Le Lézard
Subject: MISCELLANEOUS

TransCanada Reports Record Financial Results for 2018


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)

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:

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:

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:

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:

Notable recent developments include:

Canadian Natural Gas Pipelines:

U.S. Natural Gas Pipelines:

Mexico Natural Gas Pipelines:

Liquids Pipelines:

Energy:

Corporate:

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:

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

Risks and uncertainties

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:

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:

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 measureGAAP measure
  
comparable EBITDAsegmented earnings
comparable EBITsegmented earnings
comparable earningsnet income attributable to common shares
comparable earnings per common sharenet income per common share
comparable funds generated from operationsnet cash provided by operations
comparable distributable cash flownet 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:

Fourth quarter 2017 results included:

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:

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:

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:

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:

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:

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:

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:

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:

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:

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:

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:

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:

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:

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:

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 Equipmentnet 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 3222 
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 3246 
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 3714 
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 3773 
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 

 



News published on 14 february 2019 at 07:30 and distributed by: