TransCanada Corporation (TSX, NYSE: TRP) (TransCanada or the
Company) today announced net income attributable to common shares
for fourth quarter 2018 of $1.1 billion or $1.19 per share compared
to net income of $0.9 billion or $0.98 per share for the same
period in 2017. For the year ended December 31, 2018, net income
attributable to common shares was $3.5 billion or $3.92 per share
compared to net income of $3.0 billion or $3.44 per share in 2017.
Comparable earnings for fourth quarter 2018 were $946 million or
$1.03 per common share compared to $719 million or $0.82 per share
for the same period in 2017. For the year ended December 31, 2018,
comparable earnings were $3.5 billion or $3.86 per common share
compared to $2.7 billion or $3.09 per share in 2017. TransCanada's
Board of Directors also declared a quarterly dividend of $0.75 per
common share for the quarter ending March 31, 2019, equivalent to
$3.00 per common share on an annualized basis, an increase of 8.7
per cent. This is the nineteenth consecutive year the Board of
Directors has raised the dividend.
"We are very pleased with the performance of our diversified
portfolio of high-quality, long-life energy infrastructure assets
which produced record financial results again in 2018,” said Russ
Girling, TransCanada’s president and chief executive officer.
“Comparable earnings per share increased twenty-five per cent
compared to 2017 while comparable funds generated from operations
of $6.5 billion were sixteen per cent higher than last year. The
increases reflect the strong performance of our legacy assets,
contributions from approximately $4 billion of growth projects that
were placed into service and the positive impact of U.S. Tax
Reform."
"With our existing asset base expected to benefit from
supportive market fundamentals and $36 billion of secured growth
projects currently underway, approximately $9 billion of which is
commissioning or nearing completion, earnings and cash flow are
forecast to continue to rise. This is expected to support annual
dividend growth of eight to ten per cent through 2021,” added
Girling. “We have invested $13 billion in these projects to date
and are well positioned to fund the remainder of our secured growth
program through significant and growing internally generated cash
flow, access to capital markets and further portfolio management
activities. As outlined in the third quarter, we view the issuance
of common shares under our At-The-Market equity program as being
complete and will continue to evaluate the use of our Dividend
Reinvestment Program on a quarterly basis. We also continue to
progress various portfolio management activities, including the
recently announced sale of our Coolidge generating station which is
expected to close by mid-year. This will allow us to prudently fund
our capital program in a manner that is consistent with achieving
targeted leverage metrics in 2019."
"Looking ahead, we will also continue to carefully advance more
than $20 billion of projects under development including Keystone
XL and the Bruce Power life extension program. Success in advancing
these and other growth initiatives that are expected to emanate
from TransCanada's five operating businesses across North America
could extend our growth outlook well into the next decade,"
concluded Girling.
Highlights(All financial figures are unaudited
and in Canadian dollars unless noted otherwise)
- Fourth quarter 2018 financial results
- Net income attributable to common shares of $1.1 billion or
$1.19 per common share
- Comparable earnings of $946 million or $1.03 per common
share
- Comparable earnings before interest, taxes, depreciation and
amortization of $2.5 billion
- Net cash provided by operations of $2.0 billion
- Comparable funds generated from operations of $1.9 billion
- Comparable distributable cash flow of $1.7 billion or $1.89 per
common share
- For the year ended December 31, 2018
- Net income attributable to common shares of $3.5 billion or
$3.92 per common share
- Comparable earnings of $3.5 billion or $3.86 per common
share
- Comparable earnings before interest, taxes, depreciation and
amortization of $8.6 billion
- Net cash provided by operations of $6.6 billion
- Comparable funds generated from operations of $6.5 billion
- Comparable distributable cash flow of $5.9 billion or $6.52 per
common share
- Fourth quarter highlights
- TransCanada's Board approved an 8.7 per cent increase in the
quarterly common share dividend to $0.75 per common share for the
quarter ending March 31, 2019
- Announced that we will proceed with construction of the $6.2
billion Coastal GasLink pipeline project
- Announced $1.5 billion NGTL 2022 Expansion Program
- Secured transportation contracts for the North Bay Junction
Long Term Fixed Price service on the Canadian Mainline
- Completed the sale of our interests in the Cartier Wind power
facilities for approximately $630 million
- Entered into an agreement to sell our Coolidge generating
station for approximately US$465 million with closing expected to
occur in mid-2019
- Reimbursed for $470 million of Coastal GasLink pre-Final
Investment Decision costs
- In January 2019, announced planned name change to TC Energy
subject to shareholder and regulatory approval
Net income attributable to common shares increased by $231
million or $0.21 per share to $1.1 billion or $1.19 per share for
the three months ended December 31, 2018 compared to the same
period last year primarily due to changes in net income
described below, as well as the dilutive effect of common shares
issued in 2017 and 2018 under our DRP and Corporate ATM program.
Fourth quarter 2018 results included a $143 million after-tax gain
related to the sale of our interests in the Cartier Wind power
facilities; a $115 million deferred income tax recovery from an MLP
regulatory liability write-off resulting from the 2018 FERC
Actions; a $52 million recovery of deferred income taxes as a
result of finalizing the impact of U.S. Tax Reform; a $27 million
income tax recovery related to the sale of our U.S. Northeast power
generation assets; and $25 million of income after tax and after
non-controlling interests recognized on the Bison contract
terminations. These items were partially offset by a $140 million
impairment charge on Bison after tax and after non-controlling
interests; a $15 million goodwill impairment charge on Tuscarora
after tax and after non-controlling interests; and an after-tax net
loss of $7 million related to our U.S. Northeast power marketing
contracts. All of these specific items, as well as unrealized gains
and losses from changes in risk management activities, are excluded
from comparable earnings.
Net income attributable to common shares for the year ended
December 31, 2018 was $3.5 billion or $3.92 per share compared to
$3.0 billion or $3.44 per share in 2017 due to the changes in net
income described below, as well as the dilutive effect of common
shares issued in 2017 and 2018 under our DRP and Corporate ATM
program. Results in 2018 include the items highlighted for fourth
quarter 2018 with a full year after-tax net loss related to our
U.S. Northeast power marketing contracts of $4 million. All of
these specific items, as well as unrealized gains and losses from
changes in risk management activities, are excluded from comparable
earnings.
Comparable EBITDA for fourth quarter 2018 increased by $550
million to $2.5 billion compared to the same period in 2017
primarily due to the net effect of the following:
- higher contribution from Canadian Natural Gas Pipelines
primarily due to the recovery of increased depreciation approved in
both the Mainline NEB 2018 Decision and the NGTL 2018-2019
Settlement, as well as higher flow-through taxes and incentive
earnings
- higher contribution from U.S. Natural Gas Pipelines mainly due
to increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service, additional contract sales on ANR and
Great Lakes, and amortization of net regulatory liabilities
recognized as a result of U.S. Tax Reform
- higher contribution from Liquids Pipelines primarily due to
higher volumes on the Keystone Pipeline System, increased earnings
from liquids marketing activities and earnings from intra-Alberta
pipelines placed in service in the second half of 2017
- higher revenues from Mexico Natural Gas Pipelines as a result
of changes in timing of revenue recognition
- lower earnings from Bruce Power primarily due to lower volumes
resulting from higher outage days.
Comparable earnings for fourth quarter 2018 were $946 million or
$1.03 per common share compared to $719 million or $0.82 per share
for the same period in 2017, an increase of $227 million or $0.21
per share which was primarily the net result of the following:
- changes in comparable EBITDA described above
- higher depreciation primarily in Canadian Natural Gas Pipelines
due to increased depreciation rates approved in the Mainline NEB
2018 Decision and the NGTL 2018-2019 Settlement (these amounts are
fully recovered as reflected in the increase in comparable EBITDA
described above, having no net impact on comparable earnings) as
well as higher depreciation related to new projects placed in
service in 2017 and 2018
- higher interest expense primarily as a result of long-term debt
and junior subordinated notes issuances, net of maturities
- lower interest income and other as a result of realized losses
in 2018 compared to realized gains in 2017 on derivatives used to
manage net exposure to foreign exchange rate fluctuations on U.S.
dollar-denominated income.
Comparable EBITDA in 2018 increased by $1.2 billion to $8.6
billion compared to 2017 primarily due to the net effect of the
following:
- higher contribution from U.S. Natural Gas Pipelines mainly due
to increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service, additional contract sales on ANR and
Great Lakes, and amortization of net regulatory liabilities
recognized as a result of U.S. Tax Reform
- higher contribution from Liquids Pipelines primarily due to
higher volumes on the Keystone Pipeline System, increased earnings
from liquids marketing activities and earnings from intra-Alberta
pipelines placed in service in the second half of 2017
- higher contribution from Canadian Natural Gas Pipelines
primarily due to the recovery of increased depreciation as a result
of higher rates approved in both the Mainline NEB 2018 Decision and
the NGTL 2018-2019 Settlement, as well as higher overall pre-tax
rate base earnings, partially offset by lower incentive earnings
and flow-through income taxes
- lower earnings from U.S. Power mainly due to the sales of our
U.S. Northeast power generation assets in second quarter 2017
- lower earnings from Bruce Power primarily due to lower volumes
resulting from higher outage days and lower results from
contracting activities.
Comparable earnings in 2018 of $3.5 billion or $3.86 per common
share were $790 million or $0.77 per share higher than in 2017. The
2018 increase was primarily the net result of the following:
- changes in comparable EBITDA described above
- higher depreciation primarily in Canadian Natural Gas Pipelines
due to increased depreciation rates approved in the Mainline NEB
2018 Decision and the NGTL 2018-2019 Settlement (these amounts are
fully recovered as reflected in the increase in comparable EBITDA
described above, having no net impact on comparable earnings) as
well as higher depreciation related to new projects placed in
service in 2017 and 2018
- higher interest expense primarily as a result of additional
long-term debt issuances in 2018 and the full year impact of
long-term debt and junior subordinated notes issuances in 2017, net
of maturities, as well as lower capitalized interest, partially
offset by the repayment of the Columbia acquisition bridge
facilities in June 2017
- lower income tax expense primarily due to reduced income tax
rates resulting from U.S. Tax Reform and lower flow-through income
taxes in Canadian rate-regulated pipelines.
Notable recent developments include:
Canadian Natural Gas Pipelines:
- Coastal GasLink Pipeline Project: In October 2018, we announced
that we are proceeding with construction of the Coastal GasLink
pipeline project following the LNG Canada joint venture
participants' announcement that they had reached a positive Final
Investment Decision (FID) to build the LNG Canada natural gas
liquefaction facility in Kitimat, B.C. Coastal GasLink will
provide the natural gas supply to the LNG Canada facility and is
underpinned by 25-year TSAs (with additional renewal provisions)
with each of the five LNG Canada participants. Coastal GasLink will
be a 670 km (416 miles) pipeline with an initial capacity of
approximately 2.2 PJ/d (2.1 Bcf/d) with potential expansion
capacity up to 5.4 PJ/d (5.0 Bcf/d). All necessary regulatory
permits have been received to allow us to proceed with construction
activities which began in December 2018, with a planned in-service
date in 2023. Coastal GasLink has signed project and community
agreements with all 20 elected Indigenous bands along the pipeline
route, confirming strong support from Indigenous communities across
the province of B.C.In July 2018, an individual asked the National
Energy Board (NEB) to consider whether the Coastal GasLink pipeline
should be federally regulated by the NEB. In October 2018, the NEB
advised that it would consider the question of jurisdiction,
granted Coastal GasLink standing in the matter, and reserved the
right to decide on the participation of all other potentially
interested parties, including the individual who raised the
question. In December 2018, the NEB issued a process letter
addressing participation and set the schedule which is expected to
conclude in the second half of 2019, with a decision to follow.The
Coastal GasLink capital cost estimate is $6.2 billion with the
majority of the construction spend occurring in 2020 and 2021.
Subject to terms and conditions, differences between the estimated
capital cost and final cost of the project will be recovered in
future pipeline tolls. As part of the Coastal GasLink funding
plan, we are exploring joint venture partners and project
financing.The total capital cost includes pre-FID costs incurred of
$470 million. In accordance with provisions in the agreements with
the LNG Canada joint venture participants, all five parties elected
to reimburse us for their share of pre-FID costs, totaling $470
million, in November 2018. In addition, in January 2019, all five
partners elected to make cash payments throughout the construction
period with respect to carrying charges on costs incurred.
- NGTL System: In October 2018, we announced the NGTL System 2022
Expansion Program to meet capacity requirements for incremental
firm receipt and intra-basin delivery services to commence in
November 2021 and April 2022. This $1.5 billion expansion of the
NGTL System consists of approximately 197 km (122 miles) of new
pipeline, three compressor units, meter stations and associated
facilities. Applications for approvals to construct and operate the
facilities are expected to be filed with the NEB in second quarter
2019 and, pending receipt of regulatory approvals, construction
would start as early as third quarter 2020. The NGTL capital
program, excluding maintenance capital expenditures, is now
approximately $8.6 billion.
- Canadian Mainline: In December 2018, we announced the
North Bay Junction Long Term Fixed Price service (NBJ LTFP) which
includes 670 TJ/d (625 MMcf/d) of new natural gas transportation
contracts from the Western Canadian Sedimentary Basin (WCSB) on the
Canadian Mainline. Upon NEB approval of the NBJ LTFP service,
incremental volumes under these long-term, fixed-priced contracts
will reach markets in Ontario, Québec, New Brunswick, Nova Scotia
and the Northeastern U.S. using existing capacity on the Canadian
Mainline as well as new compression facilities. Customers have
executed 15-year precedent agreements to proceed with the project
with an estimated capital cost of $96 million. We filed an
application for approval of the NBJ LTFP with the NEB in January
2019 and expect a decision in third quarter 2019.In October 2018,
we concluded the written hearing process for the Canadian Mainline
2018-2020 toll review with the filing of our reply evidence to the
NEB. In December 2018, the NEB 2018 Decision was issued approving
all elements of the application, including our cost and volume
forecasts, higher depreciation rates and continuation of pricing
discretion, with the exception of the amortization period for the
Long Term Adjustment Account (LTAA), which is now to be amortized
over 2018 to 2020. The impact of the decision was reflected in
lower tolls effective February 1, 2019. As directed by the NEB, we
filed a compliance filing in January 2019, the outcome of which is
expected in first quarter 2019.
U.S. Natural Gas Pipelines:
- WB XPress: The WB XPress project, a Columbia Gas project
designed to transport approximately 1.4 PJ/d (1.3 Bcf/d) of
Marcellus gas supply westbound to the Gulf Coast and eastbound to
Mid-Atlantic Markets, was placed in service in October 2018 and
November 2018 for the Western Build and Eastern Build,
respectively.
- Mountaineer XPress and Gulf XPress: Mountaineer XPress (MXP), a
Columbia Gas project, is designed to transport supply from the
Marcellus and Utica shale plays to points along the system and to
the Leach interconnect with Columbia Gulf. Approximately 45 per
cent of this project was placed in service on January 18, 2019,
with the remainder to be placed in service in February and March
2019, along with Gulf XPress, a Columbia Gulf project. Total
estimated MXP project costs have been revised upwards to US$3.2
billion reflecting the impact of delays of various regulatory
approvals from FERC and other agencies, increased contractor
construction costs due to unusually high demand for construction
resources in the region, unusually high instances of inclement
weather throughout construction, and modifications to contractor
work plans to mitigate construction delays associated with these
impacts.
- Louisiana XPress: In November 2018, we sanctioned the Louisiana
XPress project which will connect supply directly to Gulf Coast LNG
export markets with the addition of three greenfield mid-point
compressor stations along Columbia Gulf. The anticipated in-service
date is in 2022 and estimated project costs are US$0.4
billion.
- Bison contract terminations and asset impairment: In the second
half of 2018, two customers on Bison elected to pay out the
remainder of their future contracted revenues and terminate their
associated TSAs. The termination of these agreements was agreed to
following the receipt of US$97 million in 2018, which was recorded
in Revenues, as the terminations released us from providing any
future services. This development, coupled with the persistence of
unfavourable market conditions which have inhibited system flows on
the pipeline, led us to determine that the asset’s remaining
carrying value was no longer recoverable and a non-cash impairment
charge of US$537 million was recorded in our U.S. Natural Gas
Pipelines segment. As Bison is a TC PipeLines, LP asset, in which
we have a 25.5 per cent interest, this impairment charge impacts
our net income by $140 million after tax and non-controlling
interests, but is excluded from comparable earnings. We continue to
explore alternative transportation-related options for Bison.
- Tuscarora goodwill impairment: In fourth quarter 2018,
Tuscarora finalized its regulatory approach in response to the 2018
FERC Actions, resulting in a reduction in its recourse rates. In
connection with its annual goodwill impairment analysis, we
evaluated Tuscarora’s future revenues as well as changes to other
assumptions responsive to Tuscarora’s commercial environment. In
doing so, we incorporated the outcome of a settlement-in-principle
reached with its customers in January 2019. As a result of these
developments, we determined that the fair value of Tuscarora did
not exceed its carrying value, including goodwill, and recorded a
goodwill impairment charge of US$59 million within the U.S. Natural
Gas Pipelines segment. The remaining goodwill balance related to
Tuscarora at December 31, 2018 was US$23 million. As Tuscarora is a
TC PipeLines, LP asset, in which we have a 25.5 per cent interest,
this impairment charge impacts our net income by $15 million after
tax and non-controlling interests, but is excluded from comparable
earnings.
Mexico Natural Gas Pipelines:
- Sur de Texas: Offshore construction was completed in May 2018
and the project continues to progress toward an anticipated
in-service date in early second quarter 2019. An amending agreement
was signed with the CFE that recognizes force majeure events and
the commencement of payments of fixed capacity charges began on
October 31, 2018.
Liquids Pipelines:
- Keystone XL: We have secured commercial support for all
available Keystone XL project capacity and commenced certain
pre-construction activities. We continue to address outstanding
legal challenges regarding the project. The South Dakota Supreme
Court dismissed an appeal against the certification of the project.
We expect the Nebraska Supreme Court to reach a decision in the
first quarter of 2019 regarding a challenge to the Nebraska Public
Service Commission’s route approval. We continue to participate,
together with the U.S. Department of Justice, in lawsuits commenced
in Montana to defend legal challenges to the U.S. Presidential
Permit and the exhaustive environmental assessments that support
the U.S. President’s actions.
Energy:
- Cartier Wind: In October 2018, we completed the sale of our
interests in the Cartier Wind power facilities in Québec to
Innergex Renewable Energy Inc. for gross proceeds of approximately
$630 million before closing adjustments, resulting in a gain of
$170 million ($143 million after tax).
- Coolidge Generating Station: On December 14, 2018, we entered
into an agreement to sell our Coolidge generating station in
Arizona to SWG Coolidge Holdings, LLC, for approximately US$465
million, subject to timing of the close and related adjustments.
Salt River Project Agriculture Improvement and Power District, the
PPA counterparty, exercised its contractual right of first refusal
on a sale to a third party in January 2019. The sale will result in
an estimated gain of approximately $65 million ($50 million after
tax) to be recognized upon closing of the sale transaction which is
expected to occur mid-2019.
- Napanee: Construction is substantially complete and
commissioning activities are continuing at our 900 MW natural
gas-fired power plant in eastern Ontario in the town of Greater
Napanee. We expect our total investment in the Napanee facility
will be approximately $1.7 billion with commercial operations
expected to begin in second quarter 2019.
Corporate:
- Common Share Dividend: Our Board of Directors declared a
quarterly dividend of $0.75 per share for the quarter ending March
31, 2019 on TransCanada's outstanding common shares. This
represents an increase in the dividend of 8.7 per cent from the
previous dividend and is equivalent to $3.00 per common share on an
annualized basis.
- Issuance of Long-term Debt: In fourth quarter 2018, TCPL issued
US$1.0 billion of Senior Unsecured Notes due in March 2049 bearing
interest at a fixed rate of 5.10 per cent and US$400 million of
Senior Unsecured Notes due in May 2028 bearing interest at a fixed
rate of 4.25 per cent.The net proceeds of the debt issuances were
used for general corporate purposes, to fund our capital program
and to pre-fund early 2019 senior note maturities.
- Dividend Reinvestment Plan: In 2018, the DRP participation rate
by common shareholders was approximately 35 per cent, resulting in
$870 million reinvested in common equity under the program.
- ATM Equity Program: In 2018, 20 million common shares were
issued under the Corporate ATM program at an average price of
$56.13 per common share for proceeds of $1.1 billion, net of
approximately $10 million of related commissions and fees. We view
the issuance of common shares under this program as being
complete.
- Proposed Name Change: On January 9, 2019, we announced our
intention to change our name to TC Energy to better reflect the
scope of the company's operations as a leading North American
energy infrastructure company. The name change is subject to
shareholder and regulatory approval and would be effective
immediately following the Annual and Special Meeting of
Shareholders in the second quarter of 2019.
- Management Changes: Karl Johannson and Kristine Delkus will be
retiring from the Company in the first and second quarters of 2019,
respectively. Effective January 1, 2019, Tracy Robinson was
appointed Executive Vice-President and President, Canadian Natural
Gas Pipelines and Francois Poirier was appointed to the expanded
role of President of the Energy and Mexico Natural Gas Pipelines
business units in addition to his role as Executive Vice-President,
Strategy and Corporate Development.
Teleconference and Webcast:
We will hold a teleconference and webcast on Thursday, February
14, 2019 to discuss our fourth quarter 2018 and year-end financial
results. Russ Girling, President and Chief Executive Officer, and
Don Marchand, Executive Vice-President and Chief Financial Officer,
along with other members of the TransCanada executive leadership
team, will discuss the financial results and Company developments
at 2 p.m. (MT) / 4 p.m. (ET).
Members of the investment community and other interested parties
are invited to participate by calling 800.273.9672 or 416.340.2216
(Toronto area). Please dial in 10 minutes prior to the start of the
call. No pass code is required. A live webcast of the
teleconference will be available at www.transcanada.com or via
the following URL: www.gowebcasting.com/9855.
A replay of the teleconference will be available two hours after
the conclusion of the call until midnight (ET) on February 21,
2019. Please call 800.408.3053 or 905.694.9451 (Toronto area) and
enter pass code 4856336#.
The audited annual Consolidated Financial Statements and
Management’s Discussion and Analysis (MD&A) are available under
TransCanada's profile on SEDAR at www.sedar.com,
with the U.S. Securities and Exchange Commission on EDGAR
at www.sec.gov/info/edgar.shtml and on the
TransCanada website at
www.transcanada.com.
With more than 65 years' experience, TransCanada is a leader in
the responsible development and reliable operation of North
American energy infrastructure including natural gas and liquids
pipelines, power generation and gas storage facilities. TransCanada
operates one of the largest natural gas transmission networks that
extends more than 92,600 kilometres (57,500 miles), connecting
major gas supply basins to markets across North America.
TransCanada is a leading provider of gas storage and related
services with 653 billion cubic feet of storage capacity. A large
independent power producer, TransCanada currently owns or has
interests in more than 6,600 megawatts of power generation in
Canada and the United States. TransCanada is also the developer and
operator of one of North America's leading liquids pipeline systems
that extends approximately 4,900 kilometres (3,000 miles),
connecting growing continental oil supplies to key markets and
refineries. TransCanada's common shares trade on the Toronto and
New York stock exchanges under the symbol TRP. Visit
www.transcanada.com to learn more, or connect with us on
social media.
Forward Looking Information:
This release contains certain information that is
forward-looking and is subject to important risks and uncertainties
(such statements are usually accompanied by words such as
"anticipate", "expect", "believe", "may", "will", "should",
"estimate", "intend" or other similar words). Forward-looking
statements in this document are intended to provide TransCanada
security holders and potential investors with information regarding
TransCanada and its subsidiaries, including management's assessment
of TransCanada's and its subsidiaries' future plans and financial
outlook. All forward-looking statements reflect TransCanada's
beliefs and assumptions based on information available at the time
the statements were made and as such are not guarantees of future
performance. Readers are cautioned not to place undue reliance on
this forward-looking information, which is given as of the date it
is expressed in this news release, and not to use future-oriented
information or financial outlooks for anything other than their
intended purpose. TransCanada undertakes no obligation to update or
revise any forward-looking information except as required by law.
For additional information on the assumptions made, and the risks
and uncertainties which could cause actual results to differ from
the anticipated results, refer to the Quarterly Report to
Shareholders dated February 13, 2019 and the 2018 Annual Report
filed under TransCanada's profile on SEDAR at
www.sedar.com and with the U.S. Securities and Exchange
Commission at www.sec.gov.
Non-GAAP Measures:
This news release contains references to non-GAAP measures,
including comparable earnings, comparable earnings per common
share, comparable EBITDA, comparable distributable cash flow,
comparable distributable cash flow per common share and comparable
funds generated from operations, that do not have any standardized
meaning as prescribed by U.S. GAAP and therefore are unlikely to be
comparable to similar measures presented by other companies. These
non-GAAP measures are calculated on a consistent basis from period
to period except as otherwise described in the MD&A included in
our Quarterly Report to Shareholders dated February 13, 2019 and
are adjusted for specific items in each period, as applicable. For
more information on non-GAAP measures, refer to TransCanada's
Quarterly Report to Shareholders dated February 13, 2019.
Media Enquiries:Grady Semmens403.920.7859 or
800.608.7859
Investor & Analyst
Enquiries: David Moneta / Duane
Alexander403.920.7911 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 INFORMATIONWe disclose
forward-looking information to help current and potential investors
understand management’s assessment of our future plans and
financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain
assumptions and on what we know and expect today and generally
include words like anticipate, expect, believe, may, will, should,
estimate or other similar words.
Forward-looking statements in this news release include
information about the following, among other things:
- our financial and operational performance, including the
performance of our subsidiaries
- expectations about strategies and goals for growth and
expansion
- expected cash flows and future financing options available,
including portfolio management
- expected dividend growth
- expected future credit ratings
- expected costs and schedules for planned projects, including
projects under construction and in development
- expected capital expenditures and contractual obligations
- expected regulatory processes and outcomes, including the
impact of the 2018 FERC Actions
- expected outcomes with respect to legal proceedings, including
arbitration and insurance claims
- the expected impact of future accounting changes, commitments
and contingent liabilities
- expected industry, market and economic conditions.
Forward-looking statements do not guarantee future performance.
Actual events and results could be significantly different because
of assumptions, risks or uncertainties related to our business or
events that happen after the date of this news release.
Our forward-looking information is based on the following key
assumptions, and subject to the following risks and
uncertainties:
Assumptions
- regulatory decisions and outcomes, including final outcomes of
the 2018 FERC Actions
- planned and unplanned outages and the use of our pipeline and
energy assets
- integrity and reliability of our assets
- anticipated construction costs, schedules and completion
dates
- access to capital markets, including portfolio management
- expected industry, market and economic conditions
- inflation rates and commodity prices
- interest, tax and foreign exchange rates
- nature and scope of hedging.
Risks and uncertainties
- our ability to successfully implement our strategic priorities
and whether they will yield the expected benefits
- our ability to implement a capital allocation strategy aligned
with maximizing shareholder value
- the operating performance of our pipeline and energy
assets
- amount of capacity sold and rates achieved in our pipeline
businesses
- the amount of capacity payments and revenues from our energy
business due to plant availability
- production levels within supply basins
- construction and completion of capital projects
- costs for labour, equipment and materials
- the availability and market prices of commodities
- access to capital markets on competitive terms
- interest, tax and foreign exchange rates
- performance and credit risk of our counterparties
- regulatory decisions and outcomes of legal proceedings,
including arbitration and insurance claims
- changes in environmental and other laws and regulations
- competition in the pipeline and energy sectors
- unexpected or unusual weather
- acts of civil disobedience
- cyber security and technological developments
- economic conditions in North America as well as globally
- our ability to effectively anticipate and assess changes to
government policies and regulations.
You can read more about these factors in other reports we have
filed with Canadian securities regulators and the SEC, including
the MD&A in our 2018 Annual Report.
As actual results could vary significantly from the
forward-looking information, you should not put undue reliance on
forward-looking information and should not use future-oriented
information or financial outlooks for anything other than their
intended purpose. We do not update our forward-looking statements
due to new information or future events, unless we are required to
by law.
FOR MORE INFORMATIONYou 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 MEASURESThis news release references
the following non-GAAP measures:
- comparable EBITDA
- comparable EBIT
- comparable earnings
- comparable earnings per common share
- funds generated from operations
- comparable funds generated from operations
- comparable distributable cash flow
- comparable distributable cash flow per common share.
These measures do not have any standardized meaning as
prescribed by GAAP and therefore may not be comparable to similar
measures presented by other entities.
Comparable measuresWe calculate comparable
measures by adjusting certain GAAP measures for specific items we
believe are significant but not reflective of our underlying
operations in the period. Except as otherwise described herein,
these comparable measures are calculated on a consistent basis from
period to period and are adjusted for specific items in each
period, as applicable.
Our decision not to adjust for a specific item is subjective and
made after careful consideration. Specific items may include:
- certain fair value adjustments relating to risk management
activities
- income tax refunds and adjustments to enacted tax rates
- gains or losses on sales of assets or assets held for sale
- legal, contractual and bankruptcy settlements
- impact of regulatory or arbitration decisions relating to prior
year earnings
- restructuring costs
- impairment of goodwill, investments and other assets including
certain ongoing maintenance and liquidation costs
- acquisition and integration costs.
We exclude the unrealized gains and losses from changes in the
fair value of derivatives used to reduce our exposure to certain
financial and commodity price risks. These derivatives generally
provide effective economic hedges, but do not meet the criteria for
hedge accounting. As a result, the changes in fair value are
recorded in net income. As these amounts do not accurately reflect
the gains and losses that will be realized at settlement, we do not
consider them reflective of our underlying operations.
The following table identifies our non-GAAP measures and their
most directly comparable GAAP measures.
Non-GAAP measure |
GAAP measure |
|
|
comparable EBITDA |
segmented earnings |
comparable EBIT |
segmented earnings |
comparable
earnings |
net income attributable
to common shares |
comparable earnings per
common share |
net income per common
share |
comparable funds
generated from operations |
net cash provided by
operations |
comparable distributable cash flow |
net cash
provided by operations |
Comparable EBITDA and comparable EBITComparable
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
shareComparable 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 operationsFunds 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 shareWe believe
comparable distributable cash flow is a useful supplemental measure
of performance that defines cash available to common shareholders
before capital allocation. Comparable distributable cash flow is
defined as comparable funds generated from operations less
preferred share dividends, distributions to non-controlling
interests and non-recoverable maintenance capital expenditures.
Refer to the Cash provided by operating activities section for a
reconciliation to net cash provided by operations.
Maintenance capital expenditures are expenditures incurred to
maintain our operating capacity, asset integrity and reliability,
and include amounts attributable to our proportionate share of
maintenance capital expenditures on our equity investments. We
have the opportunity to recover effectively all of our pipeline
maintenance capital expenditures in Canadian Natural Gas Pipelines,
U.S. Natural Gas Pipelines and Liquids Pipelines through tolls.
Canadian natural gas pipelines maintenance capital expenditures are
included in rate bases, on which we earn a regulated return and
subsequently recover in tolls. Our U.S. natural gas pipelines can
recover maintenance capital expenditures through tolls under
current rate settlements, or have the ability to recover such
expenditures through tolls established in future rate cases or
settlements. Tolling arrangements in our liquids pipelines provide
for the recovery of maintenance capital expenditures. As such, in
2018 our presentation of comparable distributable cash flow and
comparable distributable cash flow per common share only includes a
reduction for non-recoverable maintenance capital expenditures in
their respective calculations. We have adjusted our comparable
distributable cash flow and comparable distributable cash flow per
common share for 2017 to reflect the amended presentation format
which we believe provides better information for readers.
Consolidated results - fourth quarter 2018
We operate in three core businesses - Natural Gas Pipelines,
Liquids Pipelines and Energy. In order to provide information that
is aligned with how management decisions about our businesses are
made and how performance of our businesses is assessed, our results
are reflected in five operating segments: Canadian Natural Gas
Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas
Pipelines, Liquids Pipelines and Energy. We also have a Corporate
segment, consisting of corporate and administrative functions that
provide governance and other support to our operational business
segments.
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of $,
except per share amounts) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Segmented
earnings/(losses) |
|
|
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
|
450 |
|
|
|
333 |
|
|
|
1,250 |
|
|
|
1,236 |
|
U.S. Natural Gas
Pipelines |
|
|
(34 |
) |
|
|
461 |
|
|
|
1,700 |
|
|
|
1,760 |
|
Mexico Natural Gas
Pipelines |
|
|
128 |
|
|
|
93 |
|
|
|
510 |
|
|
|
426 |
|
Liquids Pipelines |
|
|
532 |
|
|
|
(932 |
) |
|
|
1,579 |
|
|
|
(251 |
) |
Energy |
|
|
315 |
|
|
|
472 |
|
|
|
779 |
|
|
|
1,552 |
|
Corporate |
|
|
23 |
|
|
|
63 |
|
|
|
(54 |
) |
|
|
(39 |
) |
Total segmented
earnings |
|
|
1,414 |
|
|
|
490 |
|
|
|
5,764 |
|
|
|
4,684 |
|
Interest expense |
|
|
(603 |
) |
|
|
(541 |
) |
|
|
(2,265 |
) |
|
|
(2,069 |
) |
Allowance for funds
used during construction |
|
|
161 |
|
|
|
140 |
|
|
|
526 |
|
|
|
507 |
|
Interest
income and other |
|
|
(215 |
) |
|
|
(9 |
) |
|
|
(76 |
) |
|
|
184 |
|
Income before
income taxes |
|
|
757 |
|
|
|
80 |
|
|
|
3,949 |
|
|
|
3,306 |
|
Income
tax (expense)/recovery |
|
|
(38 |
) |
|
|
870 |
|
|
|
(432 |
) |
|
|
89 |
|
Net
income |
|
|
719 |
|
|
|
950 |
|
|
|
3,517 |
|
|
|
3,395 |
|
Net
loss/(income) attributable to non-controlling interests |
|
|
414 |
|
|
|
(49 |
) |
|
|
185 |
|
|
|
(238 |
) |
Net income
attributable to controlling interests |
|
|
1,133 |
|
|
|
901 |
|
|
|
3,702 |
|
|
|
3,157 |
|
Preferred
share dividends |
|
|
(41 |
) |
|
|
(40 |
) |
|
|
(163 |
) |
|
|
(160 |
) |
Net income attributable to common shares |
|
|
1,092 |
|
|
|
861 |
|
|
|
3,539 |
|
|
|
2,997 |
|
Net income per
common share — basic |
|
$1.19 |
|
|
$0.98 |
|
|
$3.92 |
|
|
$3.44 |
|
— diluted |
|
$1.19 |
|
|
$0.98 |
|
|
$3.92 |
|
|
$3.43 |
|
Net income attributable to common shares increased by $231
million or $0.21 per common share for the three months ended
December 31, 2018 compared to the same period in
2017 primarily due to changes in net income described below,
as well as the dilutive impact of common shares issued in 2017 and
2018 under our DRP and Corporate ATM program.
Fourth quarter 2018 results included:
- a $143 million after-tax gain related to the sale of our
interests in the Cartier Wind power facilities
- a $115 million deferred income tax recovery from an MLP
regulatory liability write-off resulting from the 2018 FERC
Actions
- a $52 million recovery of deferred income taxes as a result of
finalizing the impact of U.S. Tax Reform
- a $27 million income tax recovery related to the sale of our
U.S. Northeast power generation assets
- $25 million of after-tax income recognized on the Bison
contract terminations
- a $140 million after-tax impairment charge on Bison
- a $15 million after-tax goodwill impairment charge on
Tuscarora
- an after-tax net loss of $7 million related to our U.S.
Northeast power marketing contracts.
Fourth quarter 2017 results included:
- an $804 million recovery of deferred income taxes as a result
of U.S. Tax Reform
- a $136 million after-tax gain related to the sale of our
Ontario solar assets
- a $64 million net after-tax gain related to the monetization of
our U.S. Northeast power generation assets
- a $954 million after-tax impairment charge for the Energy East
pipeline and related projects as a result of our decision not to
proceed with the project applications
- a $9 million after-tax charge related to the maintenance and
liquidation of Keystone XL assets.
Net income in both periods included unrealized gains and losses
from changes in risk management activities, which we exclude, along
with the above noted items, to arrive at comparable earnings.A
reconciliation of net income attributable to common shares to
comparable earnings is shown in the following table.
RECONCILIATION OF NET INCOME TO COMPARABLE
EARNINGS
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of $,
except per share amounts) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Net income
attributable to common shares |
|
|
1,092 |
|
|
|
861 |
|
|
|
3,539 |
|
|
|
2,997 |
|
Specific items
(net of tax): |
|
|
|
|
|
|
|
|
Gain on
sale of Cartier Wind power facilities |
|
|
(143 |
) |
|
|
— |
|
|
|
(143 |
) |
|
|
— |
|
MLP
regulatory liability write-off |
|
|
(115 |
) |
|
|
— |
|
|
|
(115 |
) |
|
|
— |
|
U.S. Tax
Reform |
|
|
(52 |
) |
|
|
(804 |
) |
|
|
(52 |
) |
|
|
(804 |
) |
Net gain
on sales of U.S. Northeast power generation assets |
|
|
(27 |
) |
|
|
(64 |
) |
|
|
(27 |
) |
|
|
(307 |
) |
Bison
contract terminations |
|
|
(25 |
) |
|
|
— |
|
|
|
(25 |
) |
|
|
— |
|
Bison
asset impairment |
|
|
140 |
|
|
|
— |
|
|
|
140 |
|
|
|
— |
|
Tuscarora
goodwill impairment |
|
|
15 |
|
|
|
— |
|
|
|
15 |
|
|
|
— |
|
U.S.
Northeast power marketing contracts |
|
|
7 |
|
|
|
— |
|
|
|
4 |
|
|
|
— |
|
Gain on
sale of Ontario solar assets |
|
|
— |
|
|
|
(136 |
) |
|
|
— |
|
|
|
(136 |
) |
Energy
East impairment charge |
|
|
— |
|
|
|
954 |
|
|
|
— |
|
|
|
954 |
|
Keystone
XL asset costs |
|
|
— |
|
|
|
9 |
|
|
|
— |
|
|
|
28 |
|
Keystone
XL income tax recoveries |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(7 |
) |
Integration and acquisition related costs – Columbia |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
69 |
|
Risk management activities1 |
|
|
54 |
|
|
|
(101 |
) |
|
|
144 |
|
|
|
(104 |
) |
Comparable earnings |
|
|
946 |
|
|
|
719 |
|
|
|
3,480 |
|
|
|
2,690 |
|
Net income per
common share |
|
$1.19 |
|
|
$0.98 |
|
|
$3.92 |
|
|
$3.44 |
|
Specific items
(net of tax): |
|
|
|
|
|
|
|
|
Gain on
sale of Cartier Wind power facilities |
|
|
(0.16 |
) |
|
|
— |
|
|
|
(0.16 |
) |
|
|
— |
|
MLP
regulatory liability write-off |
|
|
(0.13 |
) |
|
|
— |
|
|
|
(0.13 |
) |
|
|
— |
|
U.S. Tax
Reform |
|
|
(0.06 |
) |
|
|
(0.92 |
) |
|
|
(0.06 |
) |
|
|
(0.92 |
) |
Net gain
on sales of U.S. Northeast power generation assets |
|
|
(0.03 |
) |
|
|
(0.08 |
) |
|
|
(0.03 |
) |
|
|
(0.34 |
) |
Bison
contract terminations |
|
|
(0.03 |
) |
|
|
— |
|
|
|
(0.03 |
) |
|
|
— |
|
Bison
asset impairment |
|
|
0.16 |
|
|
|
— |
|
|
|
0.16 |
|
|
|
— |
|
Tuscarora
goodwill impairment |
|
|
0.02 |
|
|
|
— |
|
|
|
0.02 |
|
|
|
— |
|
U.S.
Northeast power marketing contracts |
|
|
0.01 |
|
|
|
— |
|
|
|
0.01 |
|
|
|
— |
|
Gain on
sale of Ontario solar assets |
|
|
— |
|
|
|
(0.16 |
) |
|
|
— |
|
|
|
(0.16 |
) |
Energy
East impairment charge |
|
|
— |
|
|
|
1.09 |
|
|
|
— |
|
|
|
1.09 |
|
Keystone
XL asset costs |
|
|
— |
|
|
|
0.01 |
|
|
|
— |
|
|
|
0.03 |
|
Keystone
XL income tax recoveries |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(0.01 |
) |
Integration and acquisition related costs – Columbia |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
0.08 |
|
Risk management activities1 |
|
|
0.06 |
|
|
|
(0.10 |
) |
|
|
0.16 |
|
|
|
(0.12 |
) |
Comparable earnings per common share |
|
$1.03 |
|
|
$0.82 |
|
|
$3.86 |
|
|
$3.09 |
|
1 |
|
Risk management activities |
|
three months ended December 31 |
|
year ended December 31 |
|
|
(millions of
$) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids marketing |
|
81 |
|
|
15 |
|
|
71 |
|
|
— |
|
|
|
Canadian Power |
|
— |
|
|
6 |
|
|
3 |
|
|
11 |
|
|
|
U.S. Power |
|
20 |
|
|
136 |
|
|
(11 |
) |
|
39 |
|
|
|
Natural Gas
Storage |
|
(5 |
) |
|
7 |
|
|
(11 |
) |
|
12 |
|
|
|
Interest rate |
|
— |
|
|
— |
|
|
— |
|
|
(1 |
) |
|
|
Foreign exchange |
|
(169 |
) |
|
(1 |
) |
|
(248 |
) |
|
88 |
|
|
|
Income tax attributable
to risk management activities |
|
19 |
|
|
(62 |
) |
|
52 |
|
|
(45 |
) |
|
|
Total unrealized (losses)/gains from risk management
activities |
|
(54 |
) |
|
101 |
|
|
(144 |
) |
|
104 |
|
COMPARABLE EBITDA TO COMPARABLE
EARNINGSComparable 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
2017Comparable EBITDA increased by $550 million for the
three months ended December 31, 2018 compared to the same
period in 2017 primarily due to the net effect of the
following:
- higher contribution from Canadian Natural Gas Pipelines
primarily due to the recovery of increased depreciation as a result
of higher rates approved in both the Mainline NEB 2018 Decision and
the NGTL 2018-2019 Settlement, as well as higher flow-through taxes
and incentive earnings
- higher contribution from U.S. Natural Gas Pipelines mainly due
to increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service, additional contract sales on ANR and
Great Lakes, and amortization of net regulatory liabilities
recognized as a result of U.S. Tax Reform
- higher contribution from Liquids Pipelines primarily due to
higher volumes on the Keystone Pipeline System, increased earnings
from liquids marketing activities and earnings from intra-Alberta
pipelines placed in service in the second half of 2017
- higher revenues from Mexico Natural Gas Pipelines as a result
of changes in timing of revenue recognition
- lower earnings from Bruce Power primarily due to lower volumes
resulting from higher outage days.
Comparable earnings increased by $227 million or $0.21 per
common share for the three months ended December 31, 2018
compared to the same period in 2017 and was primarily the net
effect of:
- changes in comparable EBITDA described above
- higher depreciation primarily in Canadian Natural Gas Pipelines
due to increased depreciation rates approved in the Mainline NEB
2018 Decision and the NGTL 2018-2019 Settlement (these amounts are
fully recovered as reflected in the increase in comparable EBITDA
described above, having no net impact on comparable earnings) as
well as higher depreciation related to new projects placed in
service in 2017 and 2018
- higher interest expense primarily as a result of long-term debt
and junior subordinated notes issuances, net of maturities
- lower interest income and other as a result of realized losses
in 2018 compared to realized gains in 2017 on derivatives used to
manage net exposure to foreign exchange rate fluctuations on U.S.
dollar-denominated income.
Comparable earnings per common share for the three months ended
December 31, 2018 also reflect the dilutive impact of common
shares issued in 2017 and 2018 under our DRP and our Corporate ATM
program.
2018 FERC Actions and U.S. Tax Reform
In fourth quarter 2018, the following significant developments
with respect to 2018 FERC Actions and U.S. Tax Reform took
place:
- On November 15, 2018, FERC issued a Policy Statement on the
Accounting and Ratemaking Treatment of Accumulated Deferred
Income Taxes (ADIT) and Treatment Following the Sale or Retirement
of an Asset, a policy statement (Excess ADIT Policy Statement)
addressing certain issues raised in the Notice of Inquiry (NOI)
issued on March 15, 2018. The Excess ADIT Policy Statement
clarifies FERC accounts in which pipelines should record
amortization of excess and/or deficient ADIT for FERC reporting and
ratemaking purposes. The Excess ADIT Policy Statement also
addresses how to disclose reversals of ADIT account balances in
FERC’s annual financial report filings
- In accordance with the Form 501-G filings and settlements
reached with customers in response to the 2018 FERC Actions, the
ADIT balances for all pipelines held wholly or in part by TC
PipeLines, LP were eliminated from their respective rate bases.
Therefore, regulatory liabilities recorded for these assets
pursuant to U.S. Tax Reform were written off, resulting in a
deferred income tax recovery of $115 million in fourth quarter
2018
- All of our FERC-regulated natural gas pipelines and storage
assets have now either filed a Form 501-G or an uncontested rate
settlement with FERC as directed. There has been no significant
incremental impact from our third quarter 2018 disclosures
regarding the effect of 2018 FERC Actions on future earnings and
cash flows
- Upon finalizing the 2017 annual tax returns for our U.S.
businesses and clarifying the impact of U.S. Tax Reform on our
deferred income tax liability at December 31, 2017, and as
permitted by the SEC during the one-year measurement period, it was
determined that an adjustment was required to the estimate
originally recorded. Accordingly, a deferred income tax recovery of
$52 million was recognized in fourth quarter 2018 to adjust our net
regulatory liability and ADIT balances.
Capital Program
We are developing quality projects under our capital program.
These long-life infrastructure assets are supported by long-term
commercial arrangements with creditworthy counterparties or
regulated business models and are expected to generate significant
growth in earnings and cash flows.
Our $57 billion capital program consists of approximately $36.6
billion of secured projects and approximately $20.7 billion of
projects under development. Our secured projects include
commercially supported, committed projects that are either under
construction or are in or preparing to commence the permitting
stage, but are not yet fully approved. Our projects under
development are commercially supported except where noted, but have
greater uncertainty with respect to timing and estimated project
costs and are subject to certain approvals.
Three years of maintenance capital expenditures for our
businesses are included in the secured projects table. Maintenance
capital expenditures on our regulated Canadian and U.S. natural gas
pipeline businesses are added to rate base on which we have the
opportunity to earn a return and recover these expenditures through
current or future tolls, which is similar to our capacity capital
projects on these pipelines. Tolling arrangements in our liquids
pipelines business provide for the recovery of maintenance capital
expenditures.
All projects are subject to cost adjustments due to weather,
market conditions, route refinement, permitting conditions,
scheduling and timing of regulatory permits, among other factors.
Amounts presented in the following tables exclude capitalized
interest and AFUDC.
Secured projects
|
|
Expectedin-service
date |
|
Estimatedproject
cost1 |
|
Carrying value
atDecember 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 developmentThe 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.
|
|
Estimatedproject
cost1 |
|
Carrying value
atDecember 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 EBITDAComparable 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 AMORTIZATIONDepreciation and
amortization increased by $132 million for the three months ended
December 31, 2018 compared to the same period in 2017 mainly
due to the increase in depreciation rates approved in the Mainline
NEB 2018 Decision and the NGTL 2018-2019 Settlement, as well as
NGTL System facilities that were placed in service in 2018.
U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of US$,
unless noted otherwise) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Columbia Gas |
|
236 |
|
|
177 |
|
|
873 |
|
|
623 |
|
ANR |
|
138 |
|
|
99 |
|
|
508 |
|
|
400 |
|
TC PipeLines,
LP1,2 |
|
36 |
|
|
31 |
|
|
138 |
|
|
118 |
|
Midstream |
|
21 |
|
|
23 |
|
|
122 |
|
|
93 |
|
Columbia Gulf |
|
30 |
|
|
21 |
|
|
120 |
|
|
76 |
|
Great Lakes2,3 |
|
23 |
|
|
15 |
|
|
97 |
|
|
64 |
|
Other U.S.
pipelines1,2,4 |
|
18 |
|
|
16 |
|
|
68 |
|
|
80 |
|
Non-controlling
interests5 |
|
111 |
|
|
93 |
|
|
415 |
|
|
359 |
|
Comparable EBITDA |
|
613 |
|
|
475 |
|
|
2,341 |
|
|
1,813 |
|
Depreciation and amortization |
|
(131 |
) |
|
(113 |
) |
|
(511 |
) |
|
(453 |
) |
Comparable
EBIT |
|
482 |
|
|
362 |
|
|
1,830 |
|
|
1,360 |
|
Foreign
exchange impact |
|
155 |
|
|
99 |
|
|
541 |
|
|
410 |
|
Comparable
EBIT (Cdn$) |
|
637 |
|
|
461 |
|
|
2,371 |
|
|
1,770 |
|
Specific item: |
|
|
|
|
|
|
|
|
Bison
asset impairment6 |
|
(722 |
) |
|
— |
|
|
(722 |
) |
|
— |
|
Tuscarora
goodwill impairment6 |
|
(79 |
) |
|
— |
|
|
(79 |
) |
|
— |
|
Bison
contract terminations6 |
|
130 |
|
|
— |
|
|
130 |
|
|
— |
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
— |
|
|
— |
|
|
(10 |
) |
Segmented (losses)/earnings (Cdn$) |
|
(34 |
) |
|
461 |
|
|
1,700 |
|
|
1,760 |
|
1 Results reflect our earnings from TC PipeLines, LP's ownership
interests in GTN, Great Lakes, Iroquois, Northern Border, Bison,
Portland, North Baja and Tuscarora, as well as general and
administrative costs related to TC PipeLines, LP. Results from
Northern Border and Iroquois reflect our share of equity income
from these investments. TC PipeLines, LP acquired 49.34 per cent of
our 50 per cent interest in Iroquois on June 1, 2017. On June 1,
2017, we sold the remaining 11.81 per cent of Portland to TC
PipeLines, LP.2 TC PipeLines, LP periodically conducted
at-the-market equity issuances which decreased our ownership in TC
PipeLines, LP. Effective March 2018, this program ceased to be
utilized. At December 31, 2018 our ownership interest in TC
PipeLines, LP was 25.5 per cent compared to 25.7 per cent at
December 31, 2017.3 Represents our 53.6 per cent direct
interest in Great Lakes. The remaining 46.4 per cent is held
by TC PipeLines, LP.4 Results reflect earnings from our
direct ownership interests in Crossroads, as well as Iroquois and
Portland until June 1, 2017, our effective ownership in Millennium
and Hardy Storage, and general and administrative and business
development costs related to U.S. natural gas pipelines.5 Results
reflect earnings attributable to portions of TC PipeLines, LP,
Portland (until June 1, 2017) and Columbia Pipeline Partners LP
(CPPL) (until February 17, 2017) that we do not own.6 These amounts
were recorded in TC PipeLines, LP. The pre-tax impact to us is 25.5
per cent of these amounts net of non-controlling interests.
U.S. Natural Gas Pipelines segmented earnings decreased by $495
million for the three months ended December 31, 2018 compared
to the same period in 2017.
Segmented earnings for the three months ended December 31,
2018 included:
- a $722 million non-cash asset impairment charge related to
Bison
- a $79 million non-cash goodwill impairment charge related to
Tuscarora
- $130 million of termination payments received on two of Bison’s
transportation contracts which was recorded in Revenues.
The amounts for each of these specified items are pre-tax and
before reduction for the 74.5 per cent non-controlling interests in
TC PipeLines, LP and have been excluded from our calculation of
comparable EBIT. A stronger U.S. dollar in fourth quarter 2018 had
a positive impact on the Canadian dollar equivalent segmented
earnings from our U.S. operations compared to the same period in
2017.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by
US$138 million for the three months ended December 31, 2018
compared to the same period in 2017 and was primarily the net
effect of:
- increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service and additional contract sales on ANR and
Great Lakes
- increased earnings due to the amortization of the net
regulatory liabilities that were recorded at the end of 2017,
partially offset by a reduction in certain rates on Columbia Gas as
a result of U.S. Tax Reform.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization increased by US$18 million for the three months ended
December 31, 2018 compared to the same period in 2017 mainly
due to new projects placed in service.
Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of US$,
unless noted otherwise) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Topolobampo |
|
44 |
|
|
38 |
|
|
172 |
|
|
157 |
|
Tamazunchale |
|
31 |
|
|
27 |
|
|
127 |
|
|
112 |
|
Mazatlán |
|
20 |
|
|
16 |
|
|
78 |
|
|
65 |
|
Guadalajara |
|
18 |
|
|
17 |
|
|
71 |
|
|
68 |
|
Sur de Texas1 |
|
2 |
|
|
(6 |
) |
|
16 |
|
|
8 |
|
Other |
|
— |
|
|
(1 |
) |
|
4 |
|
|
(11 |
) |
Comparable EBITDA |
|
115 |
|
|
91 |
|
|
468 |
|
|
399 |
|
Depreciation and
amortization |
|
(19 |
) |
|
(18 |
) |
|
(75 |
) |
|
(72 |
) |
Comparable EBIT |
|
96 |
|
|
73 |
|
|
393 |
|
|
327 |
|
Foreign exchange
impact |
|
32 |
|
|
20 |
|
|
117 |
|
|
99 |
|
Comparable EBIT and segmented earnings (Cdn$) |
|
128 |
|
|
93 |
|
|
510 |
|
|
426 |
|
1 Represents our 60 per cent equity interest in a joint venture
with IEnova to build, own and operate the Sur de Texas
pipeline.
Mexico Natural Gas Pipelines segmented earnings
increased by $35 million for the three months ended
December 31, 2018 compared to the same period in 2017 and are
equivalent to comparable EBIT.
Comparable EBITDA for Mexico Natural Gas
Pipelines increased by US$24 million for the three months ended
December 31, 2018 compared to the same period in 2017
primarily due to:
- higher revenues from operations as a result of changes in
timing of revenue recognition
- equity earnings from our investment in the Sur de Texas
pipeline which records AFUDC during construction, net of interest
expense on an inter-affiliate loan from TransCanada. The interest
expense on this inter-affiliate loan is fully offset in Interest
income and other in the Corporate segment
- incremental earnings from a CRE tariff increase.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization remained largely consistent for the three months ended
December 31, 2018 compared to the same period in 2017.
Liquids Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of
$) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Keystone Pipeline
System |
|
401 |
|
|
346 |
|
|
1,443 |
|
|
1,283 |
|
Intra-Alberta
pipelines |
|
38 |
|
|
29 |
|
|
160 |
|
|
33 |
|
Liquids marketing and
other |
|
99 |
|
|
26 |
|
|
246 |
|
|
32 |
|
Comparable EBITDA |
|
538 |
|
|
401 |
|
|
1,849 |
|
|
1,348 |
|
Depreciation and amortization |
|
(87 |
) |
|
(81 |
) |
|
(341 |
) |
|
(309 |
) |
Comparable
EBIT |
|
451 |
|
|
320 |
|
|
1,508 |
|
|
1,039 |
|
Specific items: |
|
|
|
|
|
|
|
|
Energy
East impairment charge |
|
— |
|
|
(1,256 |
) |
|
— |
|
|
(1,256 |
) |
Keystone
XL asset costs |
|
— |
|
|
(11 |
) |
|
— |
|
|
(34 |
) |
Risk management
activities |
|
81 |
|
|
15 |
|
|
71 |
|
|
— |
|
Segmented earnings/(losses) |
|
532 |
|
|
(932 |
) |
|
1,579 |
|
|
(251 |
) |
|
|
|
|
|
|
|
|
|
Comparable EBIT
denominated as follows: |
|
|
|
|
|
|
|
|
Canadian dollars |
|
92 |
|
|
80 |
|
|
370 |
|
|
255 |
|
U.S. dollars |
|
271 |
|
|
188 |
|
|
876 |
|
|
604 |
|
Foreign
exchange impact |
|
88 |
|
|
52 |
|
|
262 |
|
|
180 |
|
|
|
451 |
|
|
320 |
|
|
1,508 |
|
|
1,039 |
|
Liquids Pipelines segmented earnings increased by $1,464 million
for the three months ended December 31, 2018 compared to the
same period in 2017 and included the following specific items:
- a $1,256 million pre-tax impairment charge in 2017 for the
Energy East pipeline and related projects
- $11 million of pre-tax costs in 2017 related to Keystone XL for
the maintenance and liquidation of project assets which were
expensed pending further advancement of the project
- unrealized gains from changes in the fair value of derivatives
related to our liquids marketing business.
Comparable EBITDA for Liquids Pipelines increased by $137
million for the three months ended December 31, 2018 compared
to the same period in 2017 primarily due to:
- higher contracted and uncontracted volumes on the Keystone
Pipeline System
- higher contribution from liquids marketing activities from
improved margins and volumes
- incremental contributions from intra-Alberta pipelines, Grand
Rapids and Northern Courier, which began operations in the second
half of 2017
- lower business development costs as a result of capitalizing
Keystone XL expenditures in 2018
- a stronger U.S. dollar which had a positive impact on the
Canadian dollar equivalent earnings from our U.S. operations.
DEPRECIATION AND AMORTIZATIONDepreciation 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.
EnergyThe following is a reconciliation of
comparable EBITDA and comparable EBIT (our non-GAAP measures) to
segmented earnings (the most directly comparable GAAP measure).
|
|
three months ended December 31 |
|
year ended December 31 |
(millions
of Canadian $, unless noted otherwise) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Western and Eastern
Power1 |
|
99 |
|
|
115 |
|
|
428 |
|
|
444 |
|
Bruce Power1 |
|
66 |
|
|
120 |
|
|
311 |
|
|
434 |
|
U.S. Power (US$)2 |
|
— |
|
|
(8 |
) |
|
— |
|
|
100 |
|
Foreign
exchange impact on U.S. Power |
|
— |
|
|
(4 |
) |
|
— |
|
|
30 |
|
Natural Gas Storage and
other |
|
6 |
|
|
15 |
|
|
27 |
|
|
55 |
|
Business
Development3 |
|
(4 |
) |
|
(24 |
) |
|
(14 |
) |
|
(33 |
) |
Comparable
EBITDA |
|
167 |
|
|
214 |
|
|
752 |
|
|
1,030 |
|
Depreciation and
amortization |
|
(27 |
) |
|
(33 |
) |
|
(119 |
) |
|
(151 |
) |
Comparable EBIT |
|
140 |
|
|
181 |
|
|
633 |
|
|
879 |
|
Specific items: |
|
|
|
|
|
|
|
|
Gain on
sale of Cartier Wind power facilities |
|
170 |
|
|
— |
|
|
170 |
|
|
— |
|
U.S.
Northeast power marketing contracts |
|
(10 |
) |
|
— |
|
|
(5 |
) |
|
— |
|
Net gain
on sales of U.S. Northeast power generation assets |
|
— |
|
|
15 |
|
|
— |
|
|
484 |
|
Gain on
sale of Ontario solar assets |
|
— |
|
|
127 |
|
|
— |
|
|
127 |
|
Risk
management activities |
|
15 |
|
|
149 |
|
|
(19 |
) |
|
62 |
|
Segmented earnings |
|
315 |
|
|
472 |
|
|
779 |
|
|
1,552 |
|
1 Includes our share of equity income from our investments in
Portlands Energy and Bruce Power.2 In second quarter 2017, we
completed the sales of our U.S. Northeast power generation assets.3
Includes a $21 million impairment charge in 2017 related to
obsolete equipment.
Energy segmented earnings were $157 million lower in the three
months ended December 31, 2018 compared to the same period in
2017 and included the following specific items:
- a pre-tax gain in 2018 of $170 million related to the sale of
our interests in the Cartier Wind power facilities
- a pre-tax net loss of $10 million related to our U.S. Northeast
power marketing contracts. These results have been excluded from
Energy's comparable earnings in 2018 as we do not consider the
wind-down of the remaining contracts part of our underlying
operations. The contract portfolio is scheduled to run-off through
to mid-2020
- a pre-tax gain in 2017 of $127 million related to the sale of
our Ontario solar assets
- a pre-tax net gain of $15 million in 2017 related to the
monetization of our U.S. Northeast power generation assets
- unrealized gains and losses from changes in the fair value of
derivatives used to reduce our exposure to certain commodity price
risks, as noted in the table below.
Risk management activities |
|
three months ended December 31 |
|
year ended December 31 |
(millions of $,
pre-tax) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Canadian Power |
|
— |
|
|
6 |
|
|
3 |
|
|
11 |
|
U.S. Power |
|
20 |
|
|
136 |
|
|
(11 |
) |
|
39 |
|
Natural Gas
Storage |
|
(5 |
) |
|
7 |
|
|
(11 |
) |
|
12 |
|
Total unrealized gains/(losses) from risk management
activities |
|
15 |
|
|
149 |
|
|
(19 |
) |
|
62 |
|
Comparable EBITDA for Energy decreased by $47 million for the
three months ended December 31, 2018 compared to the same
period in 2017 primarily due to the net effect of:
- decreased earnings from Bruce Power primarily due to lower
volumes resulting from higher outage days. Additional financial and
operating information on Bruce Power is provided below
- decreased Western and Eastern Power results due to the sales of
our Cartier Wind power facilities in October 2018 and our Ontario
solar assets in December 2017, partially offset by higher Western
Power realized margins on higher generation volumes
- lower Natural Gas Storage results primarily due to pipeline
constraints in the Alberta natural gas market which limited our
ability to access our storage facilities and resulted in lower
realized natural gas storage price spreads.
DEPRECIATION AND AMORTIZATIONDepreciation 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 POWERThe following reflects our
proportionate share of the components of comparable EBITDA and
comparable EBIT.
|
|
three months ended December 31 |
|
year ended December 31 |
(millions
of $, unless noted otherwise) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Equity income
included in comparable EBITDA and EBIT comprised of: |
|
|
|
|
|
|
|
|
Revenues1 |
|
|
373 |
|
|
|
414 |
|
|
|
1,526 |
|
|
|
1,626 |
|
Operating
expenses |
|
|
(212 |
) |
|
|
(208 |
) |
|
|
(852 |
) |
|
|
(846 |
) |
Depreciation and other |
|
|
(95 |
) |
|
|
(86 |
) |
|
|
(363 |
) |
|
|
(346 |
) |
Comparable EBITDA and EBIT2 |
|
|
66 |
|
|
|
120 |
|
|
|
311 |
|
|
|
434 |
|
Bruce
Power – other information |
|
|
|
|
|
|
|
|
Plant
availability3 |
|
|
83 |
% |
|
|
92 |
% |
|
|
87 |
% |
|
|
90 |
% |
Planned outage
days |
|
|
100 |
|
|
|
43 |
|
|
|
280 |
|
|
|
221 |
|
Unplanned outage
days |
|
|
15 |
|
|
|
10 |
|
|
|
92 |
|
|
|
49 |
|
Sales volumes
(GWh)2 |
|
|
5,676 |
|
|
|
6,275 |
|
|
|
23,486 |
|
|
|
24,368 |
|
Realized
sales price per MWh4 |
|
$68 |
|
|
$67 |
|
|
$67 |
|
|
$67 |
|
1 Net of amounts recorded to reflect operating cost efficiencies
shared with the IESO.2 Represents our 48.3 per cent (2017 – 48.4
per cent) ownership interest in Bruce Power. Sales volumes include
deemed generation.3 The percentage of time the plant was available
to generate power, regardless of whether it was running.4
Calculation based on actual and deemed generation. Realized sales
prices per MWh includes realized gains and losses from contracting
activities and cost flow-through items. Excludes unrealized gains
and losses on contracting activities and non-electricity
revenues.
Planned maintenance on Unit 8 began and was completed in fourth
quarter 2018. Planned maintenance on Unit 3 began in fourth quarter
2018 and is scheduled to be completed in first quarter 2019.
Corporate
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented losses (the
most directly comparable GAAP measure).
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of
$) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Comparable
EBITDA and EBIT |
|
(34 |
) |
|
(1 |
) |
|
(59 |
) |
|
(21 |
) |
Specific items: |
|
|
|
|
|
|
|
|
Foreign
exchange gain – inter-affiliate loan1 |
|
57 |
|
|
64 |
|
|
5 |
|
|
63 |
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
— |
|
|
— |
|
|
(81 |
) |
Segmented earnings/(losses) |
|
23 |
|
|
63 |
|
|
(54 |
) |
|
(39 |
) |
1 Reported in Income from equity investments on the Consolidated
statement of income.
Corporate segmented earnings decreased by $40 million for the
three months ended December 31, 2018 compared to the same
period in 2017 and included the following specific items:
- foreign exchange gains on a peso-denominated inter-affiliate
loan to the Sur de Texas project for our proportionate share of the
project's financing. There is a corresponding foreign exchange loss
included in Interest income and other on the inter-affiliate loan
receivable which fully offsets this gain.
Comparable EBITDA decreased by $33 million for the three months
ended December 31, 2018 compared to the same period in 2017,
primarily due to increased general and administrative costs.
OTHER INCOME STATEMENT ITEMSInterest
expense
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of
$) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Interest on
long-term debt and junior subordinated notes |
|
|
|
|
|
|
|
|
Canadian
dollar-denominated |
|
(142 |
) |
|
(138 |
) |
|
(549 |
) |
|
(494 |
) |
U.S.
dollar-denominated |
|
(344 |
) |
|
(315 |
) |
|
(1,325 |
) |
|
(1,269 |
) |
Foreign
exchange impact |
|
(111 |
) |
|
(86 |
) |
|
(394 |
) |
|
(379 |
) |
|
|
(597 |
) |
|
(539 |
) |
|
(2,268 |
) |
|
(2,142 |
) |
Other interest and
amortization expense |
|
(41 |
) |
|
(25 |
) |
|
(121 |
) |
|
(99 |
) |
Capitalized interest |
|
35 |
|
|
23 |
|
|
124 |
|
|
173 |
|
Interest
expense included in comparable earnings |
|
(603 |
) |
|
(541 |
) |
|
(2,265 |
) |
|
(2,068 |
) |
Specific Item: |
|
|
|
|
|
|
|
|
Risk management activities |
|
— |
|
|
— |
|
|
— |
|
|
(1 |
) |
Interest expense |
|
(603 |
) |
|
(541 |
) |
|
(2,265 |
) |
|
(2,069 |
) |
Interest expense increased by $62 million for the three months
ended December 31, 2018 compared to the same period in 2017
and primarily reflects the net effect of:
- long-term debt and junior subordinated note issuances in 2018
and 2017, net of maturities
- higher capitalized interest primarily due to ongoing
construction at Napanee and the recommencement of capitalization of
Keystone XL costs in 2018, partially offset by the completion of
Northern Courier in fourth quarter 2017
- higher levels of short-term borrowing
- foreign exchange impact on translation of U.S.
dollar-denominated interest.
Allowance for funds used during
construction
|
|
three months ended December 31 |
|
year ended December 31 |
(millions
of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Allowance for
funds used during construction |
|
|
|
|
|
|
|
|
Canadian
dollar-denominated |
|
35 |
|
|
25 |
|
|
103 |
|
|
174 |
|
U.S.
dollar-denominated |
|
96 |
|
|
91 |
|
|
326 |
|
|
259 |
|
Foreign exchange
impact |
|
30 |
|
|
24 |
|
|
97 |
|
|
74 |
|
Allowance for funds used during construction |
|
161 |
|
|
140 |
|
|
526 |
|
|
507 |
|
AFUDC increased by $21 million for the three months ended
December 31, 2018 compared to the same period in 2017.
The increase in Canadian dollar-denominated AFUDC is primarily
due to higher capital expenditures on the NGTL System.
The increase in U.S. dollar-denominated AFUDC is primarily due
to continued investment in Mexico projects and additional
investment in and higher AFUDC rates on Columbia Gas growth
projects.
Interest income and other
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of
$) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Interest income
and other included in comparable earnings |
|
11 |
|
|
56 |
|
|
177 |
|
|
159 |
|
Specific items: |
|
|
|
|
|
|
|
|
Foreign
exchange loss – inter-affiliate loan |
|
(57 |
) |
|
(64 |
) |
|
(5 |
) |
|
(63 |
) |
Risk management activities |
|
(169 |
) |
|
(1 |
) |
|
(248 |
) |
|
88 |
|
Interest income and other |
|
(215 |
) |
|
(9 |
) |
|
(76 |
) |
|
184 |
|
Interest income and other decreased by $206
million for the three months ended December 31, 2018 compared
to the same period in 2017 and was primarily the net effect of:
- higher unrealized losses on risk management activities in 2018
compared to 2017, reflecting the strengthening of the U.S. dollar
at the end of 2018. These amounts have been excluded from
comparable earnings
- realized losses in 2018 compared to realized gains in 2017 on
derivatives used to manage our net exposure to foreign exchange
rate fluctuations on U.S. dollar-denominated income
- higher interest income combined with a lower foreign exchange
loss related to an inter-affiliate loan receivable from the Sur de
Texas joint venture. The corresponding interest expense and foreign
exchange gain are reflected in Income from equity investments in
the Mexico Natural Gas Pipelines and Corporate segments,
respectively. The offsetting currency-related gain and loss amounts
are excluded from comparable earnings.
Income tax (expense)/recovery
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of
$) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Income tax
expense included in comparable earnings |
|
(268 |
) |
|
(234 |
) |
|
(693 |
) |
|
(839 |
) |
Specific items: |
|
|
|
|
|
|
|
|
MLP
regulatory liability write-off |
|
115 |
|
|
— |
|
|
115 |
|
|
— |
|
U.S. Tax
Reform |
|
52 |
|
|
804 |
|
|
52 |
|
|
804 |
|
Bison
asset impairment |
|
44 |
|
|
— |
|
|
44 |
|
|
— |
|
Sales of
U.S. Northeast power generation assets |
|
27 |
|
|
49 |
|
|
27 |
|
|
(177 |
) |
Tuscarora
goodwill impairment |
|
5 |
|
|
— |
|
|
5 |
|
|
— |
|
U.S.
Northeast power marketing contracts |
|
3 |
|
|
— |
|
|
1 |
|
|
— |
|
Gain on
sale of Cartier Wind power facilities |
|
(27 |
) |
|
— |
|
|
(27 |
) |
|
— |
|
Bison
contract terminations |
|
(8 |
) |
|
— |
|
|
(8 |
) |
|
— |
|
Energy
East impairment charge |
|
— |
|
|
302 |
|
|
— |
|
|
302 |
|
Gain on
sale of Ontario solar assets |
|
— |
|
|
9 |
|
|
— |
|
|
9 |
|
Keystone
XL asset costs |
|
— |
|
|
2 |
|
|
— |
|
|
6 |
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
— |
|
|
— |
|
|
22 |
|
Keystone
XL income tax recoveries |
|
— |
|
|
— |
|
|
— |
|
|
7 |
|
Risk management activities |
|
19 |
|
|
(62 |
) |
|
52 |
|
|
(45 |
) |
Income tax (expense)/recovery |
|
(38 |
) |
|
870 |
|
|
(432 |
) |
|
89 |
|
Income tax expense included in comparable earnings increased by
$34 million for the three months ended December 31, 2018
compared to the same period in 2017. This was primarily due to
higher comparable earnings before income taxes and higher
flow-through income taxes in Canadian rate-regulated pipelines
offset by lower income tax rates as a result of U.S. Tax
Reform.
Net loss/(income) attributable to non-controlling
interests
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of
$) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Net income
attributable to non-controlling interests included in comparable
earnings |
|
(86 |
) |
|
(49 |
) |
|
(315 |
) |
|
(238 |
) |
Specific items: |
|
|
|
|
|
|
|
|
Bison
impairment |
|
538 |
|
|
— |
|
|
538 |
|
|
— |
|
Tuscarora
goodwill impairment |
|
59 |
|
|
— |
|
|
59 |
|
|
— |
|
Bison contract terminations |
|
(97 |
) |
|
— |
|
|
(97 |
) |
|
— |
|
Net loss/(income) attributable to non-controlling
interests |
|
414 |
|
|
(49 |
) |
|
185 |
|
|
(238 |
) |
Net loss/(income) attributable to non-controlling interests
decreased by $463 million for the three months ended
December 31, 2018 compared to the same period in 2017
primarily due to the net effect of:
- a $538 million charge related to the non-controlling interests
portion of a $722 million Bison asset impairment charge recorded by
TC PipeLines, LP
- a $59 million charge related to the non-controlling interests
portion of a $79 million Tuscarora goodwill impairment charge
recorded by TC PipeLines, LP
- $97 million in income related to the non-controlling interests
portion of Bison contract termination payments of $130 million
received from certain customers and recorded by TC PipeLines,
LP.
On consolidation, we recorded the non-controlling interests'
74.5 per cent of these transactions. These items have been excluded
in the calculation of comparable earnings.
Net income attributable to non-controlling interests included in
comparable earnings increased by $37 million for the three months
ended December 31, 2018 compared to the same period in 2017
primarily due to higher earnings in TC PipeLines, LP.
Preferred share dividends
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of
$) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Preferred share dividends |
|
(41 |
) |
|
(40 |
) |
|
(163 |
) |
|
(160 |
) |
Preferred share dividends remained largely consistent for the
three months ended December 31, 2018 compared to the same
period in 2017.
Cash Provided by Operating Activities
|
|
three months ended December 31 |
|
year ended December 31 |
(millions of $,
except per share amounts) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Net cash provided by
operations |
|
|
2,039 |
|
|
|
1,390 |
|
|
|
6,555 |
|
|
|
5,230 |
|
(Decrease)/increase in
operating working capital |
|
|
(28 |
) |
|
|
49 |
|
|
|
102 |
|
|
|
273 |
|
Funds generated from operations |
|
|
2,011 |
|
|
|
1,439 |
|
|
|
6,657 |
|
|
|
5,503 |
|
Specific items: |
|
|
|
|
|
|
|
|
Bison
contract terminations |
|
|
(122 |
) |
|
|
— |
|
|
|
(122 |
) |
|
|
— |
|
Net
(gain)/loss on sales of U.S. Northeast power generation assets |
|
|
(14 |
) |
|
|
— |
|
|
|
(14 |
) |
|
|
20 |
|
U.S.
Northeast power marketing contracts |
|
|
6 |
|
|
|
— |
|
|
|
1 |
|
|
|
— |
|
Keystone
XL asset costs |
|
|
— |
|
|
|
11 |
|
|
|
— |
|
|
|
34 |
|
Integration and acquisition related costs – Columbia |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
84 |
|
Comparable
funds generated from operations |
|
|
1,881 |
|
|
|
1,450 |
|
|
|
6,522 |
|
|
|
5,641 |
|
Dividends on preferred
shares |
|
|
(40 |
) |
|
|
(39 |
) |
|
|
(158 |
) |
|
|
(155 |
) |
Distributions to
non-controlling interests |
|
|
(51 |
) |
|
|
(68 |
) |
|
|
(225 |
) |
|
|
(283 |
) |
Non-recoverable maintenance capital expenditures |
|
|
(63 |
) |
|
|
(71 |
) |
|
|
(254 |
) |
|
|
(240 |
) |
Comparable
distributable cash flow |
|
|
1,727 |
|
|
|
1,272 |
|
|
|
5,885 |
|
|
|
4,963 |
|
Comparable distributable cash flow per common
share |
|
$1.89 |
|
|
$1.45 |
|
|
$6.52 |
|
|
$5.69 |
|
COMPARABLE FUNDS GENERATED FROM
OPERATIONSComparable 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 FLOWComparable
distributable cash flow, a non-GAAP measure, helps us assess the
cash available to common shareholders before capital
allocation.
The increase in comparable distributable cash flow for the three
months ended December 31, 2018 compared to the same period in
2017 reflects higher comparable funds generated from operations, as
described above. Comparable distributable cash flow per common
share for the three months ended December 31, 2018 also
reflects the dilutive impact of common shares issued under the
Corporate ATM program and DRP in 2017 and 2018.
In 2018, our determination of comparable distributable cash flow
has been revised to exclude the deduction of maintenance capital
expenditures for assets for which we have the ability to recover
these costs in pipeline tolls. Comparative periods presented in the
table have been adjusted accordingly. We believe that including
only non-recoverable maintenance capital expenditures in the
calculation of distributable cash flow best depicts the cash
available for reinvestment or distribution to shareholders. For our
rate-regulated Canadian and U.S. natural gas pipelines, we have the
opportunity to recover and earn a return on maintenance capital
expenditures through current and future tolls. Tolling arrangements
in our liquids pipelines provide for the recovery of maintenance
capital expenditures. Therefore, we have not deducted the
recoverable maintenance capital expenditures for these businesses
in the calculation of comparable distributable cash flow.
Reconciliation of non-GAAP measures
|
|
three months ended December 31 |
|
year ended December 31 |
(millions
of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Comparable
EBITDA |
|
|
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
818 |
|
|
569 |
|
|
2,379 |
|
|
2,144 |
|
U.S. Natural Gas
Pipelines |
|
812 |
|
|
604 |
|
|
3,035 |
|
|
2,357 |
|
Mexico Natural Gas
Pipelines |
|
152 |
|
|
116 |
|
|
607 |
|
|
519 |
|
Liquids Pipelines |
|
538 |
|
|
401 |
|
|
1,849 |
|
|
1,348 |
|
Energy |
|
167 |
|
|
214 |
|
|
752 |
|
|
1,030 |
|
Corporate |
|
(34 |
) |
|
(1 |
) |
|
(59 |
) |
|
(21 |
) |
Comparable
EBITDA |
|
2,453 |
|
|
1,903 |
|
|
8,563 |
|
|
7,377 |
|
Depreciation and amortization |
|
(681 |
) |
|
(516 |
) |
|
(2,350 |
) |
|
(2,048 |
) |
Comparable
EBIT |
|
1,772 |
|
|
1,387 |
|
|
6,213 |
|
|
5,329 |
|
Specific items: |
|
|
|
|
|
|
|
|
Bison
asset impairment |
|
(722 |
) |
|
— |
|
|
(722 |
) |
|
— |
|
Tuscarora
goodwill impairment |
|
(79 |
) |
|
— |
|
|
(79 |
) |
|
— |
|
U.S.
Northeast power marketing contracts |
|
(10 |
) |
|
— |
|
|
(5 |
) |
|
— |
|
Gain on
sale of Cartier Wind power facilities |
|
170 |
|
|
— |
|
|
170 |
|
|
— |
|
Bison
contract terminations |
|
130 |
|
|
— |
|
|
130 |
|
|
— |
|
Foreign
exchange gain – inter-affiliate loan |
|
57 |
|
|
64 |
|
|
5 |
|
|
63 |
|
Energy
East impairment charge |
|
— |
|
|
(1,256 |
) |
|
— |
|
|
(1,256 |
) |
Keystone
XL asset costs |
|
— |
|
|
(11 |
) |
|
— |
|
|
(34 |
) |
Gain on
sale of Ontario solar assets |
|
— |
|
|
127 |
|
|
— |
|
|
127 |
|
Net gain
on sales of U.S. Northeast power generation assets |
|
— |
|
|
15 |
|
|
— |
|
|
484 |
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
— |
|
|
— |
|
|
(91 |
) |
Risk
management activities |
|
96 |
|
|
164 |
|
|
52 |
|
|
62 |
|
Segmented earnings |
|
1,414 |
|
|
490 |
|
|
5,764 |
|
|
4,684 |
|
Condensed consolidated statement of
income
|
|
three months ended December 31 |
|
year ended December 31 |
(unaudited - millions of Canadian $, except per share amounts) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
|
1,266 |
|
|
|
968 |
|
|
|
4,038 |
|
|
|
3,693 |
|
U.S. Natural Gas
Pipelines |
|
|
1,326 |
|
|
|
900 |
|
|
|
4,314 |
|
|
|
3,584 |
|
Mexico Natural Gas
Pipelines |
|
|
159 |
|
|
|
138 |
|
|
|
619 |
|
|
|
570 |
|
Liquids Pipelines |
|
|
753 |
|
|
|
599 |
|
|
|
2,584 |
|
|
|
2,009 |
|
Energy |
|
|
400 |
|
|
|
1,012 |
|
|
|
2,124 |
|
|
|
3,593 |
|
|
|
|
3,904 |
|
|
|
3,617 |
|
|
|
13,679 |
|
|
|
13,449 |
|
Income from
Equity Investments |
|
|
222 |
|
|
|
246 |
|
|
|
714 |
|
|
|
773 |
|
Operating and
Other Expenses |
|
|
|
|
|
|
|
|
Plant operating costs
and other |
|
|
1,011 |
|
|
|
944 |
|
|
|
3,591 |
|
|
|
3,906 |
|
Commodity purchases
resold |
|
|
249 |
|
|
|
671 |
|
|
|
1,488 |
|
|
|
2,382 |
|
Property taxes |
|
|
140 |
|
|
|
127 |
|
|
|
569 |
|
|
|
569 |
|
Depreciation and
amortization |
|
|
681 |
|
|
|
516 |
|
|
|
2,350 |
|
|
|
2,055 |
|
Goodwill and other
asset impairment charges |
|
|
801 |
|
|
|
1,257 |
|
|
|
801 |
|
|
|
1,257 |
|
|
|
|
2,882 |
|
|
|
3,515 |
|
|
|
8,799 |
|
|
|
10,169 |
|
Gain on Sales
of Assets |
|
|
170 |
|
|
|
142 |
|
|
|
170 |
|
|
|
631 |
|
Financial
Charges |
|
|
|
|
|
|
|
|
Interest expense |
|
|
603 |
|
|
|
541 |
|
|
|
2,265 |
|
|
|
2,069 |
|
Allowance for funds
used during construction |
|
|
(161 |
) |
|
|
(140 |
) |
|
|
(526 |
) |
|
|
(507 |
) |
Interest
income and other |
|
|
215 |
|
|
|
9 |
|
|
|
76 |
|
|
|
(184 |
) |
|
|
|
657 |
|
|
|
410 |
|
|
|
1,815 |
|
|
|
1,378 |
|
Income before Income Taxes |
|
|
757 |
|
|
|
80 |
|
|
|
3,949 |
|
|
|
3,306 |
|
Income Tax
Expense/(Recovery) |
|
|
|
|
|
|
|
|
Current |
|
|
146 |
|
|
|
21 |
|
|
|
315 |
|
|
|
149 |
|
Deferred |
|
|
59 |
|
|
|
(87 |
) |
|
|
284 |
|
|
|
566 |
|
Deferred
– U.S. Tax Reform and 2018 FERC Actions |
|
|
(167 |
) |
|
|
(804 |
) |
|
|
(167 |
) |
|
|
(804 |
) |
|
|
|
38 |
|
|
|
(870 |
) |
|
|
432 |
|
|
|
(89 |
) |
Net
Income |
|
|
719 |
|
|
|
950 |
|
|
|
3,517 |
|
|
|
3,395 |
|
Net
(loss)/income attributable to non-controlling interests |
|
|
(414 |
) |
|
|
49 |
|
|
|
(185 |
) |
|
|
238 |
|
Net Income
Attributable to Controlling Interests |
|
|
1,133 |
|
|
|
901 |
|
|
|
3,702 |
|
|
|
3,157 |
|
Preferred
share dividends |
|
|
41 |
|
|
|
40 |
|
|
|
163 |
|
|
|
160 |
|
Net Income Attributable to Common Shares |
|
|
1,092 |
|
|
|
861 |
|
|
|
3,539 |
|
|
|
2,997 |
|
Net Income per
Common Share |
|
|
|
|
|
|
|
|
Basic |
|
$1.19 |
|
|
$0.98 |
|
|
$3.92 |
|
|
$3.44 |
|
Diluted |
|
$1.19 |
|
|
$0.98 |
|
|
$3.92 |
|
|
$3.43 |
|
Dividends Declared per Common Share |
|
$0.69 |
|
|
$0.625 |
|
|
$2.76 |
|
|
$2.50 |
|
Weighted
Average Number of Common Shares (millions) |
|
|
|
|
|
|
|
|
Basic |
|
|
915 |
|
|
|
877 |
|
|
|
902 |
|
|
|
872 |
|
Diluted |
|
|
915 |
|
|
|
879 |
|
|
|
903 |
|
|
|
874 |
|
Condensed consolidated statement of cash
flows
|
|
three months ended December 31 |
|
year ended December 31 |
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Cash Generated
from Operations |
|
|
|
|
|
|
|
|
Net income |
|
719 |
|
|
950 |
|
|
3,517 |
|
|
3,395 |
|
Depreciation and
amortization |
|
681 |
|
|
516 |
|
|
2,350 |
|
|
2,055 |
|
Goodwill and other
asset impairment charges |
|
801 |
|
|
1,257 |
|
|
801 |
|
|
1,257 |
|
Deferred income
taxes |
|
59 |
|
|
(87 |
) |
|
284 |
|
|
566 |
|
Deferred income taxes –
U.S. Tax Reform and 2018 FERC Actions |
|
(167 |
) |
|
(804 |
) |
|
(167 |
) |
|
(804 |
) |
Income from equity
investments |
|
(222 |
) |
|
(246 |
) |
|
(714 |
) |
|
(773 |
) |
Distributions received
from operating activities of equity investments |
|
224 |
|
|
227 |
|
|
985 |
|
|
970 |
|
Employee
post-retirement benefits funding, net of expense |
|
(13 |
) |
|
— |
|
|
(35 |
) |
|
(64 |
) |
Gain on sale of
assets |
|
(170 |
) |
|
(142 |
) |
|
(170 |
) |
|
(631 |
) |
Equity allowance for
funds used during construction |
|
(113 |
) |
|
(113 |
) |
|
(374 |
) |
|
(362 |
) |
Unrealized
losses/(gains) on financial instruments |
|
100 |
|
|
(163 |
) |
|
220 |
|
|
(149 |
) |
Other |
|
112 |
|
|
44 |
|
|
(40 |
) |
|
43 |
|
Decrease/(increase) in operating working capital |
|
28 |
|
|
(49 |
) |
|
(102 |
) |
|
(273 |
) |
Net cash
provided by operations |
|
2,039 |
|
|
1,390 |
|
|
6,555 |
|
|
5,230 |
|
Investing
Activities |
|
|
|
|
|
|
|
|
Capital
expenditures |
|
(2,944 |
) |
|
(2,000 |
) |
|
(9,418 |
) |
|
(7,383 |
) |
Capital projects in
development |
|
(257 |
) |
|
(11 |
) |
|
(496 |
) |
|
(146 |
) |
Contributions to equity
investments |
|
(237 |
) |
|
(541 |
) |
|
(1,015 |
) |
|
(1,681 |
) |
Proceeds from sales of
assets, net of transaction costs |
|
614 |
|
|
536 |
|
|
614 |
|
|
4,683 |
|
Reimbursement of costs
related to capital projects in development |
|
470 |
|
|
634 |
|
|
470 |
|
|
634 |
|
Other distributions
from equity investments |
|
— |
|
|
— |
|
|
121 |
|
|
362 |
|
Deferred
amounts and other |
|
(373 |
) |
|
(81 |
) |
|
(295 |
) |
|
(168 |
) |
Net cash
used in investing activities |
|
(2,727 |
) |
|
(1,463 |
) |
|
(10,019 |
) |
|
(3,699 |
) |
Financing
Activities |
|
|
|
|
|
|
|
|
Notes payable
(repaid)/issued, net |
|
(1,089 |
) |
|
(194 |
) |
|
817 |
|
|
1,038 |
|
Long-term debt issued,
net of issue costs |
|
1,879 |
|
|
1,675 |
|
|
6,238 |
|
|
3,643 |
|
Long-term debt
repaid |
|
(284 |
) |
|
(1,570 |
) |
|
(3,550 |
) |
|
(7,085 |
) |
Junior subordinated
notes issued, net of issue costs |
|
— |
|
|
— |
|
|
— |
|
|
3,468 |
|
Dividends on common
shares |
|
(417 |
) |
|
(357 |
) |
|
(1,571 |
) |
|
(1,339 |
) |
Dividends on preferred
shares |
|
(40 |
) |
|
(39 |
) |
|
(158 |
) |
|
(155 |
) |
Distributions to
non-controlling interests |
|
(51 |
) |
|
(68 |
) |
|
(225 |
) |
|
(283 |
) |
Common shares issued,
net of issue costs |
|
9 |
|
|
232 |
|
|
1,148 |
|
|
274 |
|
Partnership units of TC
PipeLines, LP issued, net of issue costs |
|
— |
|
|
63 |
|
|
49 |
|
|
225 |
|
Common units of
Columbia Pipeline Partners LP acquired |
|
— |
|
|
— |
|
|
— |
|
|
(1,205 |
) |
Net cash provided by/(used in) financing activities |
|
7 |
|
|
(258 |
) |
|
2,748 |
|
|
(1,419 |
) |
Effect of Foreign Exchange Rate Changes on Cash and Cash
Equivalents |
|
26 |
|
|
(4 |
) |
|
73 |
|
|
(39 |
) |
(Decrease)/increase in Cash and Cash
Equivalents |
|
(655 |
) |
|
(335 |
) |
|
(643 |
) |
|
73 |
|
Cash and Cash
Equivalents |
|
|
|
|
|
|
|
|
Beginning
of period |
|
1,101 |
|
|
1,424 |
|
|
1,089 |
|
|
1,016 |
|
Cash and Cash
Equivalents |
|
|
|
|
|
|
|
|
End of
period |
|
446 |
|
|
1,089 |
|
|
446 |
|
|
1,089 |
|
Condensed consolidated balance
sheet
|
|
December 31, |
|
|
December 31, |
|
(unaudited - millions of Canadian $) |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
ASSETS |
|
|
|
|
Current Assets |
|
|
|
|
Cash and
cash equivalents |
|
446 |
|
|
1,089 |
|
Accounts
receivable |
|
2,535 |
|
|
2,522 |
|
Inventories |
|
431 |
|
|
378 |
|
Assets held
for sale |
|
543 |
|
|
— |
|
Other |
|
1,180 |
|
|
691 |
|
|
|
5,135 |
|
|
4,680 |
|
Plant, Property
and Equipment |
net of accumulated
depreciation of $25,834 and $23,734, respectively |
|
66,503 |
|
|
57,277 |
|
Equity Investments |
|
7,113 |
|
|
6,366 |
|
Regulatory Assets |
|
1,548 |
|
|
1,376 |
|
Goodwill |
|
14,178 |
|
|
13,084 |
|
Loan Receivable from Affiliate |
|
1,315 |
|
|
919 |
|
Intangible and Other Assets |
|
1,921 |
|
|
1,484 |
|
Restricted Investments |
|
1,207 |
|
|
915 |
|
|
|
98,920 |
|
|
86,101 |
|
LIABILITIES |
|
|
|
|
Current Liabilities |
|
|
|
|
Notes
payable |
|
2,762 |
|
|
1,763 |
|
Accounts
payable and other |
|
5,408 |
|
|
4,057 |
|
Dividends
payable |
|
668 |
|
|
586 |
|
Accrued
interest |
|
646 |
|
|
605 |
|
Current portion of long-term debt |
|
3,462 |
|
|
2,866 |
|
|
|
12,946 |
|
|
9,877 |
|
Regulatory Liabilities |
|
3,930 |
|
|
4,321 |
|
Other Long-Term Liabilities |
|
1,008 |
|
|
727 |
|
Deferred Income Tax Liabilities |
|
6,026 |
|
|
5,403 |
|
Long-Term Debt |
|
36,509 |
|
|
31,875 |
|
Junior Subordinated Notes |
|
7,508 |
|
|
7,007 |
|
|
|
67,927 |
|
|
59,210 |
|
EQUITY |
|
|
|
|
Common
shares, no par value |
|
23,174 |
|
|
21,167 |
|
Issued
and outstanding: |
December 31, 2018 – 918
million shares |
|
|
|
|
|
December 31, 2017 – 881
million shares |
|
|
|
|
Preferred
shares |
|
3,980 |
|
|
3,980 |
|
Additional
paid-in capital |
|
17 |
|
|
— |
|
Retained
earnings |
|
2,773 |
|
|
1,623 |
|
Accumulated other comprehensive loss |
|
(606 |
) |
|
(1,731 |
) |
Controlling Interests |
|
29,338 |
|
|
25,039 |
|
Non-controlling interests |
|
1,655 |
|
|
1,852 |
|
|
|
30,993 |
|
|
26,891 |
|
|
|
98,920 |
|
|
86,101 |
|
Segmented information
three months ended December 31, 2018 |
|
CanadianNaturalGasPipelines |
|
|
U.S.NaturalGasPipelines |
|
|
MexicoNaturalGasPipelines |
|
|
LiquidsPipelines |
|
|
|
|
|
|
|
(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 |
|
CanadianNaturalGasPipelines |
|
|
U.S.NaturalGasPipelines |
|
|
MexicoNaturalGasPipelines |
|
|
LiquidsPipelines |
|
|
|
|
|
|
|
(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 |
|
CanadianNaturalGasPipelines |
|
|
U.S.NaturalGasPipelines |
|
|
MexicoNatural GasPipelines |
|
|
LiquidsPipelines |
|
|
|
|
|
|
|
(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 |
|
CanadianNaturalGasPipelines |
|
|
U.S.NaturalGasPipelines |
|
|
MexicoNatural GasPipelines |
|
|
LiquidsPipelines |
|
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
|
|
|
|
Energy |
|
|
Corporate1 |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
3,693 |
|
|
3,584 |
|
|
570 |
|
|
2,009 |
|
|
3,593 |
|
|
— |
|
|
13,449 |
|
Intersegment revenues |
|
— |
|
|
51 |
|
|
— |
|
|
— |
|
|
— |
|
|
(51 |
) |
2 |
— |
|
|
|
3,693 |
|
|
3,635 |
|
|
570 |
|
|
2,009 |
|
|
3,593 |
|
|
(51 |
) |
|
13,449 |
|
Income/(loss) from
equity investments |
|
11 |
|
|
240 |
|
|
(9 |
) |
|
(3 |
) |
|
471 |
|
|
63 |
|
3 |
773 |
|
Plant operating costs
and other |
|
(1,300 |
) |
|
(1,340 |
) |
|
(42 |
) |
|
(623 |
) |
|
(550 |
) |
|
(51 |
) |
2 |
(3,906 |
) |
Commodity purchases
resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(2,382 |
) |
|
— |
|
|
(2,382 |
) |
Property taxes |
|
(260 |
) |
|
(181 |
) |
|
— |
|
|
(89 |
) |
|
(39 |
) |
|
— |
|
|
(569 |
) |
Depreciation and
amortization |
|
(908 |
) |
|
(594 |
) |
|
(93 |
) |
|
(309 |
) |
|
(151 |
) |
|
— |
|
|
(2,055 |
) |
Goodwill and other
asset impairment charges |
|
— |
|
|
— |
|
|
— |
|
|
(1,236 |
) |
|
(21 |
) |
|
— |
|
|
(1,257 |
) |
Gain on sale of
assets |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
631 |
|
|
— |
|
|
631 |
|
Segmented earnings/(losses) |
|
1,236 |
|
|
1,760 |
|
|
426 |
|
|
(251 |
) |
|
1,552 |
|
|
(39 |
) |
|
4,684 |
|
Interest
expense |
|
(2,069 |
) |
Allowance
for funds used during construction |
|
507 |
|
Interest income and other3 |
|
184 |
|
Income
before income taxes |
|
3,306 |
|
Income tax recovery |
|
89 |
|
Net income |
|
3,395 |
|
Net income attributable to non-controlling
interests |
|
(238 |
) |
Net income attributable to controlling
interests |
|
3,157 |
|
Preferred share dividends |
|
(160 |
) |
Net income attributable to common
shares |
|
2,997 |
|
1 Includes intersegment eliminations.2 The Company records
intersegment sales at contracted rates. For segmented reporting,
these transactions are included as Intersegment revenues in the
segment providing the service and Plant operating costs and other
in the segment receiving the service. These transactions are
eliminated on consolidation. Intersegment profit is recognized when
the product or service has been provided to third parties or
otherwise realized.3 Income/(loss) from equity investments includes
foreign exchange gains on the Company's inter-affiliate loan with
Sur de Texas. The offsetting foreign exchange losses on the
inter-affiliate loan are included in Interest income and other. The
peso-denominated loan to the Sur de Texas joint venture represents
the Company's proportionate share of long-term debt financing for
this joint venture.
TOTAL ASSETS BY SEGMENT
(unaudited - millions of Canadian $) |
|
December 31, 2018 |
|
|
December 31, 2017 |
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
18,407 |
|
|
16,904 |
|
U.S. Natural Gas
Pipelines |
|
44,115 |
|
|
35,898 |
|
Mexico Natural Gas
Pipelines |
|
7,058 |
|
|
5,716 |
|
Liquids Pipelines |
|
17,352 |
|
|
15,438 |
|
Energy |
|
8,475 |
|
|
8,503 |
|
Corporate |
|
3,513 |
|
|
3,642 |
|
|
|
98,920 |
|
|
86,101 |
|
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