99.1 | A copy of the registrant’s news release of February 14, 2019. |
Date: February 14, 2019 | TRANSCANADA CORPORATION | |
By: | /s/ Donald R. Marchand | |
Donald R. Marchand | ||
Executive Vice-President and | ||
Chief Financial Officer | ||
By: | /s/ G. Glenn Menuz | |
G. Glenn Menuz | ||
Vice-President and Controller |
NewsRelease | ||
• | Fourth quarter 2018 financial results |
◦ | Comparable distributable cash flow of $1.7 billion or $1.89 per common share |
• | For the year ended December 31, 2018 |
◦ | Net income attributable to common shares of $3.5 billion or $3.92 per common share |
◦ | Comparable earnings of $3.5 billion or $3.86 per common share |
◦ | Comparable earnings before interest, taxes, depreciation and amortization of $8.6 billion |
◦ | Net cash provided by operations of $6.6 billion |
◦ | Comparable funds generated from operations of $6.5 billion |
◦ | Comparable distributable cash flow of $5.9 billion or $6.52 per common share |
• | Fourth quarter highlights |
◦ | TransCanada's Board approved an 8.7 per cent increase in the quarterly common share dividend to $0.75 per common share for the quarter ending March 31, 2019 |
◦ | Announced that we will proceed with construction of the $6.2 billion Coastal GasLink pipeline project |
◦ | Announced $1.5 billion NGTL 2022 Expansion Program |
◦ | Secured transportation contracts for the North Bay Junction Long Term Fixed Price service on the Canadian Mainline |
◦ | Completed the sale of our interests in the Cartier Wind power facilities for approximately $630 million |
◦ | Entered into an agreement to sell our Coolidge generating station for approximately US$465 million with closing expected to occur in mid-2019 |
◦ | Reimbursed for $470 million of Coastal GasLink pre-Final Investment Decision costs |
◦ | In January 2019, announced planned name change to TC Energy subject to shareholder and regulatory approval |
• | higher contribution from Canadian Natural Gas Pipelines primarily due to the recovery of increased depreciation approved in both the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher flow-through taxes and incentive earnings |
• | higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform |
• | higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, increased earnings from liquids marketing activities and earnings from intra-Alberta pipelines placed in service in the second half of 2017 |
• | higher revenues from Mexico Natural Gas Pipelines as a result of changes in timing of revenue recognition |
• | lower earnings from Bruce Power primarily due to lower volumes resulting from higher outage days. |
• | changes in comparable EBITDA described above |
• | higher depreciation primarily in Canadian Natural Gas Pipelines due to increased depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement (these amounts are fully recovered as reflected in the increase in comparable EBITDA described above, having no net impact on comparable earnings) as well as higher depreciation related to new projects placed in service in 2017 and 2018 |
• | higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities |
• | lower interest income and other as a result of realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. |
• | higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform |
• | higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, increased earnings from liquids marketing activities and earnings from intra-Alberta pipelines placed in service in the second half of 2017 |
• | higher contribution from Canadian Natural Gas Pipelines primarily due to the recovery of increased depreciation as a result of higher rates approved in both the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher overall pre-tax rate base earnings, partially offset by lower incentive earnings and flow-through income taxes |
• | lower earnings from U.S. Power mainly due to the sales of our U.S. Northeast power generation assets in second quarter 2017 |
• | lower earnings from Bruce Power primarily due to lower volumes resulting from higher outage days and lower results from contracting activities. |
• | changes in comparable EBITDA described above |
• | higher depreciation primarily in Canadian Natural Gas Pipelines due to increased depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement (these amounts are fully recovered as reflected in the increase in comparable EBITDA described above, having no net impact on comparable earnings) as well as higher depreciation related to new projects placed in service in 2017 and 2018 |
• | higher interest expense primarily as a result of additional long-term debt issuances in 2018 and the full year impact of long-term debt and junior subordinated notes issuances in 2017, net of maturities, as well as lower capitalized interest, partially offset by the repayment of the Columbia acquisition bridge facilities in June 2017 |
• | lower income tax expense primarily due to reduced income tax rates resulting from U.S. Tax Reform and lower flow-through income taxes in Canadian rate-regulated pipelines. |
• | Coastal GasLink Pipeline Project: In October 2018, we announced that we are proceeding with construction of the Coastal GasLink pipeline project following the LNG Canada joint venture participants' announcement that they had reached a positive Final Investment Decision (FID) to build the LNG Canada natural gas liquefaction facility in Kitimat, B.C. Coastal GasLink will provide the natural gas supply to the LNG Canada facility and is underpinned by 25-year TSAs (with additional renewal provisions) with each of the five LNG Canada participants. Coastal GasLink will be a 670 km (416 miles) pipeline with an initial capacity of approximately 2.2 PJ/d (2.1 Bcf/d) with potential expansion capacity up to 5.4 PJ/d (5.0 Bcf/d). All necessary regulatory permits have been received to allow us to proceed with construction activities which began in December 2018, with a planned in-service date in 2023. Coastal GasLink has signed project and community agreements with all 20 elected Indigenous bands along the pipeline route, confirming strong support from Indigenous communities across the province of B.C. |
• | NGTL System: In October 2018, we announced the NGTL System 2022 Expansion Program to meet capacity requirements for incremental firm receipt and intra-basin delivery services to commence in November 2021 and April 2022. This $1.5 billion expansion of the NGTL System consists of approximately 197 km (122 miles) of new pipeline, three compressor units, meter stations and associated facilities. Applications for approvals to construct and operate the facilities are expected to be filed with the NEB in second quarter 2019 and, |
• | Canadian Mainline: In December 2018, we announced the North Bay Junction Long Term Fixed Price service (NBJ LTFP) which includes 670 TJ/d (625 MMcf/d) of new natural gas transportation contracts from the Western Canadian Sedimentary Basin (WCSB) on the Canadian Mainline. Upon NEB approval of the NBJ LTFP service, incremental volumes under these long-term, fixed-priced contracts will reach markets in Ontario, Québec, New Brunswick, Nova Scotia and the Northeastern U.S. using existing capacity on the Canadian Mainline as well as new compression facilities. Customers have executed 15-year precedent agreements to proceed with the project with an estimated capital cost of $96 million. We filed an application for approval of the NBJ LTFP with the NEB in January 2019 and expect a decision in third quarter 2019. |
• | WB XPress: The WB XPress project, a Columbia Gas project designed to transport approximately 1.4 PJ/d (1.3 Bcf/d) of Marcellus gas supply westbound to the Gulf Coast and eastbound to Mid-Atlantic Markets, was placed in service in October 2018 and November 2018 for the Western Build and Eastern Build, respectively. |
• | Mountaineer XPress and Gulf XPress: Mountaineer XPress (MXP), a Columbia Gas project, is designed to transport supply from the Marcellus and Utica shale plays to points along the system and to the Leach interconnect with Columbia Gulf. Approximately 45 per cent of this project was placed in service on January 18, 2019, with the remainder to be placed in service in February and March 2019, along with Gulf XPress, a Columbia Gulf project. Total estimated MXP project costs have been revised upwards to US$3.2 billion reflecting the impact of delays of various regulatory approvals from FERC and other agencies, increased contractor construction costs due to unusually high demand for construction resources in the region, unusually high instances of inclement weather throughout construction, and modifications to contractor work plans to mitigate construction delays associated with these impacts. |
• | Louisiana XPress: In November 2018, we sanctioned the Louisiana XPress project which will connect supply directly to Gulf Coast LNG export markets with the addition of three greenfield mid-point compressor stations along Columbia Gulf. The anticipated in-service date is in 2022 and estimated project costs are US$0.4 billion. |
• | Bison contract terminations and asset impairment: In the second half of 2018, two customers on Bison elected to pay out the remainder of their future contracted revenues and terminate their associated TSAs. The termination of these agreements was agreed to following the receipt of US$97 million in 2018, which was recorded in Revenues, as the terminations released us from providing any future services. This development, coupled with the persistence of unfavourable market conditions which have inhibited system flows on the pipeline, led us to determine that the asset’s remaining carrying value was no longer recoverable and a non-cash impairment charge of US$537 million was recorded in our U.S. Natural Gas Pipelines segment. As Bison is a TC PipeLines, LP asset, in which we have a 25.5 per cent interest, this impairment charge impacts our net income by $140 million after tax and non-controlling interests, but is excluded from comparable earnings. We continue to explore alternative transportation-related options for Bison. |
• | Tuscarora goodwill impairment: In fourth quarter 2018, Tuscarora finalized its regulatory approach in response to the 2018 FERC Actions, resulting in a reduction in its recourse rates. In connection with its annual goodwill impairment analysis, we evaluated Tuscarora’s future revenues as well as changes to other assumptions responsive to Tuscarora’s commercial environment. In doing so, we incorporated the outcome of a settlement-in-principle reached with its customers in January 2019. As a result of these developments, we determined that the fair value of Tuscarora did not exceed its carrying value, including goodwill, and recorded a goodwill impairment charge of US$59 million within the U.S. Natural Gas Pipelines segment. The remaining goodwill balance related to Tuscarora at December 31, 2018 was US$23 million. As Tuscarora is a TC PipeLines, LP asset, in which we have a 25.5 per cent interest, this impairment charge impacts our net income by $15 million after tax and non-controlling interests, but is excluded from comparable earnings. |
• | Sur de Texas: Offshore construction was completed in May 2018 and the project continues to progress toward an anticipated in-service date in early second quarter 2019. An amending agreement was signed with the CFE that recognizes force majeure events and the commencement of payments of fixed capacity charges began on October 31, 2018. |
• | Keystone XL: We have secured commercial support for all available Keystone XL project capacity and commenced certain pre-construction activities. We continue to address outstanding legal challenges regarding the project. The South Dakota Supreme Court dismissed an appeal against the certification of the project. We expect the Nebraska Supreme Court to reach a decision in the first quarter of 2019 regarding a challenge to the Nebraska Public Service Commission’s route approval. We continue to participate, together with the U.S. Department of Justice, in lawsuits commenced in Montana to defend legal challenges to the U.S. Presidential Permit and the exhaustive environmental assessments that support the U.S. President’s actions. |
• | Cartier Wind: In October 2018, we completed the sale of our interests in the Cartier Wind power facilities in Québec to Innergex Renewable Energy Inc. for gross proceeds of approximately $630 million before closing adjustments, resulting in a gain of $170 million ($143 million after tax). |
• | Coolidge Generating Station: On December 14, 2018, we entered into an agreement to sell our Coolidge generating station in Arizona to SWG Coolidge Holdings, LLC, for approximately US$465 million, subject to timing of the close and related adjustments. Salt River Project Agriculture Improvement and Power District, the PPA counterparty, exercised its contractual right of first refusal on a sale to a third party in January 2019. The sale will result in an estimated gain of approximately $65 million ($50 million after tax) to be recognized upon closing of the sale transaction which is expected to occur mid-2019. |
• | Napanee: Construction is substantially complete and commissioning activities are continuing at our 900 MW natural gas-fired power plant in eastern Ontario in the town of Greater Napanee. We expect our total investment in the Napanee facility will be approximately $1.7 billion with commercial operations expected to begin in second quarter 2019. |
• | Common Share Dividend: Our Board of Directors declared a quarterly dividend of $0.75 per share for the quarter ending March 31, 2019 on TransCanada's outstanding common shares. This represents an increase in the dividend of 8.7 per cent from the previous dividend and is equivalent to $3.00 per common share on an annualized basis. |
• | Issuance of Long-term Debt: In fourth quarter 2018, TCPL issued US$1.0 billion of Senior Unsecured Notes due in March 2049 bearing interest at a fixed rate of 5.10 per cent and US$400 million of Senior Unsecured Notes due in May 2028 bearing interest at a fixed rate of 4.25 per cent. |
• | Dividend Reinvestment Plan: In 2018, the DRP participation rate by common shareholders was approximately 35 per cent, resulting in $870 million reinvested in common equity under the program. |
• | ATM Equity Program: In 2018, 20 million common shares were issued under the Corporate ATM program at an average price of $56.13 per common share for proceeds of $1.1 billion, net of approximately $10 million of related commissions and fees. We view the issuance of common shares under this program as being complete. |
• | Proposed Name Change: On January 9, 2019, we announced our intention to change our name to TC Energy to better reflect the scope of the company's operations as a leading North American energy infrastructure company. The name change is subject to shareholder and regulatory approval and would be effective immediately following the Annual and Special Meeting of Shareholders in the second quarter of 2019. |
• | Management Changes: Karl Johannson and Kristine Delkus will be retiring from the Company in the first and second quarters of 2019, respectively. Effective January 1, 2019, Tracy Robinson was appointed Executive Vice-President and President, Canadian Natural Gas Pipelines and Francois Poirier was appointed to the expanded role of President of the Energy and Mexico Natural Gas Pipelines business units in addition to his role as Executive Vice-President, Strategy and Corporate Development. |
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. |
• | our financial and operational performance, including the performance of our subsidiaries |
• | expectations about strategies and goals for growth and expansion |
• | expected cash flows and future financing options available, including portfolio management |
• | expected dividend growth |
• | expected future credit ratings |
• | expected costs and schedules for planned projects, including projects under construction and in development |
• | expected capital expenditures and contractual obligations |
• | expected regulatory processes and outcomes, including the impact of the 2018 FERC Actions |
• | expected outcomes with respect to legal proceedings, including arbitration and insurance claims |
• | the expected impact of future accounting changes, commitments and contingent liabilities |
• | expected industry, market and economic conditions. |
• | regulatory decisions and outcomes, including final outcomes of the 2018 FERC Actions |
• | planned and unplanned outages and the use of our pipeline and energy assets |
• | integrity and reliability of our assets |
• | anticipated construction costs, schedules and completion dates |
• | access to capital markets, including portfolio management |
• | expected industry, market and economic conditions |
• | inflation rates and commodity prices |
• | interest, tax and foreign exchange rates |
• | nature and scope of hedging. |
• | our ability to successfully implement our strategic priorities and whether they will yield the expected benefits |
• | our ability to implement a capital allocation strategy aligned with maximizing shareholder value |
• | the operating performance of our pipeline and energy assets |
• | amount of capacity sold and rates achieved in our pipeline businesses |
• | the amount of capacity payments and revenues from our energy business due to plant availability |
• | production levels within supply basins |
• | construction and completion of capital projects |
• | costs for labour, equipment and materials |
• | the availability and market prices of commodities |
• | access to capital markets on competitive terms |
• | interest, tax and foreign exchange rates |
• | performance and credit risk of our counterparties |
• | regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims |
• | changes in environmental and other laws and regulations |
• | competition in the pipeline and energy sectors |
• | unexpected or unusual weather |
• | acts of civil disobedience |
• | cyber security and technological developments |
• | economic conditions in North America as well as globally |
• | our ability to effectively anticipate and assess changes to government policies and regulations. |
• | 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. |
• | certain fair value adjustments relating to risk management activities |
• | income tax refunds and adjustments to enacted tax rates |
• | gains or losses on sales of assets or assets held for sale |
• | legal, contractual and bankruptcy settlements |
• | impact of regulatory or arbitration decisions relating to prior year earnings |
• | restructuring costs |
• | impairment of goodwill, investments and other assets including certain ongoing maintenance and liquidation costs |
• | acquisition and integration costs. |
Non-GAAP measure | GAAP measure |
comparable EBITDA | segmented earnings |
comparable EBIT | segmented earnings |
comparable earnings | net income attributable to common shares |
comparable earnings per common share | net income per common share |
comparable funds generated from operations | net cash provided by operations |
comparable distributable cash flow | net cash provided by operations |
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 |
• | a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities |
• | a $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from the 2018 FERC Actions |
• | a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform |
• | a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets |
• | $25 million of after-tax income recognized on the Bison contract terminations |
• | a $140 million after-tax impairment charge on Bison |
• | a $15 million after-tax goodwill impairment charge on Tuscarora |
• | an after-tax net loss of $7 million related to our U.S. Northeast power marketing contracts. |
• | an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform |
• | a $136 million after-tax gain related to the sale of our Ontario solar assets |
• | a $64 million net after-tax gain related to the monetization of our U.S. Northeast power generation assets |
• | a $954 million after-tax impairment charge for the Energy East pipeline and related projects as a result of our decision not to proceed with the project applications |
• | a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets. |
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 |
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 |
• | higher contribution from Canadian Natural Gas Pipelines primarily due to the recovery of increased depreciation as a result of higher rates approved in both the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as higher flow-through taxes and incentive earnings |
• | higher contribution from U.S. Natural Gas Pipelines mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service, additional contract sales on ANR and Great Lakes, and amortization of net regulatory liabilities recognized as a result of U.S. Tax Reform |
• | higher contribution from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, increased earnings from liquids marketing activities and earnings from intra-Alberta pipelines placed in service in the second half of 2017 |
• | higher revenues from Mexico Natural Gas Pipelines as a result of changes in timing of revenue recognition |
• | lower earnings from Bruce Power primarily due to lower volumes resulting from higher outage days. |
• | changes in comparable EBITDA described above |
• | higher depreciation primarily in Canadian Natural Gas Pipelines due to increased depreciation rates approved in the Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement (these amounts are fully recovered as reflected in the increase in comparable EBITDA described above, having no net impact on comparable earnings) as well as higher depreciation related to new projects placed in service in 2017 and 2018 |
• | higher interest expense primarily as a result of long-term debt and junior subordinated notes issuances, net of maturities |
• | lower interest income and other as a result of realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. |
• | On November 15, 2018, FERC issued a Policy Statement on the Accounting and Ratemaking Treatment of Accumulated Deferred Income Taxes (ADIT) and Treatment Following the Sale or Retirement of an Asset, a policy statement (Excess ADIT Policy Statement) addressing certain issues raised in the Notice of Inquiry (NOI) issued on March 15, 2018. The Excess ADIT Policy Statement clarifies FERC accounts in which pipelines should record amortization of excess and/or deficient ADIT for FERC reporting and ratemaking purposes. The Excess ADIT Policy Statement also addresses how to disclose reversals of ADIT account balances in FERC’s annual financial report filings |
• | In accordance with the Form 501-G filings and settlements reached with customers in response to the 2018 FERC Actions, the ADIT balances for all pipelines held wholly or in part by TC PipeLines, LP were eliminated from their respective rate bases. Therefore, regulatory liabilities recorded for these assets pursuant to U.S. Tax Reform were written off, resulting in a deferred income tax recovery of $115 million in fourth quarter 2018 |
• | All of our FERC-regulated natural gas pipelines and storage assets have now either filed a Form 501-G or an uncontested rate settlement with FERC as directed. There has been no significant incremental impact from our third quarter 2018 disclosures regarding the effect of 2018 FERC Actions on future earnings and cash flows |
• | Upon finalizing the 2017 annual tax returns for our U.S. businesses and clarifying the impact of U.S. Tax Reform on our deferred income tax liability at December 31, 2017, and as permitted by the SEC during the one-year measurement period, it was determined that an adjustment was required to the estimate originally recorded. Accordingly, a deferred income tax recovery of $52 million was recognized in fourth quarter 2018 to adjust our net regulatory liability and ADIT balances. |
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. |
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. |
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. |
three months ended December 31 | year ended December 31 | |||||||||||
(millions of $) | 2018 | 2017 | 2018 | 2017 | ||||||||
Net Income | ||||||||||||
NGTL System | 109 | 91 | 398 | 352 | ||||||||
Canadian Mainline | 61 | 50 | 182 | 199 | ||||||||
Average investment base | ||||||||||||
NGTL System | 9,669 | 8,385 | ||||||||||
Canadian Mainline | 3,828 | 4,184 |
three months ended December 31 | year ended December 31 | |||||||||||
(millions of US$, 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. |
• | a $722 million non-cash asset impairment charge related to Bison |
• | a $79 million non-cash goodwill impairment charge related to Tuscarora |
• | $130 million of termination payments received on two of Bison’s transportation contracts which was recorded in Revenues. |
• | increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service and additional contract sales on ANR and Great Lakes |
• | increased earnings due to the amortization of the net regulatory liabilities that were recorded at the end of 2017, partially offset by a reduction in certain rates on Columbia Gas as a result of U.S. Tax Reform. |
three months ended December 31 | year ended December 31 | |||||||||||
(millions of US$, 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. |
• | higher revenues from operations as a result of changes in timing of revenue recognition |
• | equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest expense on an inter-affiliate loan from TransCanada. The interest expense on this inter-affiliate loan is fully offset in Interest income and other in the Corporate segment |
• | incremental earnings from a CRE tariff increase. |
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 |
• | a $1,256 million pre-tax impairment charge in 2017 for the Energy East pipeline and related projects |
• | $11 million of pre-tax costs in 2017 related to Keystone XL for the maintenance and liquidation of project assets which were expensed pending further advancement of the project |
• | unrealized gains from changes in the fair value of derivatives related to our liquids marketing business. |
• | higher contracted and uncontracted volumes on the Keystone Pipeline System |
• | higher contribution from liquids marketing activities from improved margins and volumes |
• | incremental contributions from intra-Alberta pipelines, Grand Rapids and Northern Courier, which began operations in the second half of 2017 |
• | lower business development costs as a result of capitalizing Keystone XL expenditures in 2018 |
• | a stronger U.S. dollar which had a positive impact on the Canadian dollar equivalent earnings from our U.S. operations. |
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. |
• | a pre-tax gain in 2018 of $170 million related to the sale of our interests in the Cartier Wind power facilities |
• | a pre-tax net loss of $10 million related to our U.S. Northeast power marketing contracts. These results have been excluded from Energy's comparable earnings in 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020 |
• | a pre-tax gain in 2017 of $127 million related to the sale of our Ontario solar assets |
• | a pre-tax net gain of $15 million in 2017 related to the monetization of our U.S. Northeast power generation assets |
• | unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks, as noted in the table below. |
Risk management activities | three months ended December 31 | year ended December 31 | ||||||||||
(millions of $, pre-tax) | 2018 | 2017 | 2018 | 2017 | ||||||||
Canadian Power | — | 6 | 3 | 11 | ||||||||
U.S. Power | 20 | 136 | (11 | ) | 39 | |||||||
Natural Gas Storage | (5 | ) | 7 | (11 | ) | 12 | ||||||
Total unrealized gains/(losses) from risk management activities | 15 | 149 | (19 | ) | 62 |
• | decreased earnings from Bruce Power primarily due to lower volumes resulting from higher outage days. Additional financial and operating information on Bruce Power is provided below |
• | decreased Western and Eastern Power results due to the sales of our Cartier Wind power facilities in October 2018 and our Ontario solar assets in December 2017, partially offset by higher Western Power realized margins on higher generation volumes |
• | lower Natural Gas Storage results primarily due to pipeline constraints in the Alberta natural gas market which limited our ability to access our storage facilities and resulted in lower realized natural gas storage price spreads. |
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. |
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. |
• | foreign exchange gains on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the project's financing. There is a corresponding foreign exchange loss included in Interest income and other on the inter-affiliate loan receivable which fully offsets this gain. |
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 | ) |
• | long-term debt and junior subordinated note issuances in 2018 and 2017, net of maturities |
• | higher capitalized interest primarily due to ongoing construction at Napanee and the recommencement of capitalization of Keystone XL costs in 2018, partially offset by the completion of Northern Courier in fourth quarter 2017 |
• | higher levels of short-term borrowing |
• | foreign exchange impact on translation of U.S. dollar-denominated interest. |
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 |
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 |
• | higher unrealized losses on risk management activities in 2018 compared to 2017, reflecting the strengthening of the U.S. dollar at the end of 2018. These amounts have been excluded from comparable earnings |
• | realized losses in 2018 compared to realized gains in 2017 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income |
• | higher interest income combined with a lower foreign exchange loss related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange gain are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. The offsetting currency-related gain and loss amounts are excluded from comparable earnings. |
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 |
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 | ) |
• | a $538 million charge related to the non-controlling interests portion of a $722 million Bison asset impairment charge recorded by TC PipeLines, LP |
• | a $59 million charge related to the non-controlling interests portion of a $79 million Tuscarora goodwill impairment charge recorded by TC PipeLines, LP |
• | $97 million in income related to the non-controlling interests portion of Bison contract termination payments of $130 million received from certain customers and recorded by TC PipeLines, LP. |
three months ended December 31 | year ended December 31 | |||||||||||
(millions of $) | 2018 | 2017 | 2018 | 2017 | ||||||||
Preferred share dividends | (41 | ) | (40 | ) | (163 | ) | (160 | ) |
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 |
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 |
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 |
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 |
December 31, | December 31, | ||||||
(unaudited - millions of Canadian $) | 2018 | 2017 | |||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | 446 | 1,089 | |||||
Accounts receivable | 2,535 | 2,522 | |||||
Inventories | 431 | 378 | |||||
Assets held for sale | 543 | — | |||||
Other | 1,180 | 691 | |||||
5,135 | 4,680 | ||||||
Plant, Property and Equipment | net of accumulated depreciation of $25,834 and $23,734, respectively | 66,503 | 57,277 | ||||
Equity Investments | 7,113 | 6,366 | |||||
Regulatory Assets | 1,548 | 1,376 | |||||
Goodwill | 14,178 | 13,084 | |||||
Loan Receivable from Affiliate | 1,315 | 919 | |||||
Intangible and Other Assets | 1,921 | 1,484 | |||||
Restricted Investments | 1,207 | 915 | |||||
98,920 | 86,101 | ||||||
LIABILITIES | |||||||
Current Liabilities | |||||||
Notes payable | 2,762 | 1,763 | |||||
Accounts payable and other | 5,408 | 4,057 | |||||
Dividends payable | 668 | 586 | |||||
Accrued interest | 646 | 605 | |||||
Current portion of long-term debt | 3,462 | 2,866 | |||||
12,946 | 9,877 | ||||||
Regulatory Liabilities | 3,930 | 4,321 | |||||
Other Long-Term Liabilities | 1,008 | 727 | |||||
Deferred Income Tax Liabilities | 6,026 | 5,403 | |||||
Long-Term Debt | 36,509 | 31,875 | |||||
Junior Subordinated Notes | 7,508 | 7,007 | |||||
67,927 | 59,210 | ||||||
EQUITY | |||||||
Common shares, no par value | 23,174 | 21,167 | |||||
Issued and outstanding: | December 31, 2018 – 918 million shares | ||||||
December 31, 2017 – 881 million shares | |||||||
Preferred shares | 3,980 | 3,980 | |||||
Additional paid-in capital | 17 | — | |||||
Retained earnings | 2,773 | 1,623 | |||||
Accumulated other comprehensive loss | (606 | ) | (1,731 | ) | |||
Controlling Interests | 29,338 | 25,039 | |||||
Non-controlling interests | 1,655 | 1,852 | |||||
30,993 | 26,891 | ||||||
98,920 | 86,101 |
three months ended December 31, 2018 | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | |||||||||||||||||
(unaudited - millions of Canadian $) | Energy | Corporate1 | Total | ||||||||||||||||||
Revenues | 1,266 | 1,326 | 159 | 753 | 400 | — | 3,904 | ||||||||||||||
Intersegment revenues | — | 41 | — | — | 6 | (47 | ) | 2 | — | ||||||||||||
1,266 | 1,367 | 159 | 753 | 406 | (47 | ) | 3,904 | ||||||||||||||
Income from equity investments | 3 | 68 | 2 | 14 | 78 | 57 | 3 | 222 | |||||||||||||
Plant operating costs and other | (385 | ) | (443 | ) | (9 | ) | (124 | ) | (63 | ) | 13 | 2 | (1,011 | ) | |||||||
Commodity purchases resold | — | — | — | — | (249 | ) | — | (249 | ) | ||||||||||||
Property taxes | (66 | ) | (50 | ) | — | (24 | ) | — | — | (140 | ) | ||||||||||
Depreciation and amortization | (368 | ) | (175 | ) | (24 | ) | (87 | ) | (27 | ) | — | (681 | ) | ||||||||
Goodwill and other asset impairment charges | — | (801 | ) | — | — | — | — | (801 | ) | ||||||||||||
Gain on sale of assets | — | — | — | — | 170 | — | 170 | ||||||||||||||
Segmented earnings/(losses) | 450 | (34 | ) | 128 | 532 | 315 | 23 | 1,414 | |||||||||||||
Interest expense | (603 | ) | |||||||||||||||||||
Allowance for funds used during construction | 161 | ||||||||||||||||||||
Interest income and other3 | (215 | ) | |||||||||||||||||||
Income before income taxes | 757 | ||||||||||||||||||||
Income tax expense | (38 | ) | |||||||||||||||||||
Net income | 719 | ||||||||||||||||||||
Net loss attributable to non-controlling interests | 414 | ||||||||||||||||||||
Net income attributable to controlling interests | 1,133 | ||||||||||||||||||||
Preferred share dividends | (41 | ) | |||||||||||||||||||
Net income attributable to common shares | 1,092 |
1 | Includes intersegment eliminations. |
2 | The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. |
3 | Income from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. |
three months ended December 31, 2017 | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | |||||||||||||||||
(unaudited - millions of Canadian $) | Energy | Corporate1 | Total | ||||||||||||||||||
Revenues | 968 | 900 | 138 | 599 | 1,012 | — | 3,617 | ||||||||||||||
Intersegment revenues | — | 20 | — | — | — | (20 | ) | 2 | — | ||||||||||||
968 | 920 | 138 | 599 | 1,012 | (20 | ) | 3,617 | ||||||||||||||
Income/(loss) from equity investments | 2 | 65 | (9 | ) | (6 | ) | 130 | 64 | 3 | 246 | |||||||||||
Plant operating costs and other | (342 | ) | (336 | ) | (13 | ) | (186 | ) | (86 | ) | 19 | 2 | (944 | ) | |||||||
Commodity purchases resold | — | — | — | — | (671 | ) | — | (671 | ) | ||||||||||||
Property taxes | (59 | ) | (45 | ) | — | (22 | ) | (1 | ) | — | (127 | ) | |||||||||
Depreciation and amortization | (236 | ) | (143 | ) | (23 | ) | (81 | ) | (33 | ) | — | (516 | ) | ||||||||
Goodwill and other asset impairment charges | — | — | — | (1,236 | ) | (21 | ) | — | (1,257 | ) | |||||||||||
Gain on sale of assets | — | — | — | — | 142 | — | 142 | ||||||||||||||
Segmented earnings/(losses) | 333 | 461 | 93 | (932 | ) | 472 | 63 | 490 | |||||||||||||
Interest expense | (541 | ) | |||||||||||||||||||
Allowance for funds used during construction | 140 | ||||||||||||||||||||
Interest income and other3 | (9 | ) | |||||||||||||||||||
Income before income taxes | 80 | ||||||||||||||||||||
Income tax recovery | 870 | ||||||||||||||||||||
Net income | 950 | ||||||||||||||||||||
Net income attributable to non-controlling interests | (49 | ) | |||||||||||||||||||
Net income attributable to controlling interests | 901 | ||||||||||||||||||||
Preferred share dividends | (40 | ) | |||||||||||||||||||
Net income attributable to common shares | 861 |
1 | Includes intersegment eliminations. |
2 | The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. |
3 | Income/(loss) from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. |
year ended December 31, 2018 | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | |||||||||||||||||
(unaudited - millions of Canadian $) | Energy | Corporate1 | Total | ||||||||||||||||||
Revenues | 4,038 | 4,314 | 619 | 2,584 | 2,124 | — | 13,679 | ||||||||||||||
Intersegment revenues | — | 162 | — | — | 56 | (218 | ) | 2 | — | ||||||||||||
4,038 | 4,476 | 619 | 2,584 | 2,180 | (218 | ) | 13,679 | ||||||||||||||
Income from equity investments | 12 | 256 | 22 | 64 | 355 | 5 | 3 | 714 | |||||||||||||
Plant operating costs and other | (1,405 | ) | (1,368 | ) | (34 | ) | (630 | ) | (313 | ) | 159 | 2 | (3,591 | ) | |||||||
Commodity purchases resold | — | — | — | — | (1,488 | ) | — | (1,488 | ) | ||||||||||||
Property taxes | (266 | ) | (199 | ) | — | (98 | ) | (6 | ) | — | (569 | ) | |||||||||
Depreciation and amortization | (1,129 | ) | (664 | ) | (97 | ) | (341 | ) | (119 | ) | — | (2,350 | ) | ||||||||
Goodwill and other asset impairment charges | — | (801 | ) | — | — | — | — | (801 | ) | ||||||||||||
Gain on sale of assets | — | — | — | — | 170 | — | 170 | ||||||||||||||
Segmented earnings/(losses) | 1,250 | 1,700 | 510 | 1,579 | 779 | (54 | ) | 5,764 | |||||||||||||
Interest expense | (2,265 | ) | |||||||||||||||||||
Allowance for funds used during construction | 526 | ||||||||||||||||||||
Interest income and other3 | (76 | ) | |||||||||||||||||||
Income before income taxes | 3,949 | ||||||||||||||||||||
Income tax expense | (432 | ) | |||||||||||||||||||
Net income | 3,517 | ||||||||||||||||||||
Net loss attributable to non-controlling interests | 185 | ||||||||||||||||||||
Net income attributable to controlling interests | 3,702 | ||||||||||||||||||||
Preferred share dividends | (163 | ) | |||||||||||||||||||
Net income attributable to common shares | 3,539 |
1 | Includes intersegment eliminations. |
2 | The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. |
3 | Income from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. |
year ended December 31, 2017 | Canadian Natural Gas Pipelines | U.S. Natural Gas Pipelines | Mexico Natural Gas Pipelines | Liquids Pipelines | |||||||||||||||||
(unaudited - millions of Canadian $) | Energy | Corporate1 | Total | ||||||||||||||||||
Revenues | 3,693 | 3,584 | 570 | 2,009 | 3,593 | — | 13,449 | ||||||||||||||
Intersegment revenues | — | 51 | — | — | — | (51 | ) | 2 | — | ||||||||||||
3,693 | 3,635 | 570 | 2,009 | 3,593 | (51 | ) | 13,449 | ||||||||||||||
Income/(loss) from equity investments | 11 | 240 | (9 | ) | (3 | ) | 471 | 63 | 3 | 773 | |||||||||||
Plant operating costs and other | (1,300 | ) | (1,340 | ) | (42 | ) | (623 | ) | (550 | ) | (51 | ) | 2 | (3,906 | ) | ||||||
Commodity purchases resold | — | — | — | — | (2,382 | ) | — | (2,382 | ) | ||||||||||||
Property taxes | (260 | ) | (181 | ) | — | (89 | ) | (39 | ) | — | (569 | ) | |||||||||
Depreciation and amortization | (908 | ) | (594 | ) | (93 | ) | (309 | ) | (151 | ) | — | (2,055 | ) | ||||||||
Goodwill and other asset impairment charges | — | — | — | (1,236 | ) | (21 | ) | — | (1,257 | ) | |||||||||||
Gain on sale of assets | — | — | — | — | 631 | — | 631 | ||||||||||||||
Segmented earnings/(losses) | 1,236 | 1,760 | 426 | (251 | ) | 1,552 | (39 | ) | 4,684 | ||||||||||||
Interest expense | (2,069 | ) | |||||||||||||||||||
Allowance for funds used during construction | 507 | ||||||||||||||||||||
Interest income and other3 | 184 | ||||||||||||||||||||
Income before income taxes | 3,306 | ||||||||||||||||||||
Income tax recovery | 89 | ||||||||||||||||||||
Net income | 3,395 | ||||||||||||||||||||
Net income attributable to non-controlling interests | (238 | ) | |||||||||||||||||||
Net income attributable to controlling interests | 3,157 | ||||||||||||||||||||
Preferred share dividends | (160 | ) | |||||||||||||||||||
Net income attributable to common shares | 2,997 |
1 | Includes intersegment eliminations. |
2 | The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation. Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized. |
3 | Income/(loss) from equity investments includes foreign exchange gains on the Company's inter-affiliate loan with Sur de Texas. The offsetting foreign exchange losses on the inter-affiliate loan are included in Interest income and other. The peso-denominated loan to the Sur de Texas joint venture represents the Company's proportionate share of long-term debt financing for this joint venture. |
(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 |