465 million, subject to timing of the close and related adjustments. The sale will result in an estimated gain of approximately $70 million ($55 million after tax) to be recognized upon closing, which is expected to occur in mid-2019.

Corporate:

  • Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.75 per common share for the quarter ending June 30, 2019 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $3.00 per common share on an annualized basis.

  • Issuance of Long-term Debt: In April 2019, TCPL issued $1.0 billion of Medium Term Notes due in October 2049 bearing interest at a fixed rate of 4.34 per cent. The net proceeds of this debt issuance were used for general corporate purposes and to fund our capital program.

    In first quarter 2019, TCPL repaid $100 million of Debentures bearing interest at a fixed rate of 10.50 per cent, US$750 million of Senior Unsecured Notes bearing interest at a fixed rate of 7.125 per cent and US$400 million of Senior Unsecured Notes bearing interest at a fixed rate of 3.125 per cent.
  • Dividend Reinvestment Plan: In first quarter 2019, the DRP participation rate amongst common shareholders was approximately 33 per cent, resulting in $226 million reinvested in common equity under the program.

Teleconference and Webcast:

We will hold a teleconference and webcast on Friday, May 3, 2019 to discuss our first quarter 2019 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 executive leadership team, will discuss the financial results and Company developments at 1 p.m. (MT) / 3 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: http://www.gowebcasting.com/9939

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (ET) on May 10, 2019. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 7151952#.

The unaudited interim Condensed 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 our 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. We operate 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, we currently own or have interests in more than 6,600 megawatts of power generation in Canada and the United States. We are also the developer and operator of one of North America's leading liquids pipeline systems that extends approximately 4,900 kilometres (3,000 miles), connecting growing continental oil supplies to key markets and refineries. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. Visit TransCanada.com to learn more, or connect with us on social media.

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 May 2, 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 and are adjusted for specific items in each period, as applicable except as otherwise described in the Condensed consolidated financial statements and MD&A. For more information on non-GAAP measures, refer to TransCanada's Quarterly Report to Shareholders dated May 2, 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


Quarterly report to shareholders

First quarter 2019

Financial highlights

  three months ended
March 31
(millions of $, except per share amounts)   2019       2018  
       
Income      
Revenues   3,487       3,424  
Net income attributable to common shares   1,004       734  
per common share – basic and diluted $1.09     $0.83  
Comparable EBITDA1   2,383       2,063  
Comparable earnings1   987       864  
per common share1 $1.07     $0.98  
       
Cash flows      
Net cash provided by operations   1,949       1,412  
Comparable funds generated from operations1   1,791       1,611  
Comparable distributable cash flow1   1,623       1,439  
per common share1 $1.76     $1.63  
Capital spending2   2,331       2,096  
       
Dividends declared      
Per common share $0.75     $0.69  
Basic common shares outstanding (millions)      
– weighted average for the period   921       885  
– issued and outstanding at end of period   924       891  

1 Comparable EBITDA, comparable earnings, comparable earnings per common share, comparable funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share are all non-GAAP measures. Refer to the Non-GAAP measures section for more information.
2 Includes capital expenditures, capital projects in development and contributions to equity investments.

Management’s discussion and analysis

May 2, 2019

This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three months ended March 31, 2019, and should be read with the accompanying unaudited Condensed consolidated financial statements for the three months ended March 31, 2019, which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2018 audited Consolidated financial statements and notes and the MD&A in our 2018 Annual Report. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in our 2018 Annual Report. Certain comparative figures have been adjusted to reflect the current period’s presentation.

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 MD&A 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 access to and cost of capital
  • 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
  • expected outcomes with respect to legal proceedings, including arbitration and insurance claims
  • expected impact of future tax and 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 MD&A.

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

Assumptions

  • regulatory decisions and outcomes
  • planned and unplanned outages and the use of our pipeline, power and storage 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, power and storage assets
  • amount of capacity sold and rates achieved in our pipeline businesses
  • the amount of capacity payments and revenues from our power generation assets 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, power and storage 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 and others in this MD&A and 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 find more information about TransCanada in our Annual Information Form and other disclosure documents, which are available on SEDAR (www.sedar.com).

NON-GAAP MEASURES
This MD&A 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
  • 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 against their most directly comparable GAAP measures.

Comparable 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.

Comparable earnings and comparable earnings per common share
Comparable earnings represents earnings or loss 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 Consolidated results section for reconciliations to net income attributable to common shares and net income per common share.

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. Refer to the Financial condition 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.

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. As such, 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.

Refer to the Financial condition section for a reconciliation to net cash provided by operations.

Consolidated results – first quarter 2019

As of first quarter 2019, the previously disclosed Energy segment has been renamed the Power and Storage segment.

    three months ended
March 31
(millions of $, except per share amounts)     2019       2018  
         
Canadian Natural Gas Pipelines     269       253  
U.S. Natural Gas Pipelines     792       648  
Mexico Natural Gas Pipelines     116       137  
Liquids Pipelines     460       341  
Power and Storage     48       50  
Corporate     (19 )     (81 )
Total segmented earnings     1,666       1,348  
Interest expense     (586 )     (527 )
Allowance for funds used during construction     139       105  
Interest income and other     163       63  
Income before income taxes     1,382       989  
Income tax expense     (236 )     (121 )
Net income     1,146       868  
Net income attributable to non-controlling interests     (101 )     (94 )
Net income attributable to controlling interests     1,045       774  
Preferred share dividends     (41 )     (40 )
Net income attributable to common shares     1,004       734  
Net income per common share – basic and diluted   $1.09     $0.83  

Net income attributable to common shares increased by $270 million, or $0.26 per common share, for the three months ended March 31, 2019 compared to the same period in 2018. Net income per common share reflects the dilutive impact of common shares issued under our DRP in 2018 and 2019 and our Corporate ATM program in 2018.

Net income included unrealized gains and losses from changes in risk management activities which we exclude along with other specific items as noted below to arrive at comparable earnings. Results included an after-tax loss of $12 million and an after-tax gain of $6 million for the three months ended March 31, 2019 and 2018, respectively, related to our U.S. Northeast power marketing contracts. These amounts have been excluded from Power and Storage's comparable earnings as we do not consider the wind-down and sales of the remaining contracts part of our underlying operations.

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
March 31
(millions of $, except per share amounts)   2019     2018  
         
Net income attributable to common shares   1,004     734  
Specific items (net of tax):        
U.S. Northeast power marketing contracts   12     (6 )
Risk management activities1   (29 )   136  
Comparable earnings   987     864  
Net income per common share   $1.09     $0.83  
Specific items (net of tax):        
U.S. Northeast power marketing contracts   0.01      
Risk management activities   (0.03 )   0.15  
Comparable earnings per common share   $1.07     $0.98  


1   Risk management activities   three months ended
March 31
    (millions of $)   2019   2018
             
    Canadian Power   (1 )   2  
    U.S. Power   (60 )   (101 )
    Liquids marketing   (15 )   (7 )
    Natural Gas Storage   (3 )   (3 )
    Foreign exchange   120     (79 )
    Income tax attributable to risk management activities   (12 )   52  
    Total unrealized gains/(losses) from risk management activities   29     (136 )

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
March 31
(millions of $)   2019     2018  
         
Comparable EBITDA        
Canadian Natural Gas Pipelines   556     494  
U.S. Natural Gas Pipelines   972     804  
Mexico Natural Gas Pipelines   146     160  
Liquids Pipelines   563     431  
Power and Storage   151     176  
Corporate   (5 )   (2 )
Comparable EBITDA   2,383     2,063  
Depreciation and amortization   (608 )   (535 )
Interest expense   (586 )   (527 )
Allowance for funds used during construction   139     105  
Interest income and other included in comparable earnings   29     63  
Income tax expense included in comparable earnings   (228 )   (171 )
Net income attributable to non-controlling interests   (101 )   (94 )
Preferred share dividends   (41 )   (40 )
Comparable earnings   987     864  

Comparable EBITDA and comparable earnings – 2019 versus 2018

Comparable EBITDA increased by $320 million for the three months ended March 31, 2019 compared to the same period in 2018 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
  • higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System and increased earnings from liquids marketing activities
  • higher contribution from Canadian Natural Gas Pipelines mainly due to the recovery of increased depreciation in 2019 as a result of higher rates approved in both the Canadian Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement and higher incentive earnings for the Canadian Mainline
  • lower contribution from Power and Storage primarily due to the sale of our interests in the Cartier Wind power facilities in 2018 and costs related to Napanee's delayed in-service
  • foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. operations.

Comparable earnings increased by $123 million or $0.09 per common share for the three months ended March 31, 2019 compared to the same period in 2018 and was primarily the net effect of:

  • changes in comparable EBITDA described above
  • higher depreciation largely in Canadian Natural Gas Pipelines, which is fully recovered in tolls as reflected in the increase in comparable EBITDA described above, therefore having no impact on comparable earnings. In addition, higher depreciation reflects new projects placed in service
  • higher interest expense primarily as a result of long-term debt issuances, net of maturities, and the foreign exchange impact on translation of U.S. dollar-denominated interest
  • higher income tax expense due to higher comparable earnings before income taxes and lower foreign tax rate differentials
  • lower interest income and other due to realized losses in 2019 compared to realized gains in 2018 on derivatives used to manage exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income
  • higher AFUDC due to increased capital expenditures for our NGTL System and Mexico projects.

Comparable earnings per common share for the three months ended March 31, 2019 also reflects the dilutive impact of common shares issued under our DRP in 2018 and 2019 and our Corporate ATM program in 2018.

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 capital program consists of approximately $30.3 billion of secured projects which 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. An additional $21.5 billion of 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. During first quarter 2019, we placed approximately $5.3 billion of projects in service including Mountaineer XPress, Gulf XPress, and certain NGTL System expansions.

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 pipelines 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 March 31, 2019  
(billions of $)
             
Canadian Natural Gas Pipelines            
Canadian Mainline   2019-2022   0.3     0.1  
NGTL System   2019   2.8     2.0  
    2020   1.8     0.3  
    2021   2.6      
    2022+   1.4      
Coastal GasLink2,3   2023   6.2     0.2  
Regulated maintenance capital expenditures   2019-2021   1.6     0.2  
U.S. Natural Gas Pipelines            
Columbia Gas            
Modernization II   2019-2020   US 1.1     US 0.5  
Other capacity capital   2019-2021   US 0.5      
Regulated maintenance capital expenditures   2019-2021   US 1.8     US 0.1  
Mexico Natural Gas Pipelines            
Sur de Texas4   2019   US 1.5     US 1.4  
Villa de Reyes4   2019-2020   US 0.8     US 0.7  
Tula4   2020   US 0.7     US 0.6  
Liquids Pipelines            
White Spruce   2019   0.2     0.2  
Other capacity capital   2020   0.1      
Recoverable maintenance capital expenditures   2019-2021   0.1      
Power and Storage            
Napanee   2019   1.7     1.7  
Bruce Power – life extension5   2019-2023   2.2     0.7  
Other            
Non-recoverable maintenance capital expenditures6   2019-2021   0.7     0.1  
        28.1     8.8  
Foreign exchange impact on secured projects7       2.2     1.1  
Total secured projects (Cdn$)       30.3     9.9  

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 the 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 over the contract service term commencing once 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 Power and Storage assets.
7 Reflects U.S./Canada foreign exchange rate of 1.34 at March 31, 2019.

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 otherwise determined by management.

    Estimated project cost1     Carrying value
at March 31, 2019
 
(billions of $)
         
Canadian Natural Gas Pipelines        
NGTL System – Merrick   1.9      
U.S. Natural Gas Pipelines        
Other capacity capital2   US 0.7      
Liquids Pipelines        
Keystone XL3   US 8.0     US 0.7  
Heartland and TC Terminals4   0.9     0.1  
Grand Rapids Phase 24   0.7      
Keystone Hardisty Terminal4   0.3     0.1  
Power and Storage        
Bruce Power – life extension5   6.0      
    18.5     0.9  
Foreign exchange impact on projects under development6   3.0     0.2  
Total projects under development (Cdn$)   21.5     1.1  

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 Includes projects subject to a positive customer FID.
3 Carrying value reflects amount remaining after impairment charge recorded in 2015 along with additional amounts capitalized from January 1, 2018. A portion of these costs are recoverable from shippers under certain conditions.
4 Regulatory approvals have been obtained and additional commercial support is being pursued.
5 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.
6 Reflects U.S./Canada foreign exchange rate of 1.34 at March 31, 2019.

Outlook

Consolidated comparable earnings
Our overall comparable earnings outlook for 2019 remains consistent with the disclosure in the 2018 Annual Report.

Consolidated capital spending
Our expected total capital expenditures as outlined in the 2018 Annual Report remain materially unchanged.

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
March 31
(millions of $)   2019     2018  
         
NGTL System   292     271  
Canadian Mainline   237     193  
Other Canadian pipelines1   27     30  
Comparable EBITDA   556     494  
Depreciation and amortization   (287 )   (241 )
Comparable EBIT and segmented earnings   269     253  

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 comparable EBIT and segmented earnings increased by $16 million for the three months ended March 31, 2019 compared to the same period in 2018.

Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are primarily affected by our approved ROE, our investment base, the 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 revenue on a flow-through basis.

NET INCOME AND AVERAGE INVESTMENT BASE

  three months ended
March 31
(millions of $) 2019     2018  
       
Net Income      
NGTL System 113     92  
Canadian Mainline 44     37  
Average investment base      
NGTL System 11,096     9,091  
Canadian Mainline 3,665     3,817  

Net income for the NGTL System increased by $21 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to a higher average investment base resulting from continued system expansions. The NGTL System is operating under the 2018-2019 Settlement which 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 and flow-through treatment of all other costs.

Net income for the Canadian Mainline increased by $7 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to higher incentive earnings. We did not record incentive earnings in first quarter 2018 pending the outcome of the 2018-2020 toll review. The NEB 2018 Decision, received in December 2018, preserved the incentive arrangement from the NEB 2014 Decision along with an approved ROE of 10.1 per cent on 40 per cent deemed equity.

COMPARABLE EBITDA
Comparable EBITDA increased by $62 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to the recovery of increased depreciation as a result of higher rates approved in both the Canadian Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher pre-tax rate base earnings for the NGTL System and higher incentive earnings and flow-through income taxes for the Canadian Mainline.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $46 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to the increase in composite depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement as well as additional NGTL System facilities that were placed in service in 2018 and first quarter 2019.

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
March 31
(millions of US$, unless otherwise noted)   2019     2018  
         
Columbia Gas   308     231  
ANR   153     141  
TC PipeLines, LP1,2   36     39  
Great Lakes3   30     35  
Midstream   37     30  
Columbia Gulf   35     26  
Other U.S. pipelines4   19     15  
Non-controlling interests5   112     118  
Comparable EBITDA   730     635  
Depreciation and amortization   (135 )   (122 )
Comparable EBIT   595     513  
Foreign exchange impact   197     135  
Comparable EBIT and segmented earnings (Cdn$)   792     648  

1 Reflects our earnings from TC PipeLines, LP’s ownership interests in eight natural gas pipelines as well as general and administrative costs related to TC PipeLines, LP.
2 For the three months ended March 31, 2019, our ownership interest in TC PipeLines, LP was 25.5 per cent, which is unchanged from the same period in 2018.
3 Reflects our 53.55 per cent direct interest in Great Lakes. The remaining 46.45 per cent is held by TC PipeLines, LP.
4 Reflects earnings from our effective ownership in Millennium and Hardy Storage, as well as general and administrative and business development costs related to our U.S. natural gas pipelines.
5 Reflects earnings attributable to portions of TC PipeLines, LP, that we do not own.

U.S. Natural Gas Pipelines comparable EBIT and segmented earnings increased by $144 million for the three months ended March 31, 2019 compared to the same period in 2018. In addition to the net increases in comparable EBITDA noted below, a stronger U.S. dollar in 2019 had a positive impact on the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same period in 2018.

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$95 million for the three months ended March 31, 2019 compared to the same period in 2018. This was primarily the net effect of:

  • increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service
  • decreased earnings from Bison due to 2018 customer agreements to pay out their future contracted revenues and terminate their contracts.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$13 million for the three months ended March 31, 2019 compared to the same period in 2018 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
March 31
(millions of US$, unless otherwise noted)   2019     2018  
         
Topolobampo   40     44  
Tamazunchale   31     31  
Mazatlán   18     20  
Guadalajara   16     19  
Sur de Texas1   5     9  
Other       4  
Comparable EBITDA   110     127  
Depreciation and amortization   (23 )   (19 )
Comparable EBIT   87     108  
Foreign exchange impact   29     29  
Comparable EBIT and segmented earnings (Cdn$)   116     137  

1 Represents equity income from our 60 per cent interest.

Mexico Natural Gas Pipelines comparable EBIT and segmented earnings decreased by $21 million for the three months ended March 31, 2019 compared to the same period in 2018. Lower EBITDA as described below was partially offset by a stronger U.S. dollar in 2019 which had a positive impact on Canadian dollar equivalent earnings.

Comparable EBITDA for Mexico Natural Gas Pipelines decreased by US$17 million for the three months ended March 31, 2019 compared to the same period in 2018 mainly due to the net effect of:

  • lower revenues from operations as a result of changes in timing of revenue recognition in 2018  
  • lower equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. The inter-affiliate loan amount is fully offset in Interest income and other in the Corporate segment
  • a TransGas distribution received and recorded as income in 2018, recorded in Other above.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization was higher for the three months ended March 31, 2019 compared to the same period in 2018 reflecting new assets in service and other adjustments.

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
March 31
(millions of $)   2019     2018  
         
Keystone Pipeline System   424     340  
Intra-Alberta pipelines   39     39  
Liquids marketing and other   100     52  
Comparable EBITDA   563     431  
Depreciation and amortization   (88 )   (83 )
Comparable EBIT   475     348  
Specific item:        
Risk management activities   (15 )   (7 )
Segmented earnings   460     341  
         
Comparable EBIT denominated as follows:        
Canadian dollars   89     93  
U.S. dollars   290     202  
Foreign exchange impact   96     53  
Comparable EBIT   475     348  

Liquids Pipelines segmented earnings increased by $119 million for the three months ended March 31, 2019 compared to the same period in 2018 and include unrealized losses from changes in the fair value of derivatives related to our liquids marketing business which have been excluded from our calculation of comparable EBIT.

Comparable EBITDA for Liquids Pipelines increased by $132 million for the three months ended March 31, 2019 compared to the same period in 2018 and was due to:

  • higher volumes on the Keystone Pipeline System
  • higher contribution from liquids marketing activities due to improved margins and volumes
  • positive foreign exchange impact on the Canadian dollar equivalent earnings from our U.S. operations.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $5 million for the three months ended March 31, 2019 compared to the same period in 2018 as a result of new facilities being placed in service and the effect of a stronger U.S. dollar.

Power and Storage

As of first quarter 2019, the previously disclosed Energy segment has been renamed the Power and Storage segment.

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
March 31
(millions of $)   2019     2018  
         
Western and Eastern Power1   77     119  
Bruce Power1   60     54  
Natural Gas Storage and other   17     7  
Business development   (3 )   (4 )
Comparable EBITDA   151     176  
Depreciation and amortization   (23 )   (32 )
Comparable EBIT   128     144  
Specific items:        
U.S. Northeast power marketing contracts   (16 )   8  
Risk management activities   (64 )   (102 )
Segmented earnings   48     50  

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

Power and Storage segmented earnings decreased by $2 million for the three months ended March 31, 2019 compared to the same period in 2018 and included the following specific items:

  • a loss of $16 million for the three months ended March 31, 2019 (2018 – gain of $8 million) related to our U.S. Northeast power marketing contracts. These amounts have been excluded from Power and Storage's comparable earnings as we do not consider the wind-down and sales of the remaining contracts part of our underlying operations
  • unrealized losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks, primarily related to the remaining U.S. Northeast power marketing contracts.

Comparable EBITDA for Power and Storage decreased by $25 million for the three months ended March 31, 2019 compared to the same period in 2018 primarily due to the net effect of:

  • decreased Western and Eastern Power results largely due to the sale of our interests in the Cartier Wind power facilities in October 2018 and costs related to Napanee's delayed in-service. Refer to the Recent developments section for more information
  • increased Natural Gas Storage results due to higher realized natural gas storage price spreads
  • increased Bruce Power results primarily due to higher income on funds invested for future retirement benefits, partially offset by lower volumes resulting from higher outage days. Additional financial and operating information on Bruce Power is provided below.

DEPRECIATION AND AMORTIZATION
Depreciation and amortization decreased by $9 million for the three months ended March 31, 2019 compared to the same period in 2018 primarily due to the sale of our interests in the Cartier Wind power facilities in October 2018 and the cessation of depreciation on our Coolidge generating station upon classification as held for sale at December 31, 2018.

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

    three months ended
March 31
(millions of $, unless otherwise noted)     2019       2018  
         
Equity income included in comparable EBITDA and EBIT comprised of:        
Revenues1     361       371  
Operating expenses     (227 )     (227 )
Depreciation and other     (74 )     (90 )
Comparable EBITDA and EBIT2     60       54  
Bruce Power other information        
Plant availability3     79 %     85 %
Planned outage days     141       74  
Unplanned outage days     7       31  
Sales volumes (GWh)2     5,260       5,696  
Realized sales price per MWh4   $68     $67  

1 Net of amounts recorded to reflect operating cost efficiencies shared with the IESO.
2 Represents our 48.3 per cent (2018 – 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 3 began in fourth quarter 2018 and on Unit 7 in February 2019, with both units expected to be back in service in second quarter 2019. Planned maintenance is expected to occur on Unit 2 in second quarter 2019 and on Unit 5 in the second half of 2019. The overall average plant availability percentage in 2019 is expected to be in the mid-80 per cent range.

On April 1, 2019, Bruce Power's contract price increased from approximately $68 per MWh to approximately $75 per MWh reflecting capital to be invested under the Unit 6 Major Component Replacement program and the Asset Management program as well as normal annual inflation adjustments.

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
March 31
(millions of $)   2019     2018  
         
Comparable EBITDA and EBIT   (5 )   (2 )
Specific item:        
Foreign exchange loss – inter-affiliate loan1   (14 )   (79 )
Segmented losses   (19 )   (81 )

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

Corporate segmented losses decreased by $62 million for the three months ended March 31, 2019 compared to the same period in 2018. Segmented losses include foreign exchange losses on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the project's financing which are fully offset by corresponding foreign exchange gains included in Interest income and other on the inter-affiliate loan receivable. These amounts have been excluded from our calculation of comparable EBIT.

OTHER INCOME STATEMENT ITEMS

Interest Expense

    three months ended
March 31
(millions of $)   2019     2018  
         
Interest on long-term debt and junior subordinated notes        
Canadian dollar-denominated   (140 )   (134 )
U.S. dollar-denominated   (331 )   (314 )
Foreign exchange impact   (109 )   (83 )
    (580 )   (531 )
Other interest and amortization expense   (43 )   (22 )
Capitalized interest   37     26  
Interest expense   (586 )   (527 )

Interest expense increased by $59 million for the three months ended March 31, 2019 compared to the same period in 2018 and primarily reflects the net effect of:

  • long-term debt issuances, net of maturities
  • foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest
  • higher levels of short-term borrowing
  • higher capitalized interest primarily related to Napanee and Keystone XL.

Allowance for funds used during construction

    three months ended
March 31
(millions of $)   2019     2018  
         
Canadian dollar-denominated   43     20  
U.S. dollar-denominated   72     67  
Foreign exchange impact   24     18  
Allowance for funds used during construction   139     105  

AFUDC increased by $34 million for the three months ended March 31, 2019 compared to the same period in 2018. The increase in Canadian dollar-denominated AFUDC is primarily due to capital expenditures in our NGTL System expansion projects. The increase in U.S. dollar-denominated AFUDC is primarily due to continued investment in Mexico projects.

Interest income and other

    three months ended
March 31
(millions of $)   2019     2018  
         
Interest income and other included in comparable earnings   29     63  
Specific items:        
Foreign exchange gain – inter-affiliate loan   14     79  
Risk management activities   120     (79 )
Interest income and other   163     63  

Interest income and other increased by $100 million for the three months ended March 31, 2019 compared to the same period in 2018 and was primarily the net effect of:

  • unrealized gains on risk management activities in 2019 compared to unrealized losses in 2018. These amounts have been excluded from comparable earnings
  • higher interest income combined with a lower foreign exchange gain related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange loss in Sur de Texas are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively, resulting in no impact on net income. The offsetting currency-related gain and loss amounts are excluded from comparable earnings
  • realized losses in 2019 compared to realized gains in 2018 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.

Income tax expense

    three months ended
March 31
(millions of $)   2019     2018  
         
Income tax expense included in comparable earnings   (228 )   (171 )
Specific items:        
U.S. Northeast power marketing contracts   4     (2 )
Risk management activities   (12 )   52  
Income tax expense   (236 )   (121 )

Income tax expense included in comparable earnings increased by $57 million for the three months ended March 31, 2019 compared to the same period in 2018. This was primarily due to higher comparable earnings before income taxes and lower foreign tax rate differentials.

Net income attributable to non-controlling interests

...
    three months ended
March 31
(millions of $)