TransCanada Corporation (TSX, NYSE: TRP) (TransCanada or the
Company) today announced net income attributable to common shares
for first quarter 2019 of $1.004 billion or $1.09 per share
compared to net income of $734 million or $0.83 per share for the
same period in 2018. Comparable earnings for first quarter 2019
were $987 million or $1.07 per common share compared to $864
million or $0.98 per common share for the same period in 2018.
TransCanada's Board of Directors also declared a quarterly dividend
of $0.75 per common share for the quarter ending June 30, 2019,
equivalent to $3.00 per common share on an annualized basis.
"We are very pleased with the performance of our diversified and
irreplaceable portfolio of high-quality, long-life energy
infrastructure assets which continued to produce record financial
results through the first quarter of 2019,” said Russ Girling,
TransCanada’s president and chief executive officer. “Comparable
earnings per share increased nine per cent compared to the same
period last year while comparable funds generated from operations
of $1.8 billion were eleven per cent higher. The increases reflect
the strong performance of our legacy assets along with
contributions from approximately $5.3 billion of growth projects
that were placed into service in first quarter 2019."
"With the demand for our existing assets driving historically
high utilization rates and $30 billion of secured growth projects
underway, approximately $7 billion of which are expected to be
completed by the end of the year, earnings and cash flow are
forecast to continue to rise. These projects are supported by
regulated or long-term contracted business models that are expected
to support annual dividend growth of eight to ten per cent through
2021,” added Girling. “We have invested $10 billion in these
projects to date and are well positioned to fund the remainder of
our secured growth program through significant and growing
internally generated cash flow and access to capital markets. We
also continue to progress various portfolio management activities,
including the announced sale of our Coolidge generating station
which is expected to close by mid-year. This will allow us to
prudently fund our capital program in a manner that is consistent
with achieving targeted leverage metrics, including debt-to-EBITDA
in the high four times area, in 2019 and thereafter and deliver
ongoing growth as measured on a per-share basis."
"Looking ahead, we continue to methodically advance more than
$20 billion of projects under development including Keystone XL and
the Bruce Power life extension program. Success in progressing
these and other growth initiatives that are expected to emanate
from our five operating businesses across North America could
extend our growth outlook well into the next decade," concluded
Girling.
Highlights(All financial figures are unaudited
and in Canadian dollars unless noted otherwise)
- First quarter 2019 financial results
- Net income attributable to common shares of $1.004 billion or
$1.09 per common share
- Comparable earnings of $987 million or $1.07 per common
share
- Comparable earnings before interest, taxes, depreciation and
amortization of $2.4 billion
- Net cash provided by operations of $1.9 billion
- Comparable funds generated from operations of $1.8 billion
- Comparable distributable cash flow of $1.6 billion or $1.76 per
common share
- Declared a quarterly dividend of $0.75 per common share for the
quarter ending June 30, 2019
- Placed approximately $5.3 billion of projects in service
including Mountaineer XPress, Gulf XPress and certain NGTL System
expansions
- Continued pre-construction activities on Coastal GasLink
pipeline project
- Received new Presidential Permit for Keystone XL
- Completed commissioning on White Spruce pipeline
- Issued $1.0 billion of 30-year fixed-rate medium-term notes in
April 2019.
Net income attributable to common shares increased by $270
million or $0.26 per common share to $1.004 billion or $1.09 per
share for the three months ended March 31, 2019 compared to the
same period last year. Per share results reflect the dilutive
impact of common shares issued under our DRP in 2018 and 2019 and
our Corporate ATM program in 2018. First quarter 2019 and 2018
results included an after-tax loss of $12 million and an after-tax
gain of $6 million, respectively, related to our U.S. Northeast
power marketing contracts. These specific items, as well as
unrealized gains and losses from changes in risk management
activities, are excluded from comparable earnings.
Comparable EBITDA increased by $320 million for the three months
ended March 31, 2019 compared to the same period in 2018 primarily
due to the net effect of the following:
- higher contribution from U.S. Natural Gas Pipelines mainly due
to increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service
- higher contribution from Liquids Pipelines primarily due to
higher volumes on the Keystone Pipeline System and increased
earnings from liquids marketing activities
- higher contribution from Canadian Natural Gas Pipelines mainly
due to the recovery of increased depreciation in 2019 as a result
of higher rates approved in both the Canadian Mainline NEB 2018
Decision and the NGTL 2018-2019 Settlement and higher incentive
earnings for the Canadian Mainline
- lower contribution from Power and Storage primarily due to the
sale of our interests in the Cartier Wind power facilities in 2018
and costs related to Napanee's delayed in-service
- foreign exchange impact of a stronger U.S. dollar on the
Canadian dollar equivalent earnings from our U.S. operations.
Comparable earnings increased by $123 million or $0.09 per
common share for the three months ended March 31, 2019
compared to the same period in 2018 and was primarily the net
effect of:
- changes in comparable EBITDA described above
- higher depreciation largely in Canadian Natural Gas Pipelines,
which is fully recovered in tolls as reflected in the increase in
comparable EBITDA described above, therefore having no impact on
comparable earnings. In addition, higher depreciation reflects new
projects placed in service
- higher interest expense primarily as a result of long-term debt
issuances, net of maturities, and the foreign exchange impact on
translation of U.S. dollar-denominated interest
- higher income tax expense due to higher comparable earnings
before income taxes and lower foreign tax rate differentials
- lower interest income and other due to realized losses in 2019
compared to realized gains in 2018 on derivatives used to manage
exposure to foreign exchange rate fluctuations on U.S.
dollar-denominated income
- higher AFUDC due to increased capital expenditures for our NGTL
System and Mexico projects.
Comparable earnings per common share for the three months ended
March 31, 2019 also reflects the dilutive impact of common shares
issued under our DRP in 2018 and 2019 and our Corporate ATM program
in 2018.
Notable recent developments include:
Canadian Natural Gas Pipelines:
- Coastal GasLink Pipeline Project: Following the October 2018
positive Final Investment Decision (FID) by LNG Canada,
pre-construction activities continue at many locations along the
pipeline route.The NEB process considering regulatory jurisdiction
continues with all evidence now submitted. A final hearing is
scheduled for second quarter 2019 with a decision expected in third
quarter 2019.TransCanada continues to advance funding plans for the
$6.2 billion pipeline project through a combination of the sale of
up to 75 per cent ownership interest and potential project
financing.
- NGTL System: In first quarter 2019, we placed approximately
$250 million of projects in service which included the Gordondale
Lateral Loop and the Boundary Lake North projects.On March 14,
2019, we filed the NGTL System Rate Design and Services Application
with the NEB which includes a settlement agreement negotiated
between NGTL and members of its Tolls, Tariff, Facilities and
Procedures (TTFP) committee, which represents stakeholders. The
settlement is supported by a majority of members of the TTFP
committee. The Application addresses rate design, terms and
conditions of service for the NGTL System and a tolling methodology
for the North Montney Mainline. Given the complexity of the issues
raised in the Application, the NEB decided to hold a public
hearing. Application to participate and comments on the Application
were due April 12, 2019 and reply comments were submitted by NGTL
on April 18, 2019.
U.S. Natural Gas Pipelines:
- Mountaineer XPress and Gulf XPress: The Mountaineer XPress
project, a Columbia Gas project designed to transport supply from
the Marcellus and Utica shale plays to points along the system and
the Leach interconnect with Columbia Gulf, was phased into service
over first quarter 2019 along with Gulf XPress, a Columbia Gulf
project.
- Grand Chenier XPress: In February 2019, we approved the Grand
Chenier XPress project, an ANR Pipeline project which will connect
supply directly to Gulf Coast LNG export markets through the
addition of a mid-point compressor station and incremental
compression capability at existing facilities. Subject to a
positive customer FID, the anticipated in-service dates are in 2021
and 2022 for Phase I and II, respectively, with estimated project
costs of US$0.2 billion.
Mexico Natural Gas Pipelines:
- Sur de Texas: The Sur de Texas project has experienced force
majeure events that have delayed in-service. Some events are
subject to potential dispute and we have taken measures to protect
our interests under the contract. Construction and commissioning
activities are progressing such that we anticipate mechanical
completion in May with an expected June 2019 in-service.
- Villa de Reyes and Tula: Construction of the Villa de Reyes
project is ongoing with a phased in-service anticipated to commence
in the second half of 2019. Commencement of construction of the
central segment of the Tula project has been delayed due to a lack
of progress by the Secretary of Energy, the governmental department
responsible for Indigenous consultations. Project completion has
been revised to the end of 2020. We have negotiated separate CFE
contracts that would allow certain segments of Tula and Villa de
Reyes to be placed in service when facilities are complete and gas
is available.
Liquids Pipelines:
- Keystone Pipeline System: In January 2019, we entered into an
agreement with Motiva Enterprises LLC (Motiva) to construct a
pipeline connection between the Keystone Pipeline system and
Motiva’s 630,000 Bbl/d refinery in Port Arthur, Texas. The
connection is targeted to be operational in second quarter
2020.
- Keystone XL: A decision from the Nebraska Supreme Court on the
appeal of the Nebraska Public Service Commission route approval
remains pending. We expect the decision to be issued in second
quarter 2019.In September 2018, two U.S. Native American
communities filed a lawsuit in Montana challenging the Keystone XL
Presidential Permit. We, along with the U.S. Government, have filed
to have the lawsuit dismissed. In December 2018, we applied to the
U.S. District Court in Montana for a stay of its various decisions
affecting the issuance of the 2017 Keystone XL Presidential Permit
and the extensive environmental assessments made in support of its
issuance. The stay application was denied by the U.S. District
Court in February 2019. In February 2019, we applied to the Ninth
Circuit Court of Appeals (Ninth Circuit) for a stay of the U.S.
District Court decisions. On March 16, 2019, the Ninth Circuit
denied our stay application and declined to further limit the scope
of the preliminary injunction which prevents us from conducting
certain pre-construction activities.On March 29, 2019, U.S.
President Trump issued a new Presidential Permit for the Keystone
XL Project, which superseded the 2017 permit. Subsequently, we
filed a motion with the Ninth Circuit requesting the court vacate
the U.S. District Court decisions, dissolve the injunctions, and
direct the U.S. District Court to dismiss the pending cases. A
lawsuit was filed challenging the validity of the new Presidential
Permit. We are not named in the lawsuit.
- White Spruce: Commissioning has been completed on the White
Spruce pipeline, which transports crude oil from Canadian Natural
Resources Limited's Horizon facility in northeast Alberta to the
Grand Rapids pipeline with commercial in-service achieved in May
2019.
Power and Storage (previously Energy):
- Napanee: In March 2019, we experienced an equipment failure
while progressing commissioning activities at our 900 MW natural
gas-fired power plant in Napanee, Ontario. We continue to expect
that our total investment in the Napanee facility will be
approximately $1.7 billion, however, commencement of commercial
operations will be delayed into the second half of 2019 as we
repair the damaged equipment.
- Coolidge Generating Station: In December 2018, we entered into
an agreement to sell our Coolidge generating station in Arizona to
SWG Coolidge Holdings, LLC (SWG). Salt River Project Agriculture
Improvement and Power District (SRP), the PPA counterparty,
subsequently exercised its contractual right of first refusal on a
sale to a third party. On March 20, 2019, we terminated the
agreement with SWG after entering into an agreement with SRP to
sell the Coolidge generating station for approximately US$465
million, subject to timing of the close and related adjustments.
The sale will result in an estimated gain of approximately $70
million ($55 million after tax) to be recognized upon closing,
which is expected to occur in mid-2019.
Corporate:
- Common Share Dividend: Our Board of Directors declared a
quarterly dividend of $0.75 per common share for the quarter ending
June 30, 2019 on TransCanada's outstanding common shares. The
quarterly amount is equivalent to $3.00 per common share on an
annualized basis.
- Issuance of Long-term Debt: In April 2019, TCPL issued $1.0
billion of Medium Term Notes due in October 2049 bearing interest
at a fixed rate of 4.34 per cent. The net proceeds of this debt
issuance were used for general corporate purposes and to fund our
capital program.In first quarter 2019, TCPL repaid $100 million of
Debentures bearing interest at a fixed rate of 10.50 per cent,
US$750 million of Senior Unsecured Notes bearing interest at a
fixed rate of 7.125 per cent and US$400 million of Senior Unsecured
Notes bearing interest at a fixed rate of 3.125 per cent.
- Dividend Reinvestment Plan: In first quarter 2019, the DRP
participation rate amongst common shareholders was approximately 33
per cent, resulting in $226 million reinvested in common equity
under the program.
Teleconference and Webcast:
We will hold a teleconference and webcast on Friday, May 3, 2019
to discuss our first quarter 2019 financial results. Russ Girling,
President and Chief Executive Officer, and Don Marchand, Executive
Vice-President and Chief Financial Officer, along with other
members of the executive leadership team, will discuss the
financial results and Company developments at 1 p.m. (MT) / 3 p.m.
(ET).
Members of the investment community and other interested parties
are invited to participate by calling 800.273.9672 or 416.340.2216
(Toronto area). Please dial in 10 minutes prior to the start of the
call. No pass code is required. A live webcast of the
teleconference will be available at www.transcanada.com or via
the following URL: http://www.gowebcasting.com/9939.
A replay of the teleconference will be available two hours after
the conclusion of the call until midnight (ET) on May 10, 2019.
Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter
pass code 7151952#.
The unaudited interim Condensed consolidated financial
statements and Management’s Discussion and Analysis (MD&A) are
available under TransCanada's profile on SEDAR at
www.sedar.com, with the U.S. Securities and Exchange
Commission on EDGAR at
www.sec.gov/info/edgar.shtml and on our website
at www.transcanada.com.
With more than 65 years' experience, TransCanada is a leader in
the responsible development and reliable operation of North
American energy infrastructure including natural gas and liquids
pipelines, power generation and gas storage facilities. We operate
one of the largest natural gas transmission networks that extends
more than 92,600 kilometres (57,500 miles), connecting major gas
supply basins to markets across North America. TransCanada is a
leading provider of gas storage and related services with 653
billion cubic feet of storage capacity. A large independent power
producer, we currently own or have interests in more than 6,600
megawatts of power generation in Canada and the United States. We
are also the developer and operator of one of North America's
leading liquids pipeline systems that extends approximately 4,900
kilometres (3,000 miles), connecting growing continental oil
supplies to key markets and refineries. TransCanada's common shares
trade on the Toronto and New York stock exchanges under the symbol
TRP. Visit TransCanada.com to learn more, or connect with us
on social media.
Forward Looking Information
This release contains certain information that is
forward-looking and is subject to important risks and uncertainties
(such statements are usually accompanied by words such as
"anticipate", "expect", "believe", "may", "will", "should",
"estimate", "intend" or other similar words). Forward-looking
statements in this document are intended to provide TransCanada
security holders and potential investors with information regarding
TransCanada and its subsidiaries, including management's assessment
of TransCanada's and its subsidiaries' future plans and financial
outlook. All forward-looking statements reflect TransCanada's
beliefs and assumptions based on information available at the time
the statements were made and as such are not guarantees of future
performance. Readers are cautioned not to place undue reliance on
this forward-looking information, which is given as of the date it
is expressed in this news release, and not to use future-oriented
information or financial outlooks for anything other than their
intended purpose. TransCanada undertakes no obligation to update or
revise any forward-looking information except as required by law.
For additional information on the assumptions made, and the risks
and uncertainties which could cause actual results to differ from
the anticipated results, refer to the Quarterly Report to
Shareholders dated May 2, 2019 and the 2018 Annual Report filed
under TransCanada's profile on SEDAR at www.sedar.com and with
the U.S. Securities and Exchange Commission at
www.sec.gov.
Non-GAAP MeasuresThis news release contains
references to non-GAAP measures, including comparable earnings,
comparable earnings per common share, comparable EBITDA, comparable
distributable cash flow, comparable distributable cash flow per
common share and comparable funds generated from operations, that
do not have any standardized meaning as prescribed by U.S. GAAP and
therefore are unlikely to be comparable to similar measures
presented by other companies. These non-GAAP measures are
calculated on a consistent basis from period to period and are
adjusted for specific items in each period, as applicable except as
otherwise described in the Condensed consolidated financial
statements and MD&A. For more information on non-GAAP measures,
refer to TransCanada's Quarterly Report to Shareholders dated May
2, 2019.
Media Enquiries:Grady Semmens403.920.7859 or
800.608.7859
Investor & Analyst
Enquiries: David Moneta / Duane
Alexander403.920.7911 or 800.361.6522
Quarterly report to shareholders
First quarter 2019
Financial highlights
|
three months ended March 31 |
(millions
of $, except per share amounts) |
|
2019 |
|
|
|
2018 |
|
|
|
|
|
Income |
|
|
|
Revenues |
|
3,487 |
|
|
|
3,424 |
|
Net income attributable
to common shares |
|
1,004 |
|
|
|
734 |
|
per
common share – basic and diluted |
$1.09 |
|
|
$0.83 |
|
Comparable EBITDA1 |
|
2,383 |
|
|
|
2,063 |
|
Comparable
earnings1 |
|
987 |
|
|
|
864 |
|
per
common share1 |
$1.07 |
|
|
$0.98 |
|
|
|
|
|
Cash
flows |
|
|
|
Net cash provided by
operations |
|
1,949 |
|
|
|
1,412 |
|
Comparable funds
generated from operations1 |
|
1,791 |
|
|
|
1,611 |
|
Comparable
distributable cash flow1 |
|
1,623 |
|
|
|
1,439 |
|
per
common share1 |
$1.76 |
|
|
$1.63 |
|
Capital spending2 |
|
2,331 |
|
|
|
2,096 |
|
|
|
|
|
Dividends
declared |
|
|
|
Per common share |
$0.75 |
|
|
$0.69 |
|
Basic common
shares outstanding (millions) |
|
|
|
–
weighted average for the period |
|
921 |
|
|
|
885 |
|
– issued and outstanding at end of period |
|
924 |
|
|
|
891 |
|
1 Comparable EBITDA, comparable earnings, comparable earnings
per common share, comparable funds generated from operations,
comparable distributable cash flow and comparable distributable
cash flow per common share are all non-GAAP measures. Refer to the
Non-GAAP measures section for more information.2 Includes capital
expenditures, capital projects in development and contributions to
equity investments.
Management’s discussion and analysis
May 2, 2019
This management’s discussion and analysis (MD&A) contains
information to help the reader make investment decisions about
TransCanada Corporation. It discusses our business, operations,
financial position, risks and other factors for the three months
ended March 31, 2019, and should be read with the accompanying
unaudited Condensed consolidated financial statements for the three
months ended March 31, 2019, which have been prepared in
accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our
December 31, 2018 audited Consolidated financial statements
and notes and the MD&A in our 2018 Annual
Report. Capitalized and abbreviated terms that are used but
not otherwise defined herein are identified in our 2018 Annual
Report. Certain comparative figures have been adjusted to reflect
the current period’s presentation.
FORWARD-LOOKING 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 MD&A include information
about the following, among other things:
- our financial and operational performance, including the
performance of our subsidiaries
- expectations about strategies and goals for growth and
expansion
- expected cash flows and future financing options available,
including portfolio management
- expected dividend growth
- expected access to and cost of capital
- expected costs and schedules for planned projects, including
projects under construction and in development
- expected capital expenditures and contractual obligations
- expected regulatory processes and outcomes
- expected outcomes with respect to legal proceedings, including
arbitration and insurance claims
- expected impact of future tax and accounting changes,
commitments and contingent liabilities
- expected industry, market and economic conditions.
Forward-looking statements do not guarantee future performance.
Actual events and results could be significantly different because
of assumptions, risks or uncertainties related to our business or
events that happen after the date of this MD&A.
Our forward-looking information is based on the following key
assumptions, and subject to the following risks and
uncertainties:
Assumptions
- regulatory decisions and outcomes
- planned and unplanned outages and the use of our pipeline,
power and storage assets
- integrity and reliability of our assets
- anticipated construction costs, schedules and completion
dates
- access to capital markets, including portfolio management
- expected industry, market and economic conditions
- inflation rates and commodity prices
- interest, tax and foreign exchange rates
- nature and scope of hedging.
Risks and uncertainties
- our ability to successfully implement our strategic priorities
and whether they will yield the expected benefits
- our ability to implement a capital allocation strategy aligned
with maximizing shareholder value
- the operating performance of our pipeline, power and storage
assets
- amount of capacity sold and rates achieved in our pipeline
businesses
- the amount of capacity payments and revenues from our power
generation assets due to plant availability
- production levels within supply basins
- construction and completion of capital projects
- costs for labour, equipment and materials
- the availability and market prices of commodities
- access to capital markets on competitive terms
- interest, tax and foreign exchange rates
- performance and credit risk of our counterparties
- regulatory decisions and outcomes of legal proceedings,
including arbitration and insurance claims
- changes in environmental and other laws and regulations
- competition in the pipeline, power and storage sectors
- unexpected or unusual weather
- acts of civil disobedience
- cyber security and technological developments
- economic conditions in North America as well as globally
- our ability to effectively anticipate and assess changes to
government policies and regulations.
You can read more about these factors and others in this
MD&A and in other reports we have filed with Canadian
securities regulators and the SEC, including the MD&A in our
2018 Annual Report.
As actual results could vary significantly from the
forward-looking information, you should not put undue reliance on
forward-looking information and should not use future-oriented
information or financial outlooks for anything other than their
intended purpose. We do not update our forward-looking statements
due to new information or future events, unless we are required to
by law.
FOR MORE INFORMATIONYou can find more
information about TransCanada in our Annual Information Form and
other disclosure documents, which are available on SEDAR
(www.sedar.com).
NON-GAAP MEASURESThis MD&A references the
following non-GAAP measures:
- comparable EBITDA
- comparable EBIT
- comparable earnings
- comparable earnings per common share
- funds generated from operations
- comparable funds generated from operations
- comparable distributable cash flow
- comparable distributable cash flow per common share.
These measures do not have any standardized meaning as
prescribed by GAAP and therefore may not be comparable to similar
measures presented by other entities.
Comparable 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
- acquisition and integration costs.
We exclude the unrealized gains and losses from changes in the
fair value of derivatives used to reduce our exposure to certain
financial and commodity price risks. These derivatives generally
provide effective economic hedges but do not meet the criteria for
hedge accounting. As a result, the changes in fair value are
recorded in net income. As these amounts do not accurately reflect
the gains and losses that will be realized at settlement, we do not
consider them reflective of our underlying operations.
The following table identifies our non-GAAP measures against
their most directly comparable GAAP measures.
Comparable measure |
GAAP measure |
|
|
comparable EBITDA |
segmented earnings |
comparable EBIT |
segmented earnings |
comparable earnings |
net income attributable to
common shares |
comparable earnings per
common share |
net income per common
share |
comparable funds generated
from operations |
net cash provided by
operations |
comparable distributable cash flow |
net cash provided by operations |
Comparable EBITDA and comparable 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.
Comparable earnings and comparable earnings per common
shareComparable earnings represents earnings or loss
attributable to common shareholders on a consolidated basis,
adjusted for specific items. Comparable earnings is comprised of
segmented earnings, Interest expense, AFUDC, Interest income and
other, Income taxes, Non-controlling interests and Preferred share
dividends, adjusted for specific items. Refer to the Consolidated
results section for reconciliations to net income attributable to
common shares and net income per common share.
Funds generated from operations and comparable funds
generated from 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. Refer
to the Financial condition section for a reconciliation to net cash
provided by operations.
Comparable distributable cash flow and comparable
distributable cash flow per common 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.
Maintenance capital expenditures are expenditures incurred to
maintain our operating capacity, asset integrity and reliability,
and include amounts attributable to our proportionate share of
maintenance capital expenditures on our equity investments. We
have the opportunity to recover effectively all of our pipeline
maintenance capital expenditures in Canadian Natural Gas Pipelines,
U.S. Natural Gas Pipelines and Liquids Pipelines through tolls. As
such, our presentation of comparable distributable cash flow and
comparable distributable cash flow per common share only includes a
reduction for non-recoverable maintenance capital expenditures in
their respective calculations.
Refer to the Financial condition section for a reconciliation to
net cash provided by operations.
Consolidated results – first quarter 2019
As of first quarter 2019, the previously disclosed Energy
segment has been renamed the Power and Storage segment.
|
|
three months ended March 31 |
(millions
of $, except per share amounts) |
|
|
2019 |
|
|
|
2018 |
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
|
269 |
|
|
|
253 |
|
U.S. Natural Gas
Pipelines |
|
|
792 |
|
|
|
648 |
|
Mexico Natural Gas
Pipelines |
|
|
116 |
|
|
|
137 |
|
Liquids Pipelines |
|
|
460 |
|
|
|
341 |
|
Power and Storage |
|
|
48 |
|
|
|
50 |
|
Corporate |
|
|
(19 |
) |
|
|
(81 |
) |
Total segmented
earnings |
|
|
1,666 |
|
|
|
1,348 |
|
Interest expense |
|
|
(586 |
) |
|
|
(527 |
) |
Allowance for funds
used during construction |
|
|
139 |
|
|
|
105 |
|
Interest
income and other |
|
|
163 |
|
|
|
63 |
|
Income before
income taxes |
|
|
1,382 |
|
|
|
989 |
|
Income
tax expense |
|
|
(236 |
) |
|
|
(121 |
) |
Net
income |
|
|
1,146 |
|
|
|
868 |
|
Net
income attributable to non-controlling interests |
|
|
(101 |
) |
|
|
(94 |
) |
Net income
attributable to controlling interests |
|
|
1,045 |
|
|
|
774 |
|
Preferred
share dividends |
|
|
(41 |
) |
|
|
(40 |
) |
Net income
attributable to common shares |
|
|
1,004 |
|
|
|
734 |
|
Net income per common share – basic and
diluted |
|
$1.09 |
|
|
$0.83 |
|
Net income attributable to common shares increased by $270
million, or $0.26 per common share, for the three months ended
March 31, 2019 compared to the same period in 2018. Net income
per common share reflects the dilutive impact of common shares
issued under our DRP in 2018 and 2019 and our Corporate ATM program
in 2018.
Net income included unrealized gains and losses from changes in
risk management activities which we exclude along with
other specific items as noted below to arrive at comparable
earnings. Results included an after-tax loss of $12 million and an
after-tax gain of $6 million for the three months ended
March 31, 2019 and 2018, respectively, related to our U.S.
Northeast power marketing contracts. These amounts have been
excluded from Power and Storage's comparable earnings as we do not
consider the wind-down and sales of the remaining contracts part of
our underlying operations.
A reconciliation of net income attributable to common shares to
comparable earnings is shown in the following table.
RECONCILIATION OF NET INCOME TO COMPARABLE
EARNINGS
|
|
three months ended March 31 |
(millions of $,
except per share amounts) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Net income
attributable to common shares |
|
1,004 |
|
|
734 |
|
Specific items
(net of tax): |
|
|
|
|
U.S.
Northeast power marketing contracts |
|
12 |
|
|
(6 |
) |
Risk management activities1 |
|
(29 |
) |
|
136 |
|
Comparable earnings |
|
987 |
|
|
864 |
|
Net income per
common share |
|
$1.09 |
|
|
$0.83 |
|
Specific items
(net of tax): |
|
|
|
|
U.S.
Northeast power marketing contracts |
|
0.01 |
|
|
— |
|
Risk management activities |
|
(0.03 |
) |
|
0.15 |
|
Comparable earnings per common share |
|
$1.07 |
|
|
$0.98 |
|
1 |
|
Risk management activities |
|
three months ended March 31 |
|
|
(millions
of $) |
|
2019 |
|
2018 |
|
|
|
|
|
|
|
|
|
Canadian Power |
|
(1 |
) |
|
2 |
|
|
|
U.S. Power |
|
(60 |
) |
|
(101 |
) |
|
|
Liquids marketing |
|
(15 |
) |
|
(7 |
) |
|
|
Natural Gas
Storage |
|
(3 |
) |
|
(3 |
) |
|
|
Foreign exchange |
|
120 |
|
|
(79 |
) |
|
|
Income tax attributable
to risk management activities |
|
(12 |
) |
|
52 |
|
|
|
Total unrealized gains/(losses) from risk management
activities |
|
29 |
|
|
(136 |
) |
COMPARABLE EBITDA TO COMPARABLE EARNINGS
Comparable EBITDA represents segmented earnings adjusted for
certain aspects of the specific items described above and excludes
non-cash charges for depreciation and amortization.
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Comparable
EBITDA |
|
|
|
|
Canadian
Natural Gas Pipelines |
|
556 |
|
|
494 |
|
U.S.
Natural Gas Pipelines |
|
972 |
|
|
804 |
|
Mexico
Natural Gas Pipelines |
|
146 |
|
|
160 |
|
Liquids
Pipelines |
|
563 |
|
|
431 |
|
Power and
Storage |
|
151 |
|
|
176 |
|
Corporate |
|
(5 |
) |
|
(2 |
) |
Comparable
EBITDA |
|
2,383 |
|
|
2,063 |
|
Depreciation and amortization |
|
(608 |
) |
|
(535 |
) |
Interest
expense |
|
(586 |
) |
|
(527 |
) |
Allowance
for funds used during construction |
|
139 |
|
|
105 |
|
Interest
income and other included in comparable earnings |
|
29 |
|
|
63 |
|
Income
tax expense included in comparable earnings |
|
(228 |
) |
|
(171 |
) |
Net
income attributable to non-controlling interests |
|
(101 |
) |
|
(94 |
) |
Preferred share dividends |
|
(41 |
) |
|
(40 |
) |
Comparable earnings |
|
987 |
|
|
864 |
|
Comparable EBITDA and comparable earnings – 2019 versus
2018
Comparable EBITDA increased by $320 million for the three months
ended March 31, 2019 compared to the same period in 2018 primarily
due to the net effect of the following:
- higher contribution from U.S. Natural Gas Pipelines mainly due
to increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service
- higher contribution from Liquids Pipelines primarily due to
higher volumes on the Keystone Pipeline System and increased
earnings from liquids marketing activities
- higher contribution from Canadian Natural Gas Pipelines mainly
due to the recovery of increased depreciation in 2019 as a result
of higher rates approved in both the Canadian Mainline NEB 2018
Decision and the NGTL 2018-2019 Settlement and higher incentive
earnings for the Canadian Mainline
- lower contribution from Power and Storage primarily due to the
sale of our interests in the Cartier Wind power facilities in 2018
and costs related to Napanee's delayed in-service
- foreign exchange impact of a stronger U.S. dollar on the
Canadian dollar equivalent earnings from our U.S. operations.
Comparable earnings increased by $123 million or $0.09 per
common share for the three months ended March 31, 2019
compared to the same period in 2018 and was primarily the net
effect of:
- changes in comparable EBITDA described above
- higher depreciation largely in Canadian Natural Gas Pipelines,
which is fully recovered in tolls as reflected in the increase in
comparable EBITDA described above, therefore having no impact on
comparable earnings. In addition, higher depreciation reflects new
projects placed in service
- higher interest expense primarily as a result of long-term debt
issuances, net of maturities, and the foreign exchange impact on
translation of U.S. dollar-denominated interest
- higher income tax expense due to higher comparable earnings
before income taxes and lower foreign tax rate differentials
- lower interest income and other due to realized losses in 2019
compared to realized gains in 2018 on derivatives used to manage
exposure to foreign exchange rate fluctuations on U.S.
dollar-denominated income
- higher AFUDC due to increased capital expenditures for our NGTL
System and Mexico projects.
Comparable earnings per common share for the three months ended
March 31, 2019 also reflects the dilutive impact of common
shares issued under our DRP in 2018 and 2019 and our Corporate ATM
program in 2018.
Capital Program
We are developing quality projects under our capital program.
These long-life infrastructure assets are supported by long-term
commercial arrangements with creditworthy counterparties or
regulated business models and are expected to generate significant
growth in earnings and cash flows.
Our capital program consists of approximately $30.3 billion of
secured projects which include commercially supported, committed
projects that are either under construction or are in or preparing
to commence the permitting stage but are not yet fully approved. An
additional $21.5 billion of projects under development are
commercially supported except where noted but have greater
uncertainty with respect to timing and estimated project costs and
are subject to certain approvals. During first quarter 2019, we
placed approximately $5.3 billion of projects in service including
Mountaineer XPress, Gulf XPress, and certain NGTL System
expansions.
Three years of maintenance capital expenditures for our
businesses are included in the secured projects table. Maintenance
capital expenditures on our regulated Canadian and U.S. natural gas
pipelines businesses are added to rate base on which we have the
opportunity to earn a return and recover these expenditures through
current or future tolls, which is similar to our capacity capital
projects on these pipelines. Tolling arrangements in our liquids
pipelines business provide for the recovery of maintenance capital
expenditures.
All projects are subject to cost adjustments due to weather,
market conditions, route refinement, permitting conditions,
scheduling and timing of regulatory permits, among other factors.
Amounts presented in the following tables exclude capitalized
interest and AFUDC.
Secured projects
|
|
Expected in-service date |
|
Estimated project cost1 |
|
|
Carrying value at March 31, 2019 |
|
(billions
of $) |
|
|
|
|
|
|
|
Canadian
Natural Gas Pipelines |
|
|
|
|
|
|
Canadian Mainline |
|
2019-2022 |
|
0.3 |
|
|
0.1 |
|
NGTL System |
|
2019 |
|
2.8 |
|
|
2.0 |
|
|
|
2020 |
|
1.8 |
|
|
0.3 |
|
|
|
2021 |
|
2.6 |
|
|
— |
|
|
|
2022+ |
|
1.4 |
|
|
— |
|
Coastal GasLink2,3 |
|
2023 |
|
6.2 |
|
|
0.2 |
|
Regulated maintenance
capital expenditures |
|
2019-2021 |
|
1.6 |
|
|
0.2 |
|
U.S. Natural
Gas Pipelines |
|
|
|
|
|
|
Columbia Gas |
|
|
|
|
|
|
Modernization II |
|
2019-2020 |
|
US
1.1 |
|
|
US
0.5 |
|
Other capacity
capital |
|
2019-2021 |
|
US
0.5 |
|
|
— |
|
Regulated maintenance
capital expenditures |
|
2019-2021 |
|
US
1.8 |
|
|
US
0.1 |
|
Mexico Natural
Gas Pipelines |
|
|
|
|
|
|
Sur de Texas4 |
|
2019 |
|
US
1.5 |
|
|
US
1.4 |
|
Villa de Reyes4 |
|
2019-2020 |
|
US
0.8 |
|
|
US
0.7 |
|
Tula4 |
|
2020 |
|
US
0.7 |
|
|
US
0.6 |
|
Liquids
Pipelines |
|
|
|
|
|
|
White Spruce |
|
2019 |
|
0.2 |
|
|
0.2 |
|
Other capacity
capital |
|
2020 |
|
0.1 |
|
|
— |
|
Recoverable maintenance
capital expenditures |
|
2019-2021 |
|
0.1 |
|
|
— |
|
Power and
Storage |
|
|
|
|
|
|
Napanee |
|
2019 |
|
1.7 |
|
|
1.7 |
|
Bruce Power – life
extension5 |
|
2019-2023 |
|
2.2 |
|
|
0.7 |
|
Other |
|
|
|
|
|
|
Non-recoverable maintenance capital expenditures6 |
|
2019-2021 |
|
0.7 |
|
|
0.1 |
|
|
|
|
|
28.1 |
|
|
8.8 |
|
Foreign
exchange impact on secured projects7 |
|
|
|
2.2 |
|
|
1.1 |
|
Total secured projects (Cdn$) |
|
|
|
30.3 |
|
|
9.9 |
|
1 Amounts reflect our proportionate share of joint venture costs
where applicable and 100 per cent of costs related to wholly-owned
assets and assets held through TC PipeLines, LP.2 Represents 100
per cent of required capital prior to potential joint venture
partners or project financing.3 Carrying value is net of the fourth
quarter 2018 receipts from the LNG Canada participants for the
reimbursement of approximately $0.5 billion of pre-FID costs
pursuant to project agreements.4 The CFE has recognized force
majeure events for these pipelines and approved the payment of
fixed capacity charges in accordance with their respective TSAs.
Payments will be recognized as revenue over the contract service
term commencing once the pipelines are placed in service.5 Reflects
our proportionate share of the Unit 6 Major Component Replacement
program costs, expected to be in service in 2023, and amounts to be
invested under the Asset Management program through 2023.6 Includes
non-recoverable maintenance capital expenditures from all segments
and is primarily comprised of our proportionate share of
maintenance capital expenditures for Bruce Power and other Power
and Storage assets.7 Reflects U.S./Canada foreign exchange rate of
1.34 at March 31, 2019.
Projects under developmentThe costs provided in
the table below reflect the most recent estimates for each project
as filed with the various regulatory authorities or otherwise
determined by management.
|
|
Estimated project cost1 |
|
|
Carrying valueat March 31,
2019 |
|
(billions
of $) |
|
|
|
|
|
Canadian
Natural Gas Pipelines |
|
|
|
|
NGTL
System – Merrick |
|
1.9 |
|
|
— |
|
U.S. Natural
Gas Pipelines |
|
|
|
|
Other
capacity capital2 |
|
US
0.7 |
|
|
— |
|
Liquids
Pipelines |
|
|
|
|
Keystone
XL3 |
|
US
8.0 |
|
|
US
0.7 |
|
Heartland
and TC Terminals4 |
|
0.9 |
|
|
0.1 |
|
Grand
Rapids Phase 24 |
|
0.7 |
|
|
— |
|
Keystone
Hardisty Terminal4 |
|
0.3 |
|
|
0.1 |
|
Power and
Storage |
|
|
|
|
Bruce Power – life extension5 |
|
6.0 |
|
|
— |
|
|
|
18.5 |
|
|
0.9 |
|
Foreign exchange impact
on projects under development6 |
|
3.0 |
|
|
0.2 |
|
Total projects under development (Cdn$) |
|
21.5 |
|
|
1.1 |
|
1 Amounts reflect our proportionate share of joint venture costs
where applicable and 100 per cent of costs related to wholly-owned
assets and assets held through TC PipeLines, LP.2 Includes
projects subject to a positive customer FID.3 Carrying value
reflects amount remaining after impairment charge recorded in 2015
along with additional amounts capitalized from January 1, 2018. A
portion of these costs are recoverable from shippers under certain
conditions.4 Regulatory approvals have been obtained and additional
commercial support is being pursued.5 Reflects our proportionate
share of Major Component Replacement program costs for Units 3, 4,
5, 7 and 8, and the remaining Asset Management program costs beyond
2023.6 Reflects U.S./Canada foreign exchange rate of 1.34 at
March 31, 2019.
Outlook
Consolidated comparable earningsOur overall
comparable earnings outlook for 2019 remains consistent with the
disclosure in the 2018 Annual Report.
Consolidated capital spendingOur expected total
capital expenditures as outlined in the 2018 Annual Report remain
materially unchanged.
Canadian Natural Gas PipelinesThe following is
a reconciliation of comparable EBITDA and comparable EBIT (our
non-GAAP measures) to segmented earnings (the most directly
comparable GAAP measure).
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
NGTL System |
|
292 |
|
|
271 |
|
Canadian Mainline |
|
237 |
|
|
193 |
|
Other
Canadian pipelines1 |
|
27 |
|
|
30 |
|
Comparable
EBITDA |
|
556 |
|
|
494 |
|
Depreciation and
amortization |
|
(287 |
) |
|
(241 |
) |
Comparable EBIT and segmented earnings |
|
269 |
|
|
253 |
|
1 Includes results from Foothills, Ventures LP, Great Lakes
Canada and our share of equity income from our investment in TQM as
well as general and administrative and business development costs
related to our Canadian Natural Gas Pipelines.
Canadian Natural Gas Pipelines comparable EBIT and segmented
earnings increased by $16 million for the three months ended
March 31, 2019 compared to the same period in 2018.
Net income and comparable EBITDA for our rate-regulated Canadian
natural gas pipelines are primarily affected by our approved ROE,
our investment base, the level of deemed common equity and
incentive earnings. Changes in depreciation, financial charges and
income taxes also impact comparable EBITDA but do not have a
significant impact on net income as they are almost entirely
recovered in revenue on a flow-through basis.
NET INCOME AND AVERAGE INVESTMENT BASE
|
three months ended March 31 |
(millions of
$) |
2019 |
|
|
2018 |
|
|
|
|
|
Net
Income |
|
|
|
NGTL
System |
113 |
|
|
92 |
|
Canadian
Mainline |
44 |
|
|
37 |
|
Average
investment base |
|
|
|
NGTL
System |
11,096 |
|
|
9,091 |
|
Canadian Mainline |
3,665 |
|
|
3,817 |
|
Net income for the NGTL System increased by $21 million for the
three months ended March 31, 2019 compared to the same period
in 2018 mainly due to a higher average investment base resulting
from continued system expansions. The NGTL System is operating
under the 2018-2019 Settlement which includes an ROE of 10.1 per
cent on 40 per cent deemed common equity, a mechanism for sharing
variances above and below a fixed annual OM&A amount and
flow-through treatment of all other costs.
Net income for the Canadian Mainline increased by $7 million for
the three months ended March 31, 2019 compared to the same
period in 2018 mainly due to higher incentive earnings. We did not
record incentive earnings in first quarter 2018 pending the outcome
of the 2018-2020 toll review. The NEB 2018 Decision, received in
December 2018, preserved the incentive arrangement from the NEB
2014 Decision along with an approved ROE of 10.1 per cent on 40 per
cent deemed equity.
COMPARABLE EBITDAComparable EBITDA increased by
$62 million for the three months ended March 31, 2019 compared
to the same period in 2018 mainly due to the recovery of increased
depreciation as a result of higher rates approved in both the
Canadian Mainline NEB 2018 Decision and the NGTL 2018-2019
Settlement, as well as higher pre-tax rate base earnings for the
NGTL System and higher incentive earnings and flow-through income
taxes for the Canadian Mainline.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization increased by $46 million for the three months ended
March 31, 2019 compared to the same period in 2018 mainly due
to the increase in composite depreciation rates approved in the
Mainline NEB 2018 Decision and the NGTL 2018-2019 Settlement as
well as additional NGTL System facilities that were placed in
service in 2018 and first quarter 2019.
U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended March 31 |
(millions
of US$, unless otherwise noted) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Columbia Gas |
|
308 |
|
|
231 |
|
ANR |
|
153 |
|
|
141 |
|
TC PipeLines,
LP1,2 |
|
36 |
|
|
39 |
|
Great Lakes3 |
|
30 |
|
|
35 |
|
Midstream |
|
37 |
|
|
30 |
|
Columbia Gulf |
|
35 |
|
|
26 |
|
Other U.S.
pipelines4 |
|
19 |
|
|
15 |
|
Non-controlling
interests5 |
|
112 |
|
|
118 |
|
Comparable EBITDA |
|
730 |
|
|
635 |
|
Depreciation and amortization |
|
(135 |
) |
|
(122 |
) |
Comparable
EBIT |
|
595 |
|
|
513 |
|
Foreign
exchange impact |
|
197 |
|
|
135 |
|
Comparable EBIT and segmented earnings (Cdn$) |
|
792 |
|
|
648 |
|
1 Reflects our earnings from TC PipeLines, LP’s ownership
interests in eight natural gas pipelines as well as general and
administrative costs related to TC PipeLines, LP.2 For the three
months ended March 31, 2019, our ownership interest in TC
PipeLines, LP was 25.5 per cent, which is unchanged from the same
period in 2018.3 Reflects our 53.55 per cent direct interest in
Great Lakes. The remaining 46.45 per cent is held by TC PipeLines,
LP.4 Reflects earnings from our effective ownership in Millennium
and Hardy Storage, as well as general and administrative and
business development costs related to our U.S. natural gas
pipelines.5 Reflects earnings attributable to portions of TC
PipeLines, LP, that we do not own.
U.S. Natural Gas Pipelines comparable EBIT and segmented
earnings increased by $144 million for the three months ended
March 31, 2019 compared to the same period in 2018. In
addition to the net increases in comparable EBITDA noted below, a
stronger U.S. dollar in 2019 had a positive impact on the Canadian
dollar equivalent segmented earnings from our U.S. operations
compared to the same period in 2018.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by
US$95 million for the three months ended March 31, 2019
compared to the same period in 2018. This was primarily the
net effect of:
- increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service
- decreased earnings from Bison due to 2018 customer agreements
to pay out their future contracted revenues and terminate their
contracts.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization increased by US$13 million for the three months ended
March 31, 2019 compared to the same period in 2018 mainly due
to new projects placed in service.
Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended March 31 |
(millions
of US$, unless otherwise noted) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Topolobampo |
|
40 |
|
|
44 |
|
Tamazunchale |
|
31 |
|
|
31 |
|
Mazatlán |
|
18 |
|
|
20 |
|
Guadalajara |
|
16 |
|
|
19 |
|
Sur de Texas1 |
|
5 |
|
|
9 |
|
Other |
|
— |
|
|
4 |
|
Comparable EBITDA |
|
110 |
|
|
127 |
|
Depreciation and
amortization |
|
(23 |
) |
|
(19 |
) |
Comparable EBIT |
|
87 |
|
|
108 |
|
Foreign exchange
impact |
|
29 |
|
|
29 |
|
Comparable EBIT and segmented earnings (Cdn$) |
|
116 |
|
|
137 |
|
1 Represents equity income from our 60 per cent interest.
Mexico Natural Gas Pipelines comparable EBIT and segmented
earnings decreased by $21 million for the three months ended
March 31, 2019 compared to the same period in 2018. Lower
EBITDA as described below was partially offset by a stronger U.S.
dollar in 2019 which had a positive impact on Canadian dollar
equivalent earnings.
Comparable EBITDA for Mexico Natural Gas Pipelines decreased by
US$17 million for the three months ended March 31, 2019
compared to the same period in 2018 mainly due to the net effect
of:
- lower revenues from operations as a result of changes in timing
of revenue recognition in 2018
- lower equity earnings from our investment in the Sur de Texas
pipeline which records AFUDC during construction, net of interest
expense on an inter-affiliate loan from TransCanada. The
inter-affiliate loan amount is fully offset in Interest income and
other in the Corporate segment
- a TransGas distribution received and recorded as income in
2018, recorded in Other above.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization was higher for the three months ended March 31,
2019 compared to the same period in 2018 reflecting new assets in
service and other adjustments.
Liquids Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Keystone Pipeline
System |
|
424 |
|
|
340 |
|
Intra-Alberta
pipelines |
|
39 |
|
|
39 |
|
Liquids
marketing and other |
|
100 |
|
|
52 |
|
Comparable
EBITDA |
|
563 |
|
|
431 |
|
Depreciation and amortization |
|
(88 |
) |
|
(83 |
) |
Comparable
EBIT |
|
475 |
|
|
348 |
|
Specific item: |
|
|
|
|
Risk management activities |
|
(15 |
) |
|
(7 |
) |
Segmented
earnings |
|
460 |
|
|
341 |
|
|
|
|
|
|
Comparable EBIT
denominated as follows: |
|
|
|
|
Canadian dollars |
|
89 |
|
|
93 |
|
U.S. dollars |
|
290 |
|
|
202 |
|
Foreign
exchange impact |
|
96 |
|
|
53 |
|
Comparable EBIT |
|
475 |
|
|
348 |
|
Liquids Pipelines segmented earnings increased by $119 million
for the three months ended March 31, 2019 compared to the same
period in 2018 and include unrealized losses from changes in the
fair value of derivatives related to our liquids marketing business
which have been excluded from our calculation of comparable
EBIT.
Comparable EBITDA for Liquids Pipelines increased by $132
million for the three months ended March 31, 2019 compared to
the same period in 2018 and was due to:
- higher volumes on the Keystone Pipeline System
- higher contribution from liquids marketing activities due to
improved margins and volumes
- positive foreign exchange impact on the Canadian dollar
equivalent earnings from our U.S. operations.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization increased by $5 million for the three months ended
March 31, 2019 compared to the same period in 2018 as a result
of new facilities being placed in service and the effect of a
stronger U.S. dollar.
Power and Storage
As of first quarter 2019, the previously disclosed Energy
segment has been renamed the Power and Storage segment.
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Western and Eastern
Power1 |
|
77 |
|
|
119 |
|
Bruce Power1 |
|
60 |
|
|
54 |
|
Natural Gas Storage and
other |
|
17 |
|
|
7 |
|
Business
development |
|
(3 |
) |
|
(4 |
) |
Comparable
EBITDA |
|
151 |
|
|
176 |
|
Depreciation and
amortization |
|
(23 |
) |
|
(32 |
) |
Comparable EBIT |
|
128 |
|
|
144 |
|
Specific items: |
|
|
|
|
U.S.
Northeast power marketing contracts |
|
(16 |
) |
|
8 |
|
Risk
management activities |
|
(64 |
) |
|
(102 |
) |
Segmented earnings |
|
48 |
|
|
50 |
|
1 Includes our share of equity income from our investments in
Portlands Energy and Bruce Power.
Power and Storage segmented earnings decreased by $2 million for
the three months ended March 31, 2019 compared to the same
period in 2018 and included the following specific items:
- a loss of $16 million for the three months ended March 31,
2019 (2018 – gain of $8 million) related to our U.S. Northeast
power marketing contracts. These amounts have been excluded from
Power and Storage's comparable earnings as we do not consider the
wind-down and sales of the remaining contracts part of our
underlying operations
- unrealized losses from changes in the fair value of derivatives
used to reduce our exposure to certain commodity price risks,
primarily related to the remaining U.S. Northeast power marketing
contracts.
Comparable EBITDA for Power and Storage decreased by $25 million
for the three months ended March 31, 2019 compared to the same
period in 2018 primarily due to the net effect of:
- decreased Western and Eastern Power results largely due to the
sale of our interests in the Cartier Wind power facilities in
October 2018 and costs related to Napanee's delayed in-service.
Refer to the Recent developments section for more information
- increased Natural Gas Storage results due to higher realized
natural gas storage price spreads
- increased Bruce Power results primarily due to higher income on
funds invested for future retirement benefits, partially offset by
lower volumes resulting from higher outage days. Additional
financial and operating information on Bruce Power is provided
below.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization decreased by $9 million for the three months ended
March 31, 2019 compared to the same period in 2018 primarily
due to the sale of our interests in the Cartier Wind power
facilities in October 2018 and the cessation of depreciation on our
Coolidge generating station upon classification as held for sale at
December 31, 2018.
BRUCE POWERThe following reflects our
proportionate share of the components of comparable EBITDA and
comparable EBIT.
|
|
three months ended March 31 |
(millions of $,
unless otherwise noted) |
|
|
2019 |
|
|
|
2018 |
|
|
|
|
|
|
Equity income
included in comparable EBITDA and EBIT comprised of: |
|
|
|
|
Revenues1 |
|
|
361 |
|
|
|
371 |
|
Operating
expenses |
|
|
(227 |
) |
|
|
(227 |
) |
Depreciation and other |
|
|
(74 |
) |
|
|
(90 |
) |
Comparable EBITDA and EBIT2 |
|
|
60 |
|
|
|
54 |
|
Bruce
Power – other information |
|
|
|
|
Plant
availability3 |
|
|
79 |
% |
|
|
85 |
% |
Planned outage
days |
|
|
141 |
|
|
|
74 |
|
Unplanned outage
days |
|
|
7 |
|
|
|
31 |
|
Sales volumes
(GWh)2 |
|
|
5,260 |
|
|
|
5,696 |
|
Realized
sales price per MWh4 |
|
$68 |
|
|
$67 |
|
1 Net of amounts recorded to reflect operating cost efficiencies
shared with the IESO.2 Represents our 48.3 per cent (2018 – 48.4
per cent) ownership interest in Bruce Power. Sales volumes include
deemed generation.3 The percentage of time the plant was available
to generate power, regardless of whether it was running.4
Calculation based on actual and deemed generation. Realized sales
prices per MWh includes realized gains and losses from contracting
activities and cost flow-through items. Excludes unrealized gains
and losses on contracting activities and non-electricity
revenues.
Planned maintenance on Unit 3 began in fourth quarter 2018 and
on Unit 7 in February 2019, with both units expected to be back in
service in second quarter 2019. Planned maintenance is expected to
occur on Unit 2 in second quarter 2019 and on Unit 5 in the second
half of 2019. The overall average plant availability percentage in
2019 is expected to be in the mid-80 per cent range.
On April 1, 2019, Bruce Power's contract price increased from
approximately $68 per MWh to approximately $75 per MWh reflecting
capital to be invested under the Unit 6 Major Component Replacement
program and the Asset Management program as well as normal annual
inflation adjustments.
Corporate
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented losses (the
most directly comparable GAAP measure).
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Comparable
EBITDA and EBIT |
|
(5 |
) |
|
(2 |
) |
Specific item: |
|
|
|
|
Foreign
exchange loss – inter-affiliate loan1 |
|
(14 |
) |
|
(79 |
) |
Segmented losses |
|
(19 |
) |
|
(81 |
) |
1 Reported in Income from equity investments on the Condensed
consolidated statement of income.
Corporate segmented losses decreased by $62 million for the
three months ended March 31, 2019 compared to the same period
in 2018. Segmented losses include foreign exchange losses on a
peso-denominated inter-affiliate loan to the Sur de Texas project
for our proportionate share of the project's financing which are
fully offset by corresponding foreign exchange gains included in
Interest income and other on the inter-affiliate loan receivable.
These amounts have been excluded from our calculation of comparable
EBIT.
OTHER INCOME STATEMENT ITEMS
Interest Expense
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Interest on
long-term debt and junior subordinated notes |
|
|
|
|
Canadian
dollar-denominated |
|
(140 |
) |
|
(134 |
) |
U.S.
dollar-denominated |
|
(331 |
) |
|
(314 |
) |
Foreign
exchange impact |
|
(109 |
) |
|
(83 |
) |
|
|
(580 |
) |
|
(531 |
) |
Other interest and
amortization expense |
|
(43 |
) |
|
(22 |
) |
Capitalized interest |
|
37 |
|
|
26 |
|
Interest expense |
|
(586 |
) |
|
(527 |
) |
Interest expense increased by $59 million for the three months
ended March 31, 2019 compared to the same period in 2018 and
primarily reflects the net effect of:
- long-term debt issuances, net of maturities
- foreign exchange impact from a stronger U.S. dollar on
translation of U.S. dollar-denominated interest
- higher levels of short-term borrowing
- higher capitalized interest primarily related to Napanee and
Keystone XL.
Allowance for funds used during
construction
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Canadian
dollar-denominated |
|
43 |
|
|
20 |
|
U.S.
dollar-denominated |
|
72 |
|
|
67 |
|
Foreign exchange
impact |
|
24 |
|
|
18 |
|
Allowance for funds used during construction |
|
139 |
|
|
105 |
|
AFUDC increased by $34 million for the three months ended
March 31, 2019 compared to the same period in 2018. The
increase in Canadian dollar-denominated AFUDC is primarily due to
capital expenditures in our NGTL System expansion projects. The
increase in U.S. dollar-denominated AFUDC is primarily due to
continued investment in Mexico projects.
Interest income and other
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Interest income
and other included in comparable earnings |
|
29 |
|
|
63 |
|
Specific items: |
|
|
|
|
Foreign
exchange gain – inter-affiliate loan |
|
14 |
|
|
79 |
|
Risk management activities |
|
120 |
|
|
(79 |
) |
Interest income and other |
|
163 |
|
|
63 |
|
Interest income and other increased by $100
million for the three months ended March 31, 2019 compared to
the same period in 2018 and was primarily the net effect of:
- unrealized gains on risk management activities in 2019 compared
to unrealized losses in 2018. These amounts have been excluded from
comparable earnings
- higher interest income combined with a lower foreign exchange
gain related to an inter-affiliate loan receivable from the Sur de
Texas joint venture. The corresponding interest expense and foreign
exchange loss in Sur de Texas are reflected in Income from equity
investments in the Mexico Natural Gas Pipelines and Corporate
segments, respectively, resulting in no impact on net income. The
offsetting currency-related gain and loss amounts are excluded from
comparable earnings
- realized losses in 2019 compared to realized gains in 2018 on
derivatives used to manage our net exposure to foreign exchange
rate fluctuations on U.S. dollar-denominated income.
Income tax expense
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Income tax
expense included in comparable earnings |
|
(228 |
) |
|
(171 |
) |
Specific items: |
|
|
|
|
U.S.
Northeast power marketing contracts |
|
4 |
|
|
(2 |
) |
Risk
management activities |
|
(12 |
) |
|
52 |
|
Income tax expense |
|
(236 |
) |
|
(121 |
) |
Income tax expense included in comparable earnings increased by
$57 million for the three months ended March 31, 2019 compared
to the same period in 2018. This was primarily due to higher
comparable earnings before income taxes and lower foreign tax rate
differentials.
Net income attributable to non-controlling
interests
|
|
three months ended March 31 |
(millions of
$) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Net income attributable to non-controlling
interests |
|
(101 |
) |
|
(94 |
) |
Net income attributable to non-controlling interests increased
by $7 million for the three months ended March 31, 2019
compared to the same period in 2018 primarily due to higher
earnings in TC PipeLines, LP and the impact of a stronger U.S.
dollar in 2019 on the Canadian dollar equivalent earnings.
Preferred share dividends
|
|
three months ended March 31 |
(millions of
$) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Preferred share dividends |
|
(41 |
) |
|
(40 |
) |
Recent developments
CANADIAN NATURAL GAS PIPELINES
Coastal GasLink Pipeline ProjectFollowing the
October 2018 positive FID by LNG Canada, pre-construction
activities continue at many locations along the pipeline route
including the area south of Houston, B.C. which required a B.C.
Supreme Court injunction for access.
The NEB process considering regulatory jurisdiction continues
with all evidence now submitted. A final hearing is scheduled for
second quarter 2019 with a decision expected in third quarter
2019.
TransCanada continues to advance funding plans for the $6.2
billion pipeline project through a combination of the sale of up to
75 per cent ownership interest and potential project financing.
NGTL SystemOn March 14, 2019, we filed the NGTL
System Rate Design and Services Application with the NEB which
includes a settlement agreement negotiated between NGTL and members
of its Tolls, Tariff, Facilities and Procedures (TTFP) committee,
which represents stakeholders. The settlement is supported by a
majority of members of the TTFP committee. The Application
addresses rate design, terms and conditions of service for the NGTL
System and a tolling methodology for the North Montney Mainline.
Given the complexity of the issues raised in the Application, the
NEB decided to hold a public hearing. Application to participate
and comments on the Application were due April 12, 2019 and reply
comments were submitted by NGTL on April 18, 2019.
In first quarter 2019, we placed approximately $250 million of
projects in service which included the Gordondale Lateral Loop and
the Boundary Lake North projects.
Canadian Mainline 2018-2020 Toll ReviewOn March
13, 2019, the NEB approved Canadian Mainline tolls as filed in the
January 2019 compliance filing.
U.S. NATURAL GAS PIPELINES
Mountaineer XPress and Gulf XPressThe
Mountaineer XPress project, a Columbia Gas project designed to
transport supply from the Marcellus and Utica shale plays to points
along the system and the Leach interconnect with Columbia Gulf, was
phased into service over first quarter 2019 along with Gulf XPress,
a Columbia Gulf project.
Grand Chenier XPressIn February 2019, we
approved the Grand Chenier XPress project, an ANR Pipeline project
which will connect supply directly to Gulf Coast LNG export markets
through the addition of a mid-point compressor station and
incremental compression capability at existing facilities. Subject
to a positive customer FID, the anticipated in-service dates are in
2021 and 2022 for Phase I and II, respectively, with estimated
project costs of US$0.2 billion.
MEXICO NATURAL GAS PIPELINES
Sur de TexasThe Sur de Texas project has
experienced force majeure events that have delayed in-service. Some
events are subject to potential dispute and we have taken measures
to protect our interests under the contract. Construction and
commissioning activities are progressing such that we anticipate
mechanical completion in May with an expected June 2019
in-service.
Villa de Reyes and TulaConstruction of the
Villa de Reyes project is ongoing with a phased in-service
anticipated to commence in the second half of 2019. Commencement of
construction for the central segment of the Tula project has
been delayed due to a lack of progress by the Secretary of Energy,
the governmental department responsible for Indigenous
consultations. Project completion has been revised to the end of
2020. We have negotiated separate CFE contracts that would allow
certain segments of Tula and Villa de Reyes to be placed in service
when facilities are complete and gas is available.
LIQUIDS PIPELINES
Keystone Pipeline SystemIn January 2019, we
entered into an agreement with Motiva Enterprises LLC (Motiva) to
construct a pipeline connection between the Keystone Pipeline
system and Motiva’s 630,000 Bbl/d refinery in Port Arthur, Texas.
The connection is targeted to be operational in second quarter
2020.
On February 6, 2019, the Keystone Pipeline system was
temporarily shut down after a leak was detected near St. Charles,
Missouri. The pipeline system was restarted the same day while the
segment between Steele City, Nebraska to Patoka, Illinois was
restarted on February 18, 2019. This shutdown is not expected to
have a significant impact on our 2019 earnings.
Keystone XLA decision from the Nebraska Supreme
Court on the appeal of the Nebraska Public Service Commission route
approval remains pending. We expect the decision to be issued in
second quarter 2019.
In September 2018, two U.S. Native American communities filed a
lawsuit in Montana challenging the Keystone XL Presidential Permit.
We, along with the U.S. Government, have filed to have the lawsuit
dismissed. In December 2018, we applied to the U.S. District Court
in Montana for a stay of its various decisions affecting the
issuance of the 2017 Keystone XL Presidential Permit and the
extensive environmental assessments made in support of its
issuance. The stay application was denied by the U.S. District
Court in February 2019. In February 2019, we applied to the Ninth
Circuit Court of Appeals (Ninth Circuit) for a stay of the U.S.
District Court decisions. On March 16, 2019, the Ninth Circuit
denied our stay application and declined to further limit the scope
of the preliminary injunction which prevents us from conducting
certain pre-construction activities.
On March 29, 2019, U.S. President Trump issued a new
Presidential Permit for the Keystone XL Project, which superseded
the 2017 permit. Subsequently, we filed a motion with the Ninth
Circuit requesting the court vacate the U.S. District Court
decisions, dissolve the injunctions, and direct the U.S. District
Court to dismiss the pending cases. A lawsuit was filed challenging
the validity of the new Presidential Permit. We are not named in
the lawsuit.
White SpruceCommissioning has been completed on
the White Spruce pipeline, which transports crude oil from Canadian
Natural Resources Limited's Horizon facility in northeast Alberta
to the Grand Rapids pipeline with commercial in-service achieved in
May 2019.
POWER AND STORAGE (Previously ENERGY)
NapaneeIn March 2019, we experienced an
equipment failure while progressing commissioning activities at our
900 MW natural gas-fired power plant in Napanee, Ontario. We
continue to expect that our total investment in the Napanee
facility will be approximately $1.7 billion, however, commencement
of commercial operations will be delayed into the second half of
2019 as we repair the damaged equipment.
Coolidge Generating StationIn December 2018, we
entered into an agreement to sell our Coolidge generating station
in Arizona to SWG Coolidge Holdings, LLC (SWG). Salt River Project
Agriculture Improvement and Power District (SRP), the PPA
counterparty, subsequently exercised its contractual right of first
refusal on a sale to a third party. On March 20, 2019, we
terminated the agreement with SWG after entering into an agreement
with SRP to sell the Coolidge generating station for approximately
US$465 million, subject to timing of the close and related
adjustments. The sale will result in an estimated gain of
approximately $70 million ($55 million after tax) to be recognized
upon closing, which is expected to occur in mid-2019.
Financial condition
We strive to maintain strong financial capacity and flexibility
in all parts of the economic cycle. We rely on our operating cash
flow to sustain our business, pay dividends and fund a portion of
our growth. In addition, we access capital markets and engage in
portfolio management to meet our financing needs, manage our
capital structure and to preserve our credit ratings.
We believe we have the financial capacity to fund our existing
capital program through predictable and growing cash flow from
operations, access to capital markets, portfolio management, cash
on hand, substantial committed credit facilities, and if deemed
appropriate, our Corporate ATM program and DRP. Annually, in fourth
quarter, we renew and extend our credit facilities as required.
At March 31, 2019, our current assets totaled $4.9 billion
and current liabilities amounted to $13.4 billion, leaving us with
a working capital deficit of $8.5 billion compared to $7.8 billion
at December 31, 2018. Our working capital deficiency is
considered to be in the normal course of business and is managed
through:
- our ability to generate predictable and growing cash flow from
operations
- approximately $11.7 billion of unutilized, unsecured credit
facilities
- our access to capital markets, including through our DRP and
Corporate ATM programs, if deemed appropriate.
CASH PROVIDED BY OPERATING ACTIVITIES
|
|
three months ended March 31 |
(millions
of $, except per share amounts) |
|
|
2019 |
|
|
|
2018 |
|
|
|
|
|
|
Net cash provided by
operations |
|
|
1,949 |
|
|
|
1,412 |
|
(Decrease)/increase in
operating working capital |
|
|
(142 |
) |
|
|
207 |
|
Funds generated from operations |
|
|
1,807 |
|
|
|
1,619 |
|
Specific items: |
|
|
|
|
U.S.
Northeast power marketing contracts |
|
|
(16 |
) |
|
|
(8 |
) |
Comparable funds generated from operations |
|
|
1,791 |
|
|
|
1,611 |
|
Dividends on preferred
shares |
|
|
(40 |
) |
|
|
(39 |
) |
Distributions to
non-controlling interests |
|
|
(56 |
) |
|
|
(69 |
) |
Non-recoverable maintenance capital expenditures1 |
|
|
(72 |
) |
|
|
(64 |
) |
Comparable
distributable cash flow |
|
|
1,623 |
|
|
|
1,439 |
|
Comparable distributable cash flow per common share |
|
$1.76 |
|
|
$1.63 |
|
1 Includes non-recoverable maintenance capital expenditures from
all segments including cash contributions to fund our proportionate
share of maintenance capital expenditures for our equity
investments which are primarily related to contributions to Bruce
Power.
NET CASH PROVIDED BY OPERATIONSNet cash
provided by operations increased by $537 million for the three
months ended March 31, 2019 compared to the same period in
2018, primarily due to higher earnings, the recovery of increased
depreciation on Canadian regulated pipelines as well as the amount
and timing of working capital changes.
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 $180
million for the three months ended March 31, 2019 compared to
the same period in 2018 primarily due to higher comparable earnings
adjusted for non-cash items and the cash impact of specific items
as well as the recovery of higher depreciation for both the
Canadian Mainline and the NGTL System.
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 March 31, 2019 compared to the same period in
2018 reflects higher comparable funds generated from operations as
described above. Comparable distributable cash flow per common
share for the three months ended March 31, 2019 also reflects
the dilutive impact of common shares issued under our DRP in 2018
and 2019 and our Corporate ATM program in 2018.
CASH USED IN INVESTING ACTIVITIES
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Capital
spending |
|
|
|
|
Capital
expenditures |
|
(2,022 |
) |
|
(1,702 |
) |
Capital
projects in development |
|
(164 |
) |
|
(36 |
) |
Contributions to equity investments |
|
(145 |
) |
|
(358 |
) |
|
|
(2,331 |
) |
|
(2,096 |
) |
Other distributions
from equity investments |
|
120 |
|
|
121 |
|
Deferred amounts and
other |
|
(26 |
) |
|
110 |
|
Net cash used in investing activities |
|
(2,237 |
) |
|
(1,865 |
) |
Capital expenditures in first quarter 2019 were incurred
primarily for the expansion of the NGTL System and Columbia Gas
projects along with construction of the Coastal GasLink pipeline
and Napanee power generating facility.
Costs incurred on capital projects in development in 2019 and
2018 were mostly attributed to spending on Keystone XL.
Contributions to equity investments decreased in 2019 compared
to 2018 mainly due to lower contributions to Sur de Texas which
include our proportionate share of debt financing requirements.
Other distributions from equity investments in 2019 and 2018
reflect our proportionate share of Bruce Power financings
undertaken to fund its capital program and to make distributions to
its partners. In first quarter 2019, we received distributions of
$120 million (2018 – $121 million) from Bruce Power in connection
with their issuance of senior notes in capital markets.
CASH PROVIDED BY FINANCING ACTIVITIES
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Notes payable issued,
net |
|
2,852 |
|
|
1,812 |
|
Long-term debt issued,
net of issue costs1 |
|
24 |
|
|
93 |
|
Long-term debt
repaid1 |
|
(1,708 |
) |
|
(1,226 |
) |
Dividends and
distributions paid |
|
(515 |
) |
|
(466 |
) |
Common shares issued,
net of issue costs |
|
68 |
|
|
340 |
|
Partnership units of TC
PipeLines, LP issued, net of issue costs |
|
— |
|
|
49 |
|
Net cash provided by financing activities |
|
721 |
|
|
602 |
|
1 Includes draws and repayments on an unsecured loan facility by
TC PipeLines, LP.
LONG-TERM DEBT ISSUEDThe following table
outlines significant debt issuances in 2019:
(millions of Canadian $, unless otherwise noted) |
|
|
|
|
|
|
Company |
|
Issue date |
|
Type |
|
Maturity Date |
|
Amount |
|
|
Interest rate |
|
|
|
|
|
|
|
|
|
|
|
TRANSCANADA PIPELINES LIMITED |
|
|
|
|
|
|
|
|
|
|
April 2019 |
|
Medium Term Notes |
|
October 2049 |
|
1,000 |
|
|
4.34% |
The net proceeds of the above debt issuance were used for
general corporate purposes and to fund our capital program.
LONG-TERM DEBT REPAIDThe following table
outlines significant debt retired in 2019:
(millions of Canadian $, unless otherwise noted) |
|
|
|
|
Company |
|
Retirement date |
|
Type |
|
Amount |
|
|
Interest rate |
|
|
|
|
|
|
|
|
|
TRANSCANADA PIPELINES LIMITED |
|
|
|
|
|
|
|
|
March 2019 |
|
Debentures |
|
100 |
|
|
10.50% |
|
|
January 2019 |
|
Senior Unsecured Notes |
|
US 750 |
|
|
7.125% |
|
|
January 2019 |
|
Senior Unsecured
Notes |
|
US
400 |
|
|
3.125% |
DIVIDEND REINVESTMENT PLANWith respect to
dividends declared on February 14, 2019, the DRP participation rate
amongst common shareholders was approximately 33 per cent,
resulting in $226 million reinvested in common equity under the
program.
DIVIDENDSOn May 2, 2019, we declared
quarterly dividends as follows:
Quarterly dividend on our common
shares |
|
|
$0.75 per share |
Payable on
July 31, 2019 to shareholders of record at the close of business on
June 28, 2019. |
Quarterly dividends on our preferred
shares |
|
|
Payable on June 28, 2019 to
shareholders of record at the close of business on May 31,
2019: |
Series
1 |
$0.204125 |
Series
2 |
$0.22450822 |
Series
3 |
$0.1345 |
Series
4 |
$0.18461781 |
Payable on July 30,
2019 to shareholders of record at the close of business on July 2,
2019: |
Series
5 |
$0.14143750 |
Series
6 |
$0.19895342 |
Series
7 |
$0.243938 |
Series
9 |
$0.265625 |
Payable on May 31,
2019 to shareholders of record at the close of business on May 15,
2019: |
Series
11 |
$0.2375 |
Series
13 |
$0.34375 |
Series 15 |
$0.30625 |
SHARE INFORMATION
as at April 30, 2019 |
|
|
|
|
|
Common
shares |
Issued and outstanding |
|
|
927 million |
|
Preferred
shares |
Issued and outstanding |
Convertible to |
Series 1 |
9.5
million |
Series 2
preferred shares |
Series 2 |
12.5
million |
Series 1
preferred shares |
Series 3 |
8.5
million |
Series 4
preferred shares |
Series 4 |
5.5
million |
Series 3
preferred shares |
Series 5 |
12.7
million |
Series 6
preferred shares |
Series 6 |
1.3
million |
Series 5
preferred shares |
Series 71 |
24
million |
Series 8
preferred shares |
Series 9 |
18
million |
Series 10
preferred shares |
Series 11 |
10
million |
Series 12
preferred shares |
Series 13 |
20
million |
Series 14
preferred shares |
Series 15 |
40
million |
Series 16
preferred shares |
|
|
|
Options to buy
common shares |
Outstanding |
Exercisable |
|
13 million |
9 million |
1 As the total number of Series 7 preferred shares tendered for
conversion did not meet the threshold for conversion, no Series 7
preferred shares were converted into Series 8 preferred shares on
April 30, 2019.
CREDIT FACILITIESWe have
several committed credit facilities that support our commercial
paper programs and provide short-term liquidity for general
corporate purposes. In addition, we have demand credit facilities
that are also used for general corporate purposes, including
issuing letters of credit and providing additional liquidity.
At April 30, 2019, we had a total of $12.8 billion of committed
revolving and demand credit facilities, including:
Amount |
|
Unusedcapacity |
|
Borrower |
|
Description |
|
Matures |
|
|
|
|
|
|
|
|
|
Committed, syndicated, revolving, extendible senior
unsecured credit facilities: |
$3.0 billion |
|
$3.0 billion |
|
TCPL |
|
Supports TCPL's Canadian
dollar commercial paper program and is used for general corporate
purposes |
|
December 2023 |
US$4.5 billion |
|
US$4.5 billion |
|
TCPL/TCPL
USA/Columbia/TAIL |
|
Supports TCPL and TCPL
USA's U.S. dollar commercial paper programs and is used for general
corporate purposes of the borrowers, guaranteed by TCPL |
|
December 2019 |
US$1.0 billion |
|
US$1.0 billion |
|
TCPL/TCPL
USA/Columbia/TAIL |
|
Used for general corporate
purposes of the borrowers, guaranteed by TCPL |
|
December 2021 |
Demand senior unsecured revolving credit
facilities: |
$2.1 billion |
|
$1.0 billion |
|
TCPL/TCPL USA |
|
Supports the issuance of
letters of credit and provides additional liquidity, TCPL USA
facility guaranteed by TCPL |
|
Demand |
MXN$5.0 billion |
|
MXN$5.0 billion |
|
Mexican subsidiary |
|
Used for Mexico general corporate purposes, guaranteed by TCPL |
|
Demand |
At April 30, 2019, our operated affiliates had an additional
$0.8 billion of undrawn capacity on committed credit
facilities.
Refer to Financial risks and financial instruments for more
information about liquidity, market and other risks.
CONTRACTUAL OBLIGATIONSOur capital
expenditure commitments have risen by approximately $0.2 billion
since December 31, 2018. This increase is primarily due to
increased commitments related to the construction of Coastal
GasLink, Columbia growth projects and advancement of Keystone XL,
partially offset by decreased commitments for the NGTL System and
the White Spruce pipeline.
There were no other material changes to our contractual
obligations in first quarter 2019 or to payments due in the next
five years or after. Refer to the MD&A in our 2018 Annual
Report for more information about our contractual obligations.
Financial risks and financial instruments
We are exposed to market risk and counterparty credit risk and
have strategies, policies and limits in place to manage the impact
of these risks on our earnings, cash flow and, ultimately,
shareholder value. Risk management strategies, policies and limits
are designed to ensure our risks and related exposures are in line
with our business objectives and risk tolerance.
Refer to our 2018 Annual Report for more information about the
risks we face in our business. Our risks have not changed
substantially since December 31, 2018.
INTEREST RATE RISKWe utilize short-term and
long-term debt to finance our operations which exposes us to
interest rate risk. We typically pay fixed rates of interest on our
long-term debt and floating rates on our commercial paper programs
and amounts drawn on our credit facilities. A small portion of our
long-term debt is at floating interest rates. In addition, we are
exposed to interest rate risk on financial instruments and
contractual obligations containing variable interest rate
components. We manage our interest rate risk using a combination of
interest rate swaps and option derivatives.
FOREIGN EXCHANGE RISKWe generate revenues and
incur expenses that are denominated in currencies other than
Canadian dollars. As a result, our earnings and cash flows are
exposed to currency fluctuations.
A portion of our businesses generate earnings in U.S. dollars,
but since we report our financial results in Canadian dollars,
changes in the value of the U.S. dollar against the Canadian dollar
can affect our net income. As our U.S. dollar-denominated
operations continue to grow, this exposure increases. A portion of
this risk is offset by interest expense on U.S. dollar-denominated
debt. The balance of the exposure is actively managed on a rolling
one-year basis using foreign exchange derivatives, however the
natural exposure beyond that period remains.
Average exchange rate – U.S. to Canadian
dollarsThe average exchange rate for one U.S. dollar
converted into Canadian dollars was as follows:
three months
ended March 31, 2019 |
1.33 |
|
three months ended March
31, 2018 |
1.27 |
|
The impact of changes in the value of the U.S. dollar on our
U.S. and Mexico operations is partially offset by interest on U.S.
dollar-denominated debt as set out in the table below. Comparable
EBIT is a non-GAAP measure.
Significant U.S. dollar-denominated amounts
|
|
three months ended March 31 |
(millions of US$) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
U.S. Natural Gas
Pipelines comparable EBIT |
|
595 |
|
|
513 |
|
Mexico Natural Gas
Pipelines comparable EBIT1 |
|
113 |
|
|
130 |
|
U.S. Liquids Pipelines
comparable EBIT |
|
290 |
|
|
202 |
|
Interest on U.S.
dollar-denominated long-term debt and junior subordinated
notes |
|
(331 |
) |
|
(314 |
) |
Capitalized interest on
U.S. dollar-denominated capital expenditures |
|
6 |
|
|
3 |
|
U.S. dollar-denominated
allowance for funds used during construction |
|
72 |
|
|
67 |
|
U.S. dollar comparable
non-controlling interests and other |
|
(81 |
) |
|
(80 |
) |
|
|
664 |
|
|
521 |
|
1 Excludes interest expense on our inter-affiliate loan with Sur
de Texas which is offset in Interest income and other.
Net investment hedgesWe hedge our net
investment in foreign operations (on an after-tax basis) with U.S.
dollar-denominated debt, cross-currency swaps and foreign exchange
options.
COUNTERPARTY CREDIT RISKWe have exposure to
counterparty credit risk in the following areas:
- cash and cash equivalents
- accounts receivable
- available-for-sale assets
- the fair value of derivative assets
- a loan receivable.
We monitor counterparties and review our accounts receivable
regularly. We record allowances for doubtful accounts using the
specific identification method. At March 31, 2019, we had no
significant credit losses, no significant credit risk concentration
and no significant amounts past due or impaired.
We have significant credit and performance exposure to financial
institutions because they hold cash deposits and provide committed
credit lines and letters of credit that help manage our exposure to
counterparties and provide liquidity in commodity, foreign exchange
and interest rate derivative markets.
LIQUIDITY RISKWe manage our liquidity risk by
continuously forecasting our cash flow and making sure we have
adequate cash balances, cash flow from operations, committed and
demand credit facilities and access to capital markets to meet our
operating, financing and capital expenditure obligations under both
normal and stressed economic conditions.
LOAN RECEIVABLE FROM AFFILIATEWe hold a 60 per
cent equity interest in a joint venture with IEnova to build, own
and operate the Sur de Texas pipeline. We account for our interest
in the joint venture as an equity investment. In 2017, we entered
into a MXN$21.3 billion unsecured revolving credit facility with
the joint venture, which bears interest at a floating rate and
matures in March 2022.
At March 31, 2019, our Condensed consolidated balance sheet
included a MXN$19.4 billion or $1.3 billion (December 31, 2018
– MXN$18.9 billion or $1.3 billion) loan receivable from the Sur de
Texas joint venture which represents our proportionate share of
long-term debt financing requirements related to the joint venture.
Interest income and other included interest income of $35 million
for the three months ended March 31, 2019 (2018 – $27 million)
from this joint venture with a corresponding proportionate share of
interest expense recorded in Income from equity investments.
FINANCIAL INSTRUMENTSWith the exception of
Long-term debt and Junior subordinated notes, our derivative and
non-derivative financial instruments are recorded on the balance
sheet at fair value unless they were entered into and continue to
be held for the purpose of receipt or delivery in accordance with
our normal purchase and sales exemptions and are documented as
such. In addition, fair value accounting is not required for other
financial instruments that qualify for certain accounting
exemptions.
Derivative instrumentsWe use derivative
instruments to reduce volatility associated with fluctuations in
commodity prices, interest rates and foreign exchange
rates. Derivative instruments, including those that qualify
and are designated for hedge accounting treatment, are recorded at
fair value.
The majority of derivative instruments that are not designated
or do not qualify for hedge accounting treatment have been entered
into as economic hedges to manage our exposure to market risk and
are classified as held for trading. Changes in the fair value
of held-for-trading derivative instruments are recorded in net
income in the period of change. This may expose us to
increased variability in reported operating results since the fair
value of the held-for-trading derivative instruments can fluctuate
significantly from period to period.
Balance sheet presentation of derivative
instrumentsThe balance sheet presentation of the fair
value of derivative instruments is as follows:
(millions of
$) |
|
March 31,
2019 |
|
|
December
31, 2018 |
|
|
|
|
|
|
Other
current assets |
|
313 |
|
|
737 |
|
Intangible and other assets |
|
35 |
|
|
61 |
|
Accounts payable and other |
|
(389 |
) |
|
(922 |
) |
Other
long-term liabilities |
|
(49 |
) |
|
(42 |
) |
|
|
(90 |
) |
|
(166 |
) |
Unrealized and realized (losses)/gains on derivative
instrumentsThe following summary does not include hedges
of our net investment in foreign operations.
|
|
three months ended March 31 |
(millions
of $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Derivative
instruments held for trading1 |
|
|
|
|
Amount of unrealized
(losses)/gains in the period |
|
|
|
|
Commodities2 |
|
(88 |
) |
|
(109 |
) |
Foreign
exchange |
|
120 |
|
|
(79 |
) |
Amount of realized
gains/(losses) in the period |
|
|
|
|
Commodities |
|
107 |
|
|
110 |
|
Foreign
exchange |
|
(29 |
) |
|
15 |
|
Derivative
instruments in hedging relationships |
|
|
|
|
Amount of realized
(losses)/gains in the period |
|
|
|
|
Commodities |
|
(7 |
) |
|
3 |
|
Interest rate |
|
— |
|
|
1 |
|
1 Realized and unrealized gains and losses on held-for-trading
derivative instruments used to purchase and sell commodities are
included on a net basis in Revenues. Realized and unrealized gains
and losses on interest rate and foreign exchange held-for-trading
derivative instruments are included on a net basis in Interest
expense and Interest income and other, respectively.2 In the three
months ended March 31, 2019 and 2018, there were no gains or
losses included in Net income relating to discontinued cash flow
hedges where it was probable that the anticipated transaction would
not occur.
Effect of fair value and cash flow hedging
relationshipsThe following table details amounts presented
on the Condensed consolidated statement of income and in which
accounts the effects of fair value or cash flow hedging
relationships are recorded.
|
|
three months ended March 31 |
|
|
Revenues (Power and Storage) |
|
Interest Expense |
(millions of
$) |
|
2019 |
|
|
2018 |
|
|
2019 |
|
|
2018 |
|
|
|
|
|
|
|
|
|
|
Total Amount
Presented in the Condensed Consolidated Statement of
Income |
|
336 |
|
|
675 |
|
|
(586 |
) |
|
(527 |
) |
Fair Value
Hedges |
|
|
|
|
|
|
|
|
Interest rate
contracts |
|
|
|
|
|
|
|
|
Hedged
items |
|
— |
|
|
— |
|
|
(6 |
) |
|
(20 |
) |
Derivatives
designated as hedging instruments |
|
— |
|
|
— |
|
|
(1 |
) |
|
— |
|
Cash Flow
Hedges |
|
|
|
|
|
|
|
|
Reclassification of
gains/(losses) on derivative instruments from AOCI to net income1,
2 |
|
|
|
|
|
|
|
|
Interest
rate contracts |
|
— |
|
|
— |
|
|
4 |
|
|
5 |
|
Commodity contracts |
|
— |
|
|
(1 |
) |
|
— |
|
|
— |
|
1 Refer to our Condensed consolidated financial statements for
the components of OCI related to derivatives in cash flow hedging
relationships including the portion attributable to non-controlling
interests.2 There are no amounts recognized in earnings that were
excluded from effectiveness testing.
Credit-risk-related contingent features of derivative
instrumentsDerivatives often contain financial assurance
provisions that may require us to provide collateral if a
credit-risk-related contingent event occurs (for example, if our
credit rating is downgraded to non-investment grade). We may also
need to provide collateral if the fair value of our derivative
financial instruments exceeds pre-defined exposure limits.
Based on contracts in place and market prices at March 31,
2019, the aggregate fair value of all derivative contracts with
credit-risk-related contingent features that were in a net
liability position was $4 million (December 31, 2018 – $6
million), with no collateral provided in the normal course of
business. If the credit-risk-related contingent features in these
agreements were triggered on March 31, 2019, we would have
been required to provide collateral of $4 million
(December 31, 2018 – $6 million) to our counterparties.
Collateral may also need to be provided should the fair value of
derivative instruments exceed pre-defined contractual exposure
limit thresholds.
We have sufficient liquidity in the form of cash and undrawn
committed revolving bank lines to meet these contingent obligations
should they arise.
Other information
CONTROLS AND PROCEDURESManagement, including
our President and CEO and our CFO, evaluated the effectiveness of
our disclosure controls and procedures as at March 31, 2019,
as required by the Canadian securities regulatory authorities and
by the SEC, and concluded that our disclosure controls and
procedures are effective at a reasonable assurance level.
There were no changes in first quarter 2019 that had or are
likely to have a material impact on our internal control over
financial reporting.
CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY
CHANGESWhen we prepare financial statements that conform
with U.S. GAAP, we are required to make estimates and assumptions
that affect the timing and amounts we record for our assets,
liabilities, revenues and expenses because these items may be
affected by future events. We base the estimates and assumptions on
the most current information available, using our best judgement.
We also regularly assess the assets and liabilities themselves. A
summary of our critical accounting estimates is included in our
2018 Annual Report.
Our significant accounting policies have remained unchanged
since December 31, 2018 other than described below. A summary
of our significant accounting policies is included in our 2018
Annual Report.
Changes in accounting policies for 2019
LeasesIn February 2016, the FASB issued new
guidance on the accounting for leases. The new guidance amends the
definition of a lease such that, in order for an arrangement to
qualify as a lease, the lessee is required to have both (1) the
right to obtain substantially all of the economic benefits from the
use of the asset and (2) the right to direct the use of the asset.
The new guidance also establishes a right-of-use (ROU) model that
requires a lessee to recognize a ROU asset and corresponding lease
liability on the balance sheet for all leases with a term longer
than twelve months. Leases will be classified as finance or
operating, with classification affecting the pattern of expense
recognition in the consolidated statement of income. The new
guidance does not make extensive changes to lessor accounting.
The new guidance was effective January 1, 2019 and was applied
using optional transition relief which allowed entities to
initially apply the new lease standard at adoption (January 1,
2019) and recognize a cumulative-effect adjustment to the opening
balance of retained earnings in the period of adoption. This
transition option allowed us to not apply the new guidance,
including disclosure requirements, to the comparative periods
presented.
We elected available practical expedients and exemptions upon
adoption which allowed us:
- not to reassess prior conclusions on existing leases regarding
lease identification, lease classification and initial direct costs
under the new standard
- to carry forward the historical lease classification and our
accounting treatment for land easements on existing agreements
- to not recognize ROU assets or lease liabilities for leases
that qualify for the short-term lease recognition exemption
- to not separate lease and non-lease components for all leases
for which we are the lessee and for facility and liquids tank
terminals for which we are the lessor
- to use hindsight in determining the lease term and assessing
ROU assets for impairment.
The new guidance had a significant impact on our Condensed
consolidated balance sheet, but did not have an impact on our
Condensed consolidated statements of income and cash flows. The
most significant impact was the recognition of ROU assets and lease
liabilities for operating leases and providing significant new
disclosures about our leasing activities. Refer to our Condensed
consolidated financial statements for further information related
to the impact of adopting the new guidance and our updated
accounting policies related to leases.
In the application of the new guidance, significant assumptions
and judgments are used to determine the following:
- whether a contract contains a lease
- the duration of the lease term including exercising lease
renewal options. The lease term for all of our leases includes the
noncancellable period of the lease plus any additional periods
covered by either our option to extend (or not to terminate) the
lease that we are reasonably certain to exercise, or an option to
extend (or not to terminate) the lease controlled by the
lessor
- the discount rate for the lease.
Fair value measurementIn August 2018, the FASB
issued new guidance that amends certain disclosure requirements for
fair value measurements. This new guidance is effective January 1,
2020, however, early adoption of certain or all requirements is
permitted. We elected to adopt this guidance effective first
quarter 2019. The guidance was applied retrospectively and did not
have a material impact on our consolidated financial
statements.
Future accounting changes
Measurement of credit losses on financial
instrumentsIn June 2016, the FASB issued new guidance that
significantly changes how entities measure credit losses for most
financial assets and certain other financial instruments that are
not measured at fair value through net income. The new guidance
amends the impairment model of financial instruments, basing it on
expected losses rather than incurred losses. These expected credit
losses will be recognized as an allowance rather than as a direct
write down of the amortized cost basis. The new guidance is
effective January 1, 2020 and will be applied using a modified
retrospective approach. We are currently evaluating the impact of
the adoption of this guidance and have not yet determined the
effect on our consolidated financial statements.
Defined benefit plansIn August 2018, the FASB
issued new guidance which amends and clarifies disclosure
requirements related to defined benefit pension and other
post-retirement benefit plans. This new guidance is effective
January 1, 2021 and will be applied on a retrospective basis,
however, early adoption is permitted. We are currently evaluating
the timing and impact of the adoption of this guidance and have not
yet determined the effect on our consolidated financial
statements.
Implementation costs of cloud computing
arrangementsIn August 2018, the FASB issued new guidance
requiring an entity in a hosting arrangement that is a service
contract to follow the guidance for internal-use software to
determine which implementation costs should be capitalized as an
asset and which costs should be expensed. The guidance also
requires the entity to amortize the capitalized implementation
costs of a hosting arrangement over the term of the arrangement.
This guidance is effective January 1, 2020, however, early adoption
is permitted. This guidance can be applied either retrospectively
or prospectively to all implementation costs incurred after the
date of adoption. We are currently evaluating the timing and impact
of adoption of this guidance and have not yet determined the effect
on our consolidated financial statements.
ConsolidationIn October 2018, the FASB issued
new guidance for determining whether fees paid to decision makers
and service providers are variable interests for indirect interests
held through related parties under common control. This new
guidance is effective January 1, 2020 and will be applied on a
retrospective basis, however, early adoption is permitted. We are
currently evaluating the timing and impact of the adoption of this
guidance and have not yet determined the effect on our consolidated
financial statements.
Quarterly results
SELECTED QUARTERLY CONSOLIDATED FINANCIAL
DATA
|
|
2019 |
|
|
|
2018 |
|
|
|
2017 |
(millions
of $, exceptper share amounts) |
First |
|
|
Fourth |
|
|
Third |
|
|
Second |
|
|
First |
|
|
Fourth |
|
|
Third |
|
|
Second |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
3,487 |
|
|
|
3,904 |
|
|
|
3,156 |
|
|
|
3,195 |
|
|
|
3,424 |
|
|
|
3,617 |
|
|
|
3,195 |
|
|
|
3,230 |
|
Net income attributable
to common shares |
|
1,004 |
|
|
|
1,092 |
|
|
|
928 |
|
|
|
785 |
|
|
|
734 |
|
|
|
861 |
|
|
|
612 |
|
|
|
881 |
|
Comparable
earnings |
|
987 |
|
|
|
946 |
|
|
|
902 |
|
|
|
768 |
|
|
|
864 |
|
|
|
719 |
|
|
|
614 |
|
|
|
659 |
|
Share statistics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per common share – basic and diluted |
$1.09 |
|
|
$1.19 |
|
|
$1.02 |
|
|
$0.88 |
|
|
$0.83 |
|
|
$0.98 |
|
|
$0.70 |
|
|
$1.01 |
|
Comparable earnings per common share |
$1.07 |
|
|
$1.03 |
|
|
$1.00 |
|
|
$0.86 |
|
|
$0.98 |
|
|
$0.82 |
|
|
$0.70 |
|
|
$0.76 |
|
Dividends declared per common share |
$0.75 |
|
|
$0.69 |
|
|
$0.69 |
|
|
$0.69 |
|
|
$0.69 |
|
|
$0.625 |
|
|
$0.625 |
|
|
$0.625 |
|
FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY
BUSINESS SEGMENTQuarter-over-quarter revenues and net
income fluctuate for reasons that vary across our business
segments.
In our Canadian Natural Gas Pipelines, U.S. Natural Gas
Pipelines and Mexico Natural Gas Pipelines segments, except for
seasonal fluctuations in short-term throughput volumes on
U.S. pipelines, quarter-over-quarter revenues and net income
generally remain relatively stable during any fiscal year. Over the
long term, however, they fluctuate because of:
- regulators' decisions
- negotiated settlements with shippers
- newly constructed assets being placed in service
- acquisitions and divestitures
- developments outside of the normal course of operations.
In Liquids Pipelines, annual revenues and net income are based
on contracted and uncommitted spot transportation and liquids
marketing activities. Quarter-over-quarter revenues and net income
are affected by:
- regulatory decisions
- newly constructed assets being placed in service
- acquisitions and divestitures
- demand for uncontracted transportation services
- liquids marketing activities
- developments outside of the normal course of operations
- certain fair value adjustments.
In Power and Storage, quarter-over-quarter revenues and net
income are affected by:
- weather
- customer demand
- newly constructed assets being placed in service
- acquisitions and divestitures
- market prices for natural gas and power
- capacity prices and payments
- planned and unplanned plant outages
- developments outside of the normal course of operations
- certain fair value adjustments.
FACTORS AFFECTING FINANCIAL INFORMATION BY
QUARTERWe calculate comparable measures by adjusting
certain GAAP and non-GAAP measures for specific items we believe
are significant but not reflective of our underlying operations in
the period.
Comparable earnings exclude the unrealized gains and losses from
changes in the fair value of certain 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 part of our underlying
operations.
In the first quarter 2019, comparable earnings also
excluded:
- an after-tax loss of $12 million related to our U.S. Northeast
power marketing contracts.
In fourth quarter 2018, comparable earnings also excluded:
- 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.
In third quarter 2018, comparable earnings also excluded:
- after-tax gain of $8 million related to our U.S. Northeast
power marketing contracts.
In second quarter 2018, comparable earnings also excluded:
- an after-tax loss of $11 million related to our U.S. Northeast
power marketing contracts.
In the first quarter 2018, comparable earnings also
excluded:
- after-tax gain of $6 million related to our U.S. Northeast
power marketing contracts, primarily due to income recognized on
the sale of our retail contracts.
In fourth quarter 2017, comparable earnings also excluded:
- 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.
In third quarter 2017, comparable earnings also excluded:
- an incremental net loss of $12 million related to the
monetization of our U.S. Northeast power generation assets
- an after-tax charge of $30 million for integration-related
costs associated with the acquisition of Columbia
- an after-tax charge of $8 million related to the maintenance of
Keystone XL assets.
In second quarter 2017, comparable earnings also excluded:
- a $265 million net after-tax gain related to the monetization
of our U.S. Northeast power generation assets which included a $441
million after-tax gain on the sale of TC Hydro and a loss of $176
million after tax on the sale of the thermal and wind package
- an after-tax charge of $15 million for integration-related
costs associated with the acquisition of Columbia
- an after-tax charge of $4 million related to the maintenance of
Keystone XL assets.
Condensed consolidated statement of
income
|
|
three months ended March 31 |
(unaudited - millions of Canadian $, except per share amounts) |
|
|
2019 |
|
|
|
2018 |
|
|
|
|
|
|
Revenues |
|
|
|
|
Canadian Natural Gas
Pipelines |
|
|
967 |
|
|
|
884 |
|
U.S. Natural Gas
Pipelines |
|
|
1,304 |
|
|
|
1,091 |
|
Mexico Natural Gas
Pipelines |
|
|
152 |
|
|
|
151 |
|
Liquids Pipelines |
|
|
728 |
|
|
|
623 |
|
Power and
Storage |
|
|
336 |
|
|
|
675 |
|
|
|
|
3,487 |
|
|
|
3,424 |
|
Income from
Equity Investments |
|
|
155 |
|
|
|
80 |
|
Operating and
Other Expenses |
|
|
|
|
Plant operating costs
and other |
|
|
929 |
|
|
|
874 |
|
Commodity purchases
resold |
|
|
252 |
|
|
|
597 |
|
Property taxes |
|
|
187 |
|
|
|
150 |
|
Depreciation and
amortization |
|
|
608 |
|
|
|
535 |
|
|
|
|
1,976 |
|
|
|
2,156 |
|
Financial
Charges |
|
|
|
|
Interest expense |
|
|
586 |
|
|
|
527 |
|
Allowance for funds
used during construction |
|
|
(139 |
) |
|
|
(105 |
) |
Interest
income and other |
|
|
(163 |
) |
|
|
(63 |
) |
|
|
|
284 |
|
|
|
359 |
|
Income before Income Taxes |
|
|
1,382 |
|
|
|
989 |
|
Income Tax
Expense |
|
|
|
|
Current |
|
|
160 |
|
|
|
50 |
|
Deferred |
|
|
76 |
|
|
|
71 |
|
|
|
|
236 |
|
|
|
121 |
|
Net
Income |
|
|
1,146 |
|
|
|
868 |
|
Net
income attributable to non-controlling interests |
|
|
101 |
|
|
|
94 |
|
Net Income
Attributable to Controlling Interests |
|
|
1,045 |
|
|
|
774 |
|
Preferred
share dividends |
|
|
41 |
|
|
|
40 |
|
Net Income
Attributable to Common Shares |
|
|
1,004 |
|
|
|
734 |
|
Net Income per Common Share |
|
|
|
|
Basic and diluted |
|
$1.09 |
|
|
$0.83 |
|
Dividends Declared per Common Share |
|
$0.75 |
|
|
$0.69 |
|
Weighted
Average Number of Common Shares (millions) |
|
|
|
|
Basic |
|
|
921 |
|
|
|
885 |
|
Diluted |
|
|
922 |
|
|
|
886 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated statement of
comprehensive income
|
|
three months ended March 31 |
(unaudited - millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Net Income |
|
1,146 |
|
|
868 |
|
Other
Comprehensive (Loss)/Income, Net of Income Taxes |
|
|
|
|
Foreign currency
translation losses and gains on net investment in foreign
operations |
|
(370 |
) |
|
432 |
|
Change in fair value of
net investment hedges |
|
20 |
|
|
(2 |
) |
Change in fair value of
cash flow hedges |
|
(17 |
) |
|
7 |
|
Reclassification to net
income of gains and losses on cash flow hedges |
|
3 |
|
|
3 |
|
Reclassification of
actuarial gains and losses on pension and other post-retirement
benefit plans |
|
3 |
|
|
(2 |
) |
Other
comprehensive income on equity investments |
|
1 |
|
|
6 |
|
Other
comprehensive (loss)/income |
|
(360 |
) |
|
444 |
|
Comprehensive
Income |
|
786 |
|
|
1,312 |
|
Comprehensive income attributable to non-controlling interests |
|
61 |
|
|
160 |
|
Comprehensive
Income Attributable to Controlling Interests |
|
725 |
|
|
1,152 |
|
Preferred
share dividends |
|
41 |
|
|
40 |
|
Comprehensive Income Attributable to Common
Shares |
|
684 |
|
|
1,112 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated statement of cash
flows
|
|
three months ended March 31 |
(unaudited - millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Cash Generated
from Operations |
|
|
|
|
Net income |
|
1,146 |
|
|
868 |
|
Depreciation and
amortization |
|
608 |
|
|
535 |
|
Deferred income
taxes |
|
76 |
|
|
71 |
|
Income from equity
investments |
|
(155 |
) |
|
(80 |
) |
Distributions received
from operating activities of equity investments |
|
277 |
|
|
234 |
|
Employee
post-retirement benefits funding, net of expense |
|
3 |
|
|
3 |
|
Equity allowance for
funds used during construction |
|
(94 |
) |
|
(78 |
) |
Unrealized
(gains)/losses on financial instruments |
|
(32 |
) |
|
188 |
|
Other |
|
(22 |
) |
|
(122 |
) |
Decrease/(increase) in operating working capital |
|
142 |
|
|
(207 |
) |
Net cash
provided by operations |
|
1,949 |
|
|
1,412 |
|
Investing
Activities |
|
|
|
|
Capital
expenditures |
|
(2,022 |
) |
|
(1,702 |
) |
Capital projects in
development |
|
(164 |
) |
|
(36 |
) |
Contributions to equity
investments |
|
(145 |
) |
|
(358 |
) |
Other distributions
from equity investments |
|
120 |
|
|
121 |
|
Deferred
amounts and other |
|
(26 |
) |
|
110 |
|
Net cash
used in investing activities |
|
(2,237 |
) |
|
(1,865 |
) |
Financing
Activities |
|
|
|
|
Notes payable issued,
net |
|
2,852 |
|
|
1,812 |
|
Long-term debt issued,
net of issue costs |
|
24 |
|
|
93 |
|
Long-term debt
repaid |
|
(1,708 |
) |
|
(1,226 |
) |
Dividends on common
shares |
|
(419 |
) |
|
(358 |
) |
Dividends on preferred
shares |
|
(40 |
) |
|
(39 |
) |
Distributions to
non-controlling interests |
|
(56 |
) |
|
(69 |
) |
Common shares issued,
net of issue costs |
|
68 |
|
|
340 |
|
Partnership units of TC
PipeLines, LP issued, net of issue costs |
|
— |
|
|
49 |
|
Net cash provided by financing activities |
|
721 |
|
|
602 |
|
Effect of Foreign Exchange Rate Changes on Cash and Cash
Equivalents |
|
(7 |
) |
|
29 |
|
Increase in
Cash and Cash Equivalents |
|
426 |
|
|
178 |
|
Cash and Cash
Equivalents |
|
|
|
|
Beginning
of period |
|
446 |
|
|
1,089 |
|
Cash and Cash
Equivalents |
|
|
|
|
End of
period |
|
872 |
|
|
1,267 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated balance
sheet
|
|
March 31, |
|
|
December 31, |
|
(unaudited - millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
ASSETS |
|
|
|
|
Current Assets |
|
|
|
|
Cash and
cash equivalents |
|
872 |
|
|
446 |
|
Accounts
receivable |
|
2,214 |
|
|
2,535 |
|
Inventories |
|
407 |
|
|
431 |
|
Assets held
for sale |
|
533 |
|
|
543 |
|
Other |
|
879 |
|
|
1,180 |
|
|
|
4,905 |
|
|
5,135 |
|
Plant, Property
and Equipment |
net of accumulated
depreciation of $26,181 and $25,834, respectively |
|
67,520 |
|
|
66,503 |
|
Equity Investments |
|
6,966 |
|
|
7,113 |
|
Regulatory Assets |
|
1,557 |
|
|
1,548 |
|
Goodwill |
|
13,881 |
|
|
14,178 |
|
Loan Receivable from Affiliate |
|
1,336 |
|
|
1,315 |
|
Intangible and Other Assets |
|
1,867 |
|
|
1,921 |
|
Restricted Investments |
|
1,315 |
|
|
1,207 |
|
|
|
99,347 |
|
|
98,920 |
|
LIABILITIES |
|
|
|
|
Current Liabilities |
|
|
|
|
Notes
payable |
|
5,587 |
|
|
2,762 |
|
Accounts
payable and other |
|
4,693 |
|
|
5,408 |
|
Dividends
payable |
|
705 |
|
|
668 |
|
Accrued
interest |
|
613 |
|
|
646 |
|
Current portion of long-term debt |
|
1,757 |
|
|
3,462 |
|
|
|
13,355 |
|
|
12,946 |
|
Regulatory Liabilities |
|
3,971 |
|
|
3,930 |
|
Other Long-Term Liabilities |
|
1,492 |
|
|
1,008 |
|
Deferred Income Tax Liabilities |
|
5,995 |
|
|
6,026 |
|
Long-Term Debt |
|
35,857 |
|
|
36,509 |
|
Junior Subordinated Notes |
|
7,380 |
|
|
7,508 |
|
|
|
68,050 |
|
|
67,927 |
|
EQUITY |
|
|
|
|
Common
shares, no par value |
|
23,466 |
|
|
23,174 |
|
Issued
and outstanding: |
March 31, 2019 – 924
million shares |
|
|
|
|
|
December 31, 2018 – 918
million shares |
|
|
|
|
Preferred
shares |
|
3,980 |
|
|
3,980 |
|
Additional
paid-in capital |
|
11 |
|
|
17 |
|
Retained
earnings |
|
3,106 |
|
|
2,773 |
|
Accumulated other comprehensive loss |
|
(926 |
) |
|
(606 |
) |
Controlling Interests |
|
29,637 |
|
|
29,338 |
|
Non-controlling interests |
|
1,660 |
|
|
1,655 |
|
|
|
31,297 |
|
|
30,993 |
|
|
|
99,347 |
|
|
98,920 |
|
Contingencies and Guarantees (Note
12)Variable Interest Entities (Note
13)Subsequent Event (Note 14)
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated statement of
equity
|
three months ended March 31 |
(unaudited - millions of Canadian $) |
2019 |
|
|
2018 |
|
|
|
|
|
Common
Shares |
|
|
|
Balance at beginning of
period |
23,174 |
|
|
21,167 |
|
Shares issued: |
|
|
|
Under
at-the-market equity issuance program, net of issue costs |
— |
|
|
327 |
|
Under
dividend reinvestment and share purchase plan |
216 |
|
|
195 |
|
On exercise of stock options |
76 |
|
|
14 |
|
Balance
at end of period |
23,466 |
|
|
21,703 |
|
Preferred
Shares |
|
|
|
Balance
at beginning and end of period |
3,980 |
|
|
3,980 |
|
Additional
Paid-In Capital |
|
|
|
Balance at beginning of
period |
17 |
|
|
— |
|
Issuance of stock
options, net of exercises |
(6 |
) |
|
3 |
|
Dilution from TC
PipeLines, LP units issued |
— |
|
|
7 |
|
Balance at end of period |
11 |
|
|
10 |
|
Retained
Earnings |
|
|
|
Balance at beginning of
period |
2,773 |
|
|
1,623 |
|
Net income attributable
to controlling interests |
1,045 |
|
|
774 |
|
Common share
dividends |
(693 |
) |
|
(614 |
) |
Preferred share
dividends |
(19 |
) |
|
(19 |
) |
Adjustment related to
income tax effects of asset drop-downs to TC PipeLines, LP |
— |
|
|
95 |
|
Balance at end of period |
3,106 |
|
|
1,859 |
|
Accumulated
Other Comprehensive Loss |
|
|
|
Balance at beginning of
period |
(606 |
) |
|
(1,731 |
) |
Other comprehensive
(loss)/income attributable to controlling interests |
(320 |
) |
|
378 |
|
Balance at end of period |
(926 |
) |
|
(1,353 |
) |
Equity Attributable to Controlling Interests |
29,637 |
|
|
26,199 |
|
Equity
Attributable to Non-Controlling Interests |
|
|
|
Balance at beginning of
period |
1,655 |
|
|
1,852 |
|
Net income attributable
to non-controlling interests |
101 |
|
|
94 |
|
Other comprehensive
(loss)/income attributable to non-controlling interests |
(40 |
) |
|
66 |
|
Issuance of TC
PipeLines, LP units |
|
|
|
Proceeds,
net of issue costs |
— |
|
|
49 |
|
Decrease
in TransCanada's ownership of TC PipeLines, LP |
— |
|
|
(9 |
) |
Distributions declared
to non-controlling interests |
(56 |
) |
|
(71 |
) |
Balance at end of period |
1,660 |
|
|
1,981 |
|
Total Equity |
31,297 |
|
|
28,180 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Notes to Condensed consolidated financial
statements
(unaudited)
1. Basis of presentation
These Condensed consolidated financial statements of TransCanada
Corporation (TransCanada or the Company) have been prepared by
management in accordance with U.S. GAAP. The accounting policies
applied are consistent with those outlined in TransCanada’s annual
audited Consolidated financial statements for the year ended
December 31, 2018, except as described in Note 2, Accounting
changes. Capitalized and abbreviated terms that are used but not
otherwise defined herein are identified in the 2018 audited
Consolidated financial statements included in TransCanada’s 2018
Annual Report. As of first quarter 2019, the previously disclosed
Energy segment has been renamed the Power and Storage segment.
These Condensed consolidated financial statements reflect
adjustments, all of which are normal recurring adjustments that
are, in the opinion of management, necessary to reflect fairly the
financial position and results of operations for the respective
periods. These Condensed consolidated financial statements do
not include all disclosures required in the annual financial
statements and should be read in conjunction with the 2018 audited
Consolidated financial statements included in TransCanada’s 2018
Annual Report. Certain comparative figures have been
reclassified to conform with the current period’s presentation.
Earnings for interim periods may not be indicative of results
for the fiscal year in the Company’s natural gas pipelines segments
due to the timing of regulatory decisions and seasonal fluctuations
in short-term throughput volumes on U.S. pipelines. Earnings
for interim periods may also not be indicative of results for the
fiscal year in the Company’s Power and Storage segment due to the
impact of seasonal weather conditions on customer demand and market
pricing in certain of the Company’s investments in electrical power
generation plants and non-regulated gas storage facilities.
USE OF ESTIMATES AND JUDGMENTSIn preparing
these financial statements, TransCanada is required to make
estimates and assumptions that affect both the amount and timing of
recording assets, liabilities, revenues and expenses since the
determination of these items may be dependent on future events. The
Company uses the most current information available and exercises
careful judgment in making these estimates and assumptions. In the
opinion of management, these Condensed consolidated financial
statements have been properly prepared within reasonable limits of
materiality and within the framework of the Company’s significant
accounting policies included in the annual audited Consolidated
financial statements for the year ended December 31, 2018,
except as described in Note 2, Accounting changes.
2. Accounting changes
CHANGES IN ACCOUNTING POLICIES FOR 2019
LeasesIn February 2016, the FASB issued new
guidance on the accounting for leases. The new guidance amends the
definition of a lease such that, in order for an arrangement to
qualify as a lease, the lessee is required to have both (1) the
right to obtain substantially all of the economic benefits from the
use of the asset and (2) the right to direct the use of the asset.
The new guidance also establishes a right-of-use (ROU) model that
requires a lessee to recognize a ROU asset and corresponding lease
liability on the balance sheet for all leases with a term longer
than twelve months. Leases will be classified as finance or
operating, with classification affecting the pattern of expense
recognition in the consolidated statement of income. The new
guidance does not make extensive changes to lessor accounting.
The new guidance was effective January 1, 2019 and was applied
using optional transition relief which allowed entities to
initially apply the new lease standard at adoption (January 1,
2019) and recognize a cumulative-effect adjustment to the opening
balance of retained earnings in the period of adoption. This
transition option allowed the Company to not apply the new
guidance, including disclosure requirements, to the comparative
periods presented.
The Company elected available practical expedients and
exemptions upon adoption which allowed the Company:
- not to reassess prior conclusions on existing leases regarding
lease identification, lease classification and initial direct costs
under the new standard
- to carry forward the historical lease classification and its
accounting treatment for land easements on existing agreements
- to not recognize ROU assets or lease liabilities for leases
that qualify for the short-term lease recognition exemption
- to not separate lease and non-lease components for all leases
for which the Company is the lessee and for facility and liquids
tank terminals for which the Company is the lessor
- to use hindsight in determining the lease term and assessing
ROU assets for impairment.
The new guidance had a significant impact on the Company's
Condensed consolidated balance sheet, but did not have an impact on
the Company's Condensed consolidated statements of income and cash
flows. The most significant impact was the recognition of ROU
assets and lease liabilities for operating leases and providing
significant new disclosures about the Company's leasing activities.
Refer to Note 7, Leases, for further information related to the
impact of adopting the new guidance and the Company's updated
accounting policies related to leases.
In the application of the new guidance, significant assumptions
and judgments are used to determine the following:
- whether a contract contains a lease
- the duration of the lease term including exercising lease
renewal options. The lease term for all of the Company’s leases
includes the noncancellable period of the lease plus any additional
periods covered by either a Company option to extend (or not to
terminate) the lease that the Company is reasonably certain to
exercise, or an option to extend (or not to terminate) the lease
controlled by the lessor
- the discount rate for the lease.
Fair value measurementIn August 2018, the FASB
issued new guidance that amends certain disclosure requirements for
fair value measurements. This new guidance is effective January 1,
2020, however, early adoption of certain or all requirements is
permitted. The Company elected to adopt this guidance effective
first quarter 2019. The guidance was applied retrospectively and
did not have a material impact on the Company's consolidated
financial statements.
FUTURE ACCOUNTING CHANGES
Measurement of credit losses on financial
instrumentsIn June 2016, the FASB issued new guidance that
significantly changes how entities measure credit losses for most
financial assets and certain other financial instruments that are
not measured at fair value through net income. The new guidance
amends the impairment model of financial instruments, basing it on
expected losses rather than incurred losses. These expected credit
losses will be recognized as an allowance rather than as a direct
write down of the amortized cost basis. The new guidance is
effective January 1, 2020 and will be applied using a modified
retrospective approach. The Company is currently evaluating the
impact of the adoption of this guidance and has not yet determined
the effect on its consolidated financial statements.
Defined benefit plansIn August 2018, the FASB
issued new guidance which amends and clarifies disclosure
requirements related to defined benefit pension and other
post-retirement benefit plans. This new guidance is effective
January 1, 2021 and will be applied on a retrospective basis,
however, early adoption is permitted. The Company is currently
evaluating the timing and impact of the adoption of this guidance
and has not yet determined the effect on its consolidated financial
statements.
Implementation costs of cloud computing
arrangementsIn August 2018, the FASB issued new guidance
requiring an entity in a hosting arrangement that is a service
contract to follow the guidance for internal-use software to
determine which implementation costs should be capitalized as an
asset and which costs should be expensed. The guidance also
requires the entity to amortize the capitalized implementation
costs of a hosting arrangement over the term of the arrangement.
This guidance is effective January 1, 2020, however, early adoption
is permitted. This guidance can be applied either retrospectively
or prospectively to all implementation costs incurred after the
date of adoption. The Company is currently evaluating the timing
and impact of adoption of this guidance and has not yet determined
the effect on its consolidated financial statements.
ConsolidationIn October 2018, the FASB issued
new guidance for determining whether fees paid to decision makers
and service providers are variable interests for indirect interests
held through related parties under common control. This new
guidance is effective January 1, 2020 and will be applied on a
retrospective basis, however, early adoption is permitted. The
Company is currently evaluating the timing and impact of the
adoption of this guidance and has not yet determined the effect on
its consolidated financial statements.
3. Segmented information
three months ended March 31, 2019 |
|
Canadian Natural Gas Pipelines |
|
|
U.S. Natural Gas Pipelines |
|
|
Mexico Natural Gas Pipelines |
|
|
Liquids Pipelines |
|
|
Power and Storage1 |
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
|
Corporate2 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
967 |
|
|
1,304 |
|
|
152 |
|
|
728 |
|
|
336 |
|
|
— |
|
|
3,487 |
|
Intersegment revenues |
|
— |
|
|
42 |
|
|
— |
|
|
— |
|
|
5 |
|
|
(47 |
) |
3 |
— |
|
|
|
967 |
|
|
1,346 |
|
|
152 |
|
|
728 |
|
|
341 |
|
|
(47 |
) |
|
3,487 |
|
Income/(loss) from
equity investments |
|
1 |
|
|
76 |
|
|
6 |
|
|
14 |
|
|
72 |
|
|
(14 |
) |
4 |
155 |
|
Plant operating costs
and other |
|
(343 |
) |
|
(362 |
) |
|
(12 |
) |
|
(166 |
) |
|
(88 |
) |
|
42 |
|
3 |
(929 |
) |
Commodity purchases
resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(252 |
) |
|
— |
|
|
(252 |
) |
Property taxes |
|
(69 |
) |
|
(88 |
) |
|
— |
|
|
(28 |
) |
|
(2 |
) |
|
— |
|
|
(187 |
) |
Depreciation and
amortization |
|
(287 |
) |
|
(180 |
) |
|
(30 |
) |
|
(88 |
) |
|
(23 |
) |
|
— |
|
|
(608 |
) |
Segmented Earnings/(Loss) |
|
269 |
|
|
792 |
|
|
116 |
|
|
460 |
|
|
48 |
|
|
(19 |
) |
|
1,666 |
|
Interest
expense |
|
(586 |
) |
Allowance
for funds used during construction |
|
139 |
|
Interest income and other4 |
|
163 |
|
Income
before income taxes |
|
1,382 |
|
Income tax expense |
|
(236 |
) |
Net Income |
|
1,146 |
|
Net income attributable to non-controlling
interests |
|
(101 |
) |
Net Income Attributable to Controlling
Interests |
|
1,045 |
|
Preferred share dividends |
|
(41 |
) |
Net Income Attributable to Common
Shares |
|
1,004 |
|
1 Previously referred to as Energy.2 Includes intersegment
eliminations.3 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.4
Income/(loss) from equity investments includes foreign exchange
losses on the Company's inter-affiliate loan with Sur de Texas. The
offsetting foreign exchange gains 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 March 31, 2018 |
|
Canadian Natural Gas Pipelines |
|
|
U.S. Natural Gas Pipelines |
|
|
Mexico Natural Gas Pipelines |
|
|
Liquids Pipelines |
|
|
Power and Storage1 |
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
|
Corporate2 |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
884 |
|
|
1,091 |
|
|
151 |
|
|
623 |
|
|
675 |
|
|
— |
|
|
3,424 |
|
Intersegment revenues |
|
— |
|
|
25 |
|
|
— |
|
|
— |
|
|
42 |
|
|
(67 |
) |
3 |
— |
|
|
|
884 |
|
|
1,116 |
|
|
151 |
|
|
623 |
|
|
717 |
|
|
(67 |
) |
|
3,424 |
|
Income/(loss) from
equity investments |
|
3 |
|
|
67 |
|
|
11 |
|
|
15 |
|
|
63 |
|
|
(79 |
) |
4 |
80 |
|
Plant operating costs
and other |
|
(323 |
) |
|
(324 |
) |
|
(2 |
) |
|
(191 |
) |
|
(99 |
) |
|
65 |
|
3 |
(874 |
) |
Commodity purchases
resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(597 |
) |
|
— |
|
|
(597 |
) |
Property taxes |
|
(70 |
) |
|
(55 |
) |
|
— |
|
|
(23 |
) |
|
(2 |
) |
|
— |
|
|
(150 |
) |
Depreciation and
amortization |
|
(241 |
) |
|
(156 |
) |
|
(23 |
) |
|
(83 |
) |
|
(32 |
) |
|
— |
|
|
(535 |
) |
Segmented Earnings/(Loss) |
|
253 |
|
|
648 |
|
|
137 |
|
|
341 |
|
|
50 |
|
|
(81 |
) |
|
1,348 |
|
Interest
expense |
|
(527 |
) |
Allowance
for funds used during construction |
|
105 |
|
Interest income and other4 |
|
63 |
|
Income
before income taxes |
|
989 |
|
Income tax expense |
|
(121 |
) |
Net Income |
|
868 |
|
Net income attributable to non-controlling
interests |
|
(94 |
) |
Net Income Attributable to Controlling
Interests |
|
774 |
|
Preferred share dividends |
|
(40 |
) |
Net Income Attributable to Common
Shares |
|
734 |
|
1 Previously referred to as Energy.2 Includes intersegment
eliminations.3 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.4
Income/(loss) from equity investments includes foreign exchange
losses on the Company's inter-affiliate loan with Sur de Texas. The
offsetting foreign exchange gains 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 $) |
|
March 31,
2019 |
|
|
December
31, 2018 |
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
19,287 |
|
|
18,407 |
|
U.S. Natural Gas
Pipelines |
|
43,532 |
|
|
44,115 |
|
Mexico Natural Gas
Pipelines |
|
6,858 |
|
|
7,058 |
|
Liquids Pipelines |
|
17,025 |
|
|
17,352 |
|
Power and Storage |
|
8,331 |
|
|
8,475 |
|
Corporate |
|
4,314 |
|
|
3,513 |
|
|
|
99,347 |
|
|
98,920 |
|
4. Revenues
DISAGGREGATION OF REVENUESThe following tables
summarize total Revenues for the three months ended March 31,
2019 and 2018:
three months ended March 31, 2019(unaudited -
millions of Canadian $) |
CanadianNaturalGasPipelines |
|
U.S.NaturalGasPipelines |
|
MexicoNaturalGasPipelines |
|
Liquids Pipelines |
|
Power and Storage |
|
Total |
|
|
|
|
|
|
|
|
Revenues from contracts
with customers |
|
|
|
|
|
|
Capacity
arrangements and transportation |
967 |
|
1,100 |
|
151 |
|
593 |
|
— |
|
2,811 |
|
Power
generation |
— |
|
— |
|
— |
|
— |
|
343 |
|
343 |
|
Natural gas storage and other |
— |
|
180 |
|
1 |
|
1 |
|
28 |
|
210 |
|
|
967 |
|
1,280 |
|
152 |
|
594 |
|
371 |
|
3,364 |
|
Other
revenues1 |
— |
|
24 |
|
— |
|
134 |
|
(35 |
) |
123 |
|
|
967 |
|
1,304 |
|
152 |
|
728 |
|
336 |
|
3,487 |
|
1 Other revenues include income from the Company's marketing
activities, financial instruments and lease arrangements. These
arrangements are not in the scope of the revenue guidance. Refer to
Note 7, Leases, and Note 11, Risk management and financial
instruments, for further information on income from lease
arrangements and financial instruments, respectively.
three months ended March 31, 2018(unaudited -
millions of Canadian $) |
CanadianNaturalGasPipelines |
|
U.S.NaturalGasPipelines |
|
MexicoNaturalGasPipelines |
|
LiquidsPipelines |
|
Power and Storage |
|
Total |
|
|
|
|
|
|
|
|
Revenues from contracts
with customers |
|
|
|
|
|
|
Capacity
arrangements and transportation |
884 |
|
884 |
|
150 |
|
534 |
|
— |
|
2,452 |
|
Power
generation |
— |
|
— |
|
— |
|
— |
|
590 |
|
590 |
|
Natural gas storage and other |
— |
|
192 |
|
1 |
|
1 |
|
30 |
|
224 |
|
|
884 |
|
1,076 |
|
151 |
|
535 |
|
620 |
|
3,266 |
|
Other
revenues1 |
— |
|
15 |
|
— |
|
88 |
|
55 |
|
158 |
|
|
884 |
|
1,091 |
|
151 |
|
623 |
|
675 |
|
3,424 |
|
1 Other revenues include income from the Company's marketing
activities, financial instruments and lease arrangements. These
arrangements are not in the scope of the revenue guidance. Refer to
Note 11, Risk management and financial instruments, for further
information on income from financial instruments.
CONTRACT BALANCES
(unaudited - millions of Canadian $) |
March 31, 2019 |
|
|
December 31, 2018 |
|
|
|
|
|
|
|
|
Receivables from
contracts with customers |
1,382 |
|
|
1,684 |
|
|
Contract assets1 |
249 |
|
|
159 |
|
|
Long-term contract
assets2 |
11 |
|
|
21 |
|
|
Contract
liabilities3 |
39 |
|
|
11 |
|
|
Long-term
contract liabilities4 |
119 |
|
|
121 |
|
|
1 Recorded as part of Other current assets on the Condensed
consolidated balance sheet.2 Recorded as part of Intangibles and
other assets on the Condensed consolidated balance sheet.3
Comprised of deferred revenue recorded in Accounts payable and
other on the Condensed consolidated balance sheet. During the three
months ended March 31, 2019, $6 million of revenue was
recognized that was included in contract liabilities at the
beginning of the period.4 Comprised of deferred revenue recorded in
Other long-term liabilities on the Condensed consolidated balance
sheet.
Contract assets and long-term contract assets primarily relate
to the Company’s right to revenues for services completed but not
invoiced at the reporting date on long-term committed capacity
natural gas pipelines contracts. The change in contract assets is
primarily related to the transfer to Accounts receivable when these
rights become unconditional and the customer is invoiced as well as
the recognition of additional revenues that remain to be invoiced.
Contract liabilities and long-term contract liabilities primarily
relate to force majeure fixed capacity payments received on
long-term capacity arrangements in Mexico.
FUTURE REVENUES FROM REMAINING PERFORMANCE
OBLIGATIONS
Capacity Arrangements and TransportationAs at
March 31, 2019, future revenues from long-term pipeline
capacity arrangements and transportation contracts extending
through 2045 are approximately $32.3 billion, of which
approximately $5.4 billion is expected to be recognized during the
remainder of 2019.
Power GenerationThe Company has long-term power
generation contracts extending through 2030. Revenues from power
generation contracts have a variable component related to market
prices that are subject to factors outside the Company’s influence.
These revenues are considered to be fully constrained and are
recognized on a monthly basis when the Company satisfies the
performance obligation.
Natural Gas Storage and OtherAs at
March 31, 2019, future revenues from long-term natural gas
storage and other contracts extending through 2033 are
approximately $1.7 billion, of which approximately $366 million is
expected to be recognized during the remainder of 2019.
5. Income taxes
Effective Tax RatesThe effective income tax
rates for the three-month periods ended March 31, 2019 and
2018 were 17 per cent and 12 per cent, respectively. The higher
effective tax rate in 2019 was primarily the result of lower
foreign tax rate differentials partially offset by lower
flow-through tax in Canadian rate-regulated pipelines.
Further to U.S. Tax Reform, the U.S. Treasury and the U.S.
Internal Revenue Service issued proposed regulations in November
and December of 2018 which provided administrative guidance and
clarified certain aspects of the new laws with respect to interest
deductibility, base erosion and anti-abuse tax, the new dividend
received deduction and anti-hybrid rules. The proposed regulations
are complex and comprehensive, and considerable uncertainty
continues to exist pending release of the final regulations which
is expected to occur later in 2019. As these proposed regulations
have not been enacted as at March 31, 2019, their impact has not
been reflected in income tax expense. If the proposed regulations
are enacted as currently drafted, the resulting income tax expense
should not have a material impact on the Company's financial
statements.
6. Assets held for sale
Coolidge Generating StationIn December 2018,
TransCanada entered into an agreement to sell its Coolidge
generating station in Arizona to SWG Coolidge Holdings, LLC (SWG).
Salt River Project Agriculture Improvement and Power District
(SRP), the PPA counterparty, subsequently exercised its contractual
right of first refusal on a sale to a third party. On March 20,
2019, TransCanada terminated the agreement with SWG after entering
into an agreement with SRP to sell the Coolidge generating station
for approximately US$465 million, subject to timing of the close
and related adjustments.
The sale will result in an estimated gain of approximately $70
million ($55 million after tax) including the release of an
estimated $10 million of foreign currency translation gains. The
gain will be recognized upon closing of the sale transaction, which
is expected to occur mid-2019.
At March 31, 2019, the related assets and liabilities in
the Power and Storage segment were classified as held for sale as
follows:
|
|
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
Assets held for
sale |
|
|
Accounts receivable |
|
6 |
|
Other current
assets |
|
1 |
|
Plant,
property and equipment |
|
526 |
|
Total assets held for sale |
|
533 |
|
Liabilities
related to assets held for sale |
|
|
Other
long-term liabilities |
|
(3 |
) |
Total liabilities related to assets held for
sale1 |
|
(3 |
) |
1 Included in Accounts payable and other on the Condensed
consolidated balance sheet.
7. Leases
In 2016, the FASB issued new guidance on leases. The Company
adopted the new guidance on January 1, 2019 using optional
transition relief. Results reported for 2019 reflect the
application of the new guidance, while the 2018 comparative results
were prepared and reported under previous leases guidance.
Lessee Accounting PolicyThe Company determines
if an arrangement is a lease at inception of the contract.
Operating leases are recognized as ROU assets and included in
Plant, property and equipment while corresponding liabilities are
included in Accounts payable and other, and Other long-term
liabilities on the Condensed consolidated balance sheet.
Operating lease ROU assets and operating lease liabilities are
recognized based on the present value of the future minimum lease
payments over the lease term at the commencement date of the lease
agreement. As the Company’s lease contracts do not provide an
implicit interest rate, the Company uses its incremental borrowing
rate based on the information available at commencement date in
determining the present value of future payments. The operating
lease ROU asset also includes any lease payments made and initial
direct costs incurred and excludes lease incentives. Lease terms
may include options to extend or terminate the lease when it is
reasonably certain that the Company will exercise that option.
Operating lease expense is recognized on a straight-line basis over
the lease term and included in Plant operating costs and other in
the Condensed consolidated statement of income.
Lessor Accounting Policy
The Company is the lessor for certain contracts
and these contracts are accounted for as operating leases. The
Company recognizes lease payments as income over the lease term on
a straight-line basis. Variable lease payments are recognized as
income in the period in which the changes in facts and
circumstances on which these payments are based occur.
Impact of New Lease Guidance on Date of
AdoptionThe following table illustrates the impact of the
adoption of the new lease guidance on the Company's previously
reported consolidated balance sheet line items:
(unaudited - millions of Canadian $) |
As reported December 31, 2018 |
|
Adjustment |
|
January 1, 2019 |
|
|
|
|
|
Plant, property and
equipment |
66,503 |
|
585 |
|
67,088 |
|
Accounts payable and
other |
5,408 |
|
57 |
|
5,465 |
|
Other
long-term liabilities |
1,008 |
|
528 |
|
1,536 |
|
As a LesseeThe Company has operating leases for
corporate offices, other various premises, equipment and land. Some
leases have an option to renew for periods of one to 25 years, and
some may include options to terminate the lease within one year.
Payments due under lease contracts include fixed payments plus, for
many of the Company's leases, variable payments such as
proportionate share of the buildings' property taxes, insurance and
common area maintenance. The Company subleases some of the leased
premises.
Operating lease cost is as follows:
(unaudited - millions of Canadian $) |
three months ended March 31, 2019 |
|
|
Operating lease
cost1 |
28 |
Sublease
income |
(2) |
Net
operating lease cost |
26 |
1 Includes short-term leases and variable lease costs.
Other information related to operating leases is noted in the
following table:
(unaudited - millions of Canadian $) |
three months ended March 31, 2019 |
|
|
|
Cash paid for amounts
included in the measurement of operating lease liabilities |
19 |
Weighted average
remaining lease term |
10.8years |
Weighted
average discount rate |
3.56% |
Maturities of operating lease liabilities on a prospective
12-month basis and where they are disclosed on the Condensed
consolidated balance sheet as at March 31, 2019 are as follows:
(unaudited - millions of Canadian $) |
|
|
|
2020 |
72 |
|
2021 |
69 |
|
2022 |
64 |
|
2023 |
58 |
|
2024 |
57 |
|
Thereafter |
355 |
|
Total operating lease
payments |
675 |
|
Imputed interest |
(110 |
) |
Operating lease liabilities recorded on the Condensed consolidated
balance sheet |
565 |
|
Reported as
follows: |
|
Accounts
payable and other |
55 |
|
Other
long-term liabilities |
510 |
|
|
565 |
|
Future payments reported under previous lease guidance for the
Company’s operating leases as at December 31, 2018 were as
follows:
(unaudited - millions of Canadian $) |
Minimum operating lease payments |
|
|
2019 |
81 |
2020 |
78 |
2021 |
76 |
2022 |
69 |
2023 |
67 |
Thereafter |
390 |
|
761 |
As at March 31, 2019, the carrying value of the ROU assets
recorded under operating leases was $570 million and is included in
Plant, property and equipment on the Condensed consolidated balance
sheet.
As a LessorCoolidge, Grandview and Bécancour
power plants in the Power and Storage segment and the Northern
Courier pipeline in the Liquids Pipelines segment are accounted for
as operating leases. As Coolidge is classified as Assets held for
sale, it is not included in the following lease disclosures. The
Company has long-term PPAs for the sale of power for the Power and
Storage lease assets which expire between 2024 and 2026. Northern
Courier pipeline transports bitumen and diluent between the Fort
Hills mine site and Suncor Energy’s terminal, with a contract
expiring in 2042.
Some leases contain variable lease payments that are based on
operating hours and the reimbursement of variable costs, options to
purchase the underlying asset at fair value or based on a formula
considering the remaining fixed payments, and options to extend a
lease up to five years. Lessees have rights under some leases to
terminate under certain circumstances.
The Company also leases liquids tanks which are accounted for as
operating leases.
Operating lease income recorded by the Company for the three
months ended March 31, 2019 was $55 million.
Future lease payments to be received under operating leases as
at March 31, 2019 are as follows:
(unaudited - millions of Canadian $) |
Future lease payments |
|
|
Remainder of 2019 |
183 |
2020 |
226 |
2021 |
223 |
2022 |
218 |
2023 |
224 |
Thereafter |
1,940 |
|
3,014 |
The cost and accumulated depreciation for facilities accounted
for as operating leases was $2,023 million and $338 million,
respectively, at March 31, 2019 (December 31, 2018 – $2,007 million
and $324 million, respectively).
8. Long-term debt
LONG-TERM DEBT REPAIDThe Company retired
long-term debt in the three months ended March 31, 2019 as
follows:
(unaudited - millions of Canadian $, unless otherwise noted) |
|
|
|
|
|
|
|
|
Company |
|
Retirement date |
|
Type |
|
Amount |
|
|
Interest rate |
|
|
|
|
|
|
|
|
|
TRANSCANADA PIPELINES LIMITED |
|
|
|
|
|
|
|
|
March 2019 |
|
Debentures |
|
100 |
|
|
10.50% |
|
|
January 2019 |
|
Senior Unsecured Notes |
|
US 750 |
|
|
7.125% |
|
|
January 2019 |
|
Senior Unsecured
Notes |
|
US
400 |
|
|
3.125% |
CAPITALIZED INTERESTIn the three months ended
March 31, 2019, TransCanada capitalized interest related to
capital projects of $37 million (2018 – $26 million).
9. Other comprehensive (loss)/income and accumulated
other comprehensive loss
Components of other comprehensive (loss)/income, including the
portion attributable to non-controlling interests and related tax
effects, are as follows:
three months ended March 31, 2019 |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
Before Tax Amount |
|
|
Income TaxRecovery/(Expense) |
|
|
Net of Tax Amount |
|
|
|
|
|
|
|
|
Foreign currency
translation losses on net investment in foreign operations |
|
(364 |
) |
|
(6 |
) |
|
(370 |
) |
Change in fair value of
net investment hedges |
|
27 |
|
|
(7 |
) |
|
20 |
|
Change in fair value of
cash flow hedges |
|
(22 |
) |
|
5 |
|
|
(17 |
) |
Reclassification to net
income of gains and losses on cash flow hedges |
|
4 |
|
|
(1 |
) |
|
3 |
|
Reclassification of
actuarial gains and losses on pension and other post-retirement
benefit plans |
|
4 |
|
|
(1 |
) |
|
3 |
|
Other
comprehensive income on equity investments |
|
1 |
|
|
— |
|
|
1 |
|
Other Comprehensive Loss |
|
(350 |
) |
|
(10 |
) |
|
(360 |
) |
three months ended March 31, 2018 |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
Before Tax Amount |
|
|
Income TaxRecovery/(Expense) |
|
|
Net of Tax Amount |
|
|
|
|
|
|
|
|
Foreign currency
translation gains on net investment in foreign operations |
|
416 |
|
|
16 |
|
|
432 |
|
Change in fair value of
net investment hedges |
|
(3 |
) |
|
1 |
|
|
(2 |
) |
Change in fair value of
cash flow hedges |
|
6 |
|
|
1 |
|
|
7 |
|
Reclassification to net
income of gains and losses on cash flow hedges |
|
4 |
|
|
(1 |
) |
|
3 |
|
Reclassification of
actuarial gains and losses on pension and other post-retirement
benefit plans |
|
4 |
|
|
(6 |
) |
|
(2 |
) |
Other
comprehensive income on equity investments |
|
7 |
|
|
(1 |
) |
|
6 |
|
Other Comprehensive Income |
|
434 |
|
|
10 |
|
|
444 |
|
The changes in AOCI by component are as
follows:
three months ended March 31, 2019 |
|
|
|
|
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
Currency TranslationAdjustments |
|
|
Cash FlowHedges |
|
|
Pension and OPEB Plan Adjustments |
|
|
Equity Investments |
|
|
Total1 |
|
|
|
|
|
|
|
|
|
|
|
|
AOCI balance at January
1, 2019 |
|
107 |
|
|
(23 |
) |
|
(314 |
) |
|
(376 |
) |
|
(606 |
) |
Other comprehensive
loss before reclassifications2 |
|
(315 |
) |
|
(12 |
) |
|
— |
|
|
(1 |
) |
|
(328 |
) |
Amounts
reclassified from AOCI3,4 |
|
— |
|
|
2 |
|
|
3 |
|
|
3 |
|
|
8 |
|
Net current period
other comprehensive (loss)/income |
|
(315 |
) |
|
(10 |
) |
|
3 |
|
|
2 |
|
|
(320 |
) |
AOCI balance at March 31, 2019 |
|
(208 |
) |
|
(33 |
) |
|
(311 |
) |
|
(374 |
) |
|
(926 |
) |
1 All amounts are net of tax. Amounts in parentheses indicate
losses recorded to OCI.2 Other comprehensive loss before
reclassifications on currency translation adjustments and cash flow
hedges are net of non-controlling interests losses of $35 million
and $5 million, respectively.3 Losses related to cash flow hedges
reported in AOCI and expected to be reclassified to net income in
the next 12 months are estimated to be $16 million ($12 million,
net of tax) at March 31, 2019. These estimates assume constant
commodity prices, interest rates and foreign exchange rates over
time, however, the amounts reclassified will vary based on the
actual value of these factors at the date of settlement.4 Amounts
reclassified from AOCI on cash flow hedges and equity investments
are net of non-controlling interests gains of $1 million and nil,
respectively.
Details about reclassifications out of AOCI into the Condensed
consolidated statement of income are as follows:
|
Amounts Reclassified From AOCI |
|
Affected line item in the Condensed
consolidated statement of income |
|
three months ended March 31 |
|
(unaudited - millions of Canadian $) |
2019 |
|
2018 |
|
|
|
|
|
|
|
Cash flow hedges |
|
|
|
|
Commodities |
— |
|
1 |
|
|
Revenues (Power and
Storage) |
Interest |
(3 |
) |
(5 |
) |
|
Interest
expense |
|
(3 |
) |
(4 |
) |
|
Total before tax |
|
1 |
|
1 |
|
|
Income
tax expense |
|
(2 |
) |
(3 |
) |
|
Net of
tax1,3 |
Pension and other
post-retirement benefit plan adjustments |
|
|
|
|
Amortization of actuarial losses |
(4 |
) |
(4 |
) |
|
Plant operating costs
and other2 |
|
1 |
|
6 |
|
|
Income
tax expense |
|
(3 |
) |
2 |
|
|
Net of
tax1 |
Equity investments |
|
|
|
|
Equity
income |
(3 |
) |
(7 |
) |
|
Income from equity
investments |
|
— |
|
1 |
|
|
Income tax expense |
|
(3 |
) |
(6 |
) |
|
Net of tax1,3 |
1 All amounts in parentheses indicate expenses to the Condensed
consolidated statement of income.2 These AOCI components are
included in the computation of net benefit cost. Refer to Note 10,
Employee post-retirement benefits, for further information.3
Amounts reclassified from AOCI on cash flow hedges and equity
investments are net of non-controlling interests gains of $1
million and nil, respectively, for the three months ended
March 31, 2019 (2018 – nil and nil).
10. Employee post-retirement benefits
The net benefit cost recognized for the Company’s pension
benefit plans and other post-retirement benefit plans is as
follows:
|
|
three months ended March 31 |
|
|
Pension benefit plans |
|
Other post-retirement benefit
plans |
(unaudited -
millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
2019 |
|
|
2018 |
|
|
|
|
|
|
|
|
|
|
Service cost1 |
|
33 |
|
|
30 |
|
|
1 |
|
|
1 |
|
Other components of net
benefit cost1 |
|
|
|
|
|
|
|
|
Interest
cost |
|
35 |
|
|
33 |
|
|
4 |
|
|
3 |
|
Expected
return on plan assets |
|
(58 |
) |
|
(55 |
) |
|
(4 |
) |
|
(4 |
) |
Amortization of actuarial losses |
|
3 |
|
|
4 |
|
|
1 |
|
|
— |
|
Amortization of regulatory asset |
|
3 |
|
|
5 |
|
|
— |
|
|
— |
|
|
|
(17 |
) |
|
(13 |
) |
|
1 |
|
|
(1 |
) |
Net Benefit Cost |
|
16 |
|
|
17 |
|
|
2 |
|
|
— |
|
1 Service cost and other components of net benefit cost are
included in Plant operating costs and other in the Condensed
consolidated statement of income.
11. Risk management and financial
instruments
RISK MANAGEMENT OVERVIEWTransCanada has
exposure to market risk and counterparty credit risk, and has
strategies, policies and limits in place to manage the impact of
these risks on earnings, cash flow and shareholder value.
COUNTERPARTY CREDIT RISKTransCanada’s maximum
counterparty credit exposure with respect to financial instruments
at March 31, 2019, without taking into account security held,
consisted of cash and cash equivalents, accounts receivable,
available-for-sale assets, derivative assets and a loan
receivable.
The Company monitors its counterparties and regularly reviews
its accounts receivable. The Company records an allowance for
doubtful accounts as necessary using the specific identification
method. At March 31, 2019, there were no significant credit
losses, no significant credit risk concentration and no significant
amounts past due or impaired.
LOAN RECEIVABLE FROM AFFILIATERelated party
transactions are conducted in the normal course of business and are
measured at the exchange amount, which is the amount of
consideration established and agreed to by the related parties.
The Company holds a 60 per cent equity interest in a joint
venture with IEnova to build, own and operate the Sur de Texas
pipeline. The Company accounts for its interest in the joint
venture as an equity investment. In 2017, the Company entered into
a MXN$21.3 billion unsecured revolving credit facility with the
joint venture, which bears interest at a floating rate and matures
in March 2022.
At March 31, 2019, the Company's Condensed consolidated
balance sheet included a MXN$19.4 billion or $1.3 billion
(December 31, 2018 – MXN$18.9 billion or $1.3 billion) loan
receivable from the Sur de Texas joint venture which represents
TransCanada's proportionate share of long-term debt financing
requirements related to the joint venture. Interest income
and other included interest income of $35 million for the three
months ended March 31, 2019 (2018 – $27 million) from this
joint venture with a corresponding proportionate share of interest
expense recorded in Income from equity investments.
NET INVESTMENT IN FOREIGN OPERATIONSThe Company
hedges its net investment in foreign operations (on an after-tax
basis) with U.S. dollar-denominated debt, cross-currency swaps and
foreign exchange options.
The fair values and notional amounts for the derivatives
designated as a net investment hedge were as follows:
|
|
March 31, 2019 |
|
December 31, 2018 |
(unaudited -
millions of Canadian $, unless otherwise noted) |
|
Fair
value1,2 |
|
|
Notional
amount |
|
Fair
value1,2 |
|
|
Notional
amount |
|
|
|
|
|
|
|
|
|
U.S. dollar
cross-currency swaps (maturing 2019)3 |
|
(12 |
) |
|
US 100 |
|
(43 |
) |
|
US
300 |
U.S. dollar foreign
exchange options (maturing 2019 to 2020) |
|
(13 |
) |
|
US 2,500 |
|
(47 |
) |
|
US
2,500 |
|
|
(25 |
) |
|
US 2,600 |
|
(90 |
) |
|
US 2,800 |
1 Fair value equals carrying value.2 No amounts have been
excluded from the assessment of hedge effectiveness.3 In the three
months ended March 31, 2019, Net income includes net realized
gains of nil (2018 – $1 million) related to the interest component
of cross-currency swap settlements which are reported within
Interest expense on the Company’s Condensed consolidated
statement of income.
The notional amounts and fair value of U.S. dollar-denominated
debt designated as a net investment hedge were as follows:
(unaudited - millions of Canadian $, unless otherwise noted) |
|
March 31, 2019 |
|
December 31, 2018 |
|
|
|
|
|
Notional
amount |
|
30,800 (US 23,100) |
|
31,000 (US
22,700) |
Fair value |
|
32,900 (US 24,600) |
|
31,700 (US 23,200) |
FINANCIAL INSTRUMENTS
Non-derivative financial instruments
Fair value of non-derivative financial
instrumentsAvailable-for-sale assets are recorded at fair
value which is calculated using quoted market prices where
available. Certain non-derivative financial instruments included in
Cash and cash equivalents, Accounts receivable, Intangible and
other assets, Notes payable, Accounts payable and other, Accrued
interest and Other long-term liabilities have carrying amounts that
approximate their fair value due to the nature of the item or the
short time to maturity. Each of these instruments are classified in
Level II of the fair value hierarchy.
Credit risk has been taken into consideration when calculating
the fair value of non-derivative instruments.
Balance sheet presentation of non-derivative financial
instrumentsThe following table details the fair value of
the Company's non-derivative financial instruments, excluding those
where carrying amounts approximate fair value, which are classified
in Level II of the fair value hierarchy:
|
|
March 31, 2019 |
|
December 31, 2018 |
(unaudited -
millions of Canadian $) |
|
Carryingamount |
|
|
Fairvalue |
|
|
Carryingamount |
|
|
Fairvalue |
|
|
|
|
|
|
|
|
|
|
Long-term debt
including current portion1,2 |
|
(37,614 |
) |
|
(41,737 |
) |
|
(39,971 |
) |
|
(42,284 |
) |
Junior subordinated
notes |
|
(7,380 |
) |
|
(7,006 |
) |
|
(7,508 |
) |
|
(6,665 |
) |
|
|
(44,994 |
) |
|
(48,743 |
) |
|
(47,479 |
) |
|
(48,949 |
) |
1 Long-term debt is recorded at amortized cost except for US$450
million (December 31, 2018 – US$750 million) that is
attributed to hedged risk and recorded at fair value.2 Net income
for the three months ended March 31, 2019 includes unrealized
losses of $3 million (2018 – gains of $5 million) for fair value
adjustments attributable to the hedged interest rate risk
associated with interest rate swap fair value hedging relationships
on US$450 million of long-term debt at March 31, 2019
(December 31, 2018 – US$750 million). There were no other
unrealized gains or losses from fair value adjustments to the
non-derivative financial instruments.
Available-for-sale assets summaryThe following
tables summarize additional information about the Company's
restricted investments that are classified as available-for-sale
assets:
|
March 31, 2019 |
|
December 31, 2018 |
(unaudited -
millions of Canadian $) |
LMCI
restricted investments |
|
|
Other
restricted investments1 |
|
|
LMCI
restricted investments |
|
|
Other
restricted investments1 |
|
|
|
|
|
|
|
|
|
Fair values of fixed
income securities2 |
|
|
|
|
|
|
|
Maturing
within 1 year |
— |
|
|
24 |
|
|
— |
|
|
22 |
|
Maturing
within 1-5 years |
— |
|
|
94 |
|
|
— |
|
|
110 |
|
Maturing
within 5-10 years |
156 |
|
|
— |
|
|
140 |
|
|
— |
|
Maturing
after 10 years |
1,053 |
|
|
— |
|
|
952 |
|
|
— |
|
|
1,209 |
|
|
118 |
|
|
1,092 |
|
|
132 |
|
1 Other restricted investments have been set aside to fund
insurance claim losses to be paid by the Company's wholly-owned
captive insurance subsidiary.2 Available-for-sale assets are
recorded at fair value and included in Other current assets and
Restricted investments on the Company's Condensed consolidated
balance sheet.
|
|
March 31, 2019 |
|
March 31, 2018 |
(unaudited -
millions of Canadian $) |
|
LMCI
restricted investments1 |
|
|
Other
restricted investments2 |
|
|
LMCI
restricted investments1 |
|
|
Other
restricted investments2 |
|
|
|
|
|
|
|
|
|
|
Net unrealized gains in
the period |
|
|
|
|
|
|
|
|
three months ended |
|
51 |
|
|
1 |
|
|
2 |
|
|
1 |
|
1 Gains and losses arising from changes in the fair value of
LMCI restricted investments impact the subsequent amounts to be
collected through tolls to cover future pipeline abandonment costs.
As a result, the Company records these gains and losses as
regulatory assets or liabilities.2 Gains and losses on other
restricted investments are included in Interest income and other on
the Condensed consolidated statement of income.
Derivative instruments
Fair value of derivative instrumentsThe fair
value of foreign exchange and interest rate derivatives has been
calculated using the income approach which uses period-end market
rates and applies a discounted cash flow valuation model. The fair
value of commodity derivatives has been calculated using quoted
market prices where available. In the absence of quoted market
prices, third-party broker quotes or other valuation techniques
have been used. The fair value of options has been calculated using
the Black-Scholes pricing model. Credit risk has been taken into
consideration when calculating the fair value of derivative
instruments. Unrealized gains and losses on derivative instruments
are not necessarily representative of the amounts that will be
realized on settlement.
In some cases, even though the derivatives are considered to be
effective economic hedges, they do not meet the specific criteria
for hedge accounting treatment or are not designated as a hedge and
are accounted for at fair value with changes in fair value recorded
in net income in the period of change. This may expose the Company
to increased variability in reported earnings because the fair
value of the derivative instruments can fluctuate significantly
from period to period.
Balance sheet presentation of derivative
instrumentsThe balance sheet classification of the fair
value of derivative instruments is as follows:
at March 31, 2019 |
Cash Flow Hedges |
|
|
Fair Value Hedges |
|
|
Net Investment Hedges |
|
|
Held for Trading |
|
|
Total Fair Value of Derivative
Instruments1 |
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
|
|
|
|
|
Other current
assets |
|
|
|
|
|
|
|
|
|
Commodities2 |
— |
|
|
— |
|
|
— |
|
|
294 |
|
|
294 |
|
Foreign
exchange |
— |
|
|
— |
|
|
14 |
|
|
3 |
|
|
17 |
|
Interest rate |
2 |
|
|
— |
|
|
— |
|
|
— |
|
|
2 |
|
|
2 |
|
|
— |
|
|
14 |
|
|
297 |
|
|
313 |
|
Intangible and other
assets |
|
|
|
|
|
|
|
|
|
Commodities2 |
— |
|
|
— |
|
|
— |
|
|
28 |
|
|
28 |
|
Foreign
exchange |
— |
|
|
— |
|
|
1 |
|
|
— |
|
|
1 |
|
Interest
rate |
4 |
|
|
2 |
|
|
— |
|
|
— |
|
|
6 |
|
|
4 |
|
|
2 |
|
|
1 |
|
|
28 |
|
|
35 |
|
Total Derivative Assets |
6 |
|
|
2 |
|
|
15 |
|
|
325 |
|
|
348 |
|
Accounts payable and
other |
|
|
|
|
|
|
|
|
|
Commodities2 |
(4 |
) |
|
— |
|
|
— |
|
|
(273 |
) |
|
(277 |
) |
Foreign
exchange |
— |
|
|
— |
|
|
(39 |
) |
|
(71 |
) |
|
(110 |
) |
Interest rate |
— |
|
|
(2 |
) |
|
— |
|
|
— |
|
|
(2 |
) |
|
(4 |
) |
|
(2 |
) |
|
(39 |
) |
|
(344 |
) |
|
(389 |
) |
Other long-term
liabilities |
|
|
|
|
|
|
|
|
|
Commodities2 |
(1 |
) |
|
— |
|
|
— |
|
|
(23 |
) |
|
(24 |
) |
Foreign
exchange |
— |
|
|
— |
|
|
(1 |
) |
|
— |
|
|
(1 |
) |
Interest rate |
(24 |
) |
|
— |
|
|
— |
|
|
— |
|
|
(24 |
) |
|
(25 |
) |
|
— |
|
|
(1 |
) |
|
(23 |
) |
|
(49 |
) |
Total Derivative Liabilities |
(29 |
) |
|
(2 |
) |
|
(40 |
) |
|
(367 |
) |
|
(438 |
) |
Total Derivatives |
(23 |
) |
|
— |
|
|
(25 |
) |
|
(42 |
) |
|
(90 |
) |
1 Fair value equals carrying value.2 Includes purchases and
sales of power, natural gas and liquids.
at December 31, 2018 |
Cash Flow Hedges |
|
|
Fair Value Hedges |
|
|
Net Investment Hedges |
|
|
Held for Trading |
|
|
Total Fair Value of Derivative
Instruments1 |
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
|
|
|
|
|
Other current
assets |
|
|
|
|
|
|
|
|
|
Commodities2 |
1 |
|
|
— |
|
|
— |
|
|
716 |
|
|
717 |
|
Foreign
exchange |
— |
|
|
— |
|
|
16 |
|
|
1 |
|
|
17 |
|
Interest rate |
3 |
|
|
— |
|
|
— |
|
|
— |
|
|
3 |
|
|
4 |
|
|
— |
|
|
16 |
|
|
717 |
|
|
737 |
|
Intangible and other
assets |
|
|
|
|
|
|
|
|
|
Commodities2 |
1 |
|
|
— |
|
|
— |
|
|
50 |
|
|
51 |
|
Foreign
exchange |
— |
|
|
— |
|
|
1 |
|
|
— |
|
|
1 |
|
Interest rate |
8 |
|
|
1 |
|
|
— |
|
|
— |
|
|
9 |
|
|
9 |
|
|
1 |
|
|
1 |
|
|
50 |
|
|
61 |
|
Total Derivative Assets |
13 |
|
|
1 |
|
|
17 |
|
|
767 |
|
|
798 |
|
Accounts payable and
other |
|
|
|
|
|
|
|
|
|
Commodities2 |
(4 |
) |
|
— |
|
|
— |
|
|
(622 |
) |
|
(626 |
) |
Foreign
exchange |
— |
|
|
— |
|
|
(105 |
) |
|
(188 |
) |
|
(293 |
) |
Interest rate |
— |
|
|
(3 |
) |
|
— |
|
|
— |
|
|
(3 |
) |
|
(4 |
) |
|
(3 |
) |
|
(105 |
) |
|
(810 |
) |
|
(922 |
) |
Other long-term
liabilities |
|
|
|
|
|
|
|
|
|
Commodities2 |
— |
|
|
— |
|
|
— |
|
|
(28 |
) |
|
(28 |
) |
Foreign
exchange |
— |
|
|
— |
|
|
(2 |
) |
|
— |
|
|
(2 |
) |
Interest rate |
(11 |
) |
|
(1 |
) |
|
— |
|
|
— |
|
|
(12 |
) |
|
(11 |
) |
|
(1 |
) |
|
(2 |
) |
|
(28 |
) |
|
(42 |
) |
Total Derivative Liabilities |
(15 |
) |
|
(4 |
) |
|
(107 |
) |
|
(838 |
) |
|
(964 |
) |
Total Derivatives |
(2 |
) |
|
(3 |
) |
|
(90 |
) |
|
(71 |
) |
|
(166 |
) |
1 Fair value equals carrying value.2 Includes purchases and
sales of power, natural gas and liquids.
The majority of derivative instruments held for trading have
been entered into for risk management purposes and all are subject
to the Company's risk management strategies, policies and limits.
These include derivatives that have not been designated as hedges
or do not qualify for hedge accounting treatment but have been
entered into as economic hedges to manage the Company's exposures
to market risk.
Derivatives in fair value hedging
relationshipsThe following table details amounts recorded
on the Condensed consolidated balance sheet in relation to
cumulative adjustments for fair value hedges included in the
carrying amount of the hedged liabilities:
|
Carrying amount |
|
Fair value hedging adjustments1 |
(unaudited -
millions of Canadian $) |
March 31,
2019 |
|
|
December
31, 2018 |
|
|
March 31,
2019 |
|
|
December
31, 2018 |
|
|
|
|
|
|
|
|
|
Current portion of
long-term debt |
(332 |
) |
|
(748 |
) |
|
2 |
|
|
3 |
|
Long-term
debt |
(269 |
) |
|
(273 |
) |
|
(2 |
) |
|
— |
|
|
(601 |
) |
|
(1,021 |
) |
|
— |
|
|
3 |
|
1 At March 31, 2019 and December 31, 2018, adjustments
for discontinued hedging relationships included in these balances
were nil.
Notional and Maturity SummaryThe maturity and
notional amount or quantity outstanding related to the Company's
derivative instruments excluding hedges of the net investment in
foreign operations is as follows:
at March
31, 2019 |
Power |
|
|
Natural Gas |
|
|
Liquids |
|
|
Foreign Exchange |
|
|
Interest Rate |
|
(unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases1 |
17,374 |
|
|
34 |
|
|
63 |
|
|
— |
|
|
— |
|
Sales1 |
14,243 |
|
|
43 |
|
|
82 |
|
|
— |
|
|
— |
|
Millions
of U.S. dollars |
— |
|
|
— |
|
|
— |
|
|
3,900 |
|
|
1,400 |
|
Maturity dates |
2019-2024 |
|
|
2019-2027 |
|
|
2019-2020 |
|
|
2019-2020 |
|
|
2019-2030 |
|
1 Volumes for power, natural gas and liquids derivatives are in
GWh, Bcf and MMBbls, respectively.
at
December 31, 2018 |
Power |
|
|
NaturalGas |
|
|
Liquids |
|
|
Foreign Exchange |
|
|
Interest Rate |
|
(unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases1 |
23,865 |
|
|
44 |
|
|
59 |
|
|
— |
|
|
— |
|
Sales1 |
17,689 |
|
|
56 |
|
|
79 |
|
|
— |
|
|
— |
|
Millions
of U.S. dollars |
— |
|
|
— |
|
|
— |
|
|
3,862 |
|
|
1,650 |
|
Maturity dates |
2019-2023 |
|
|
2019-2027 |
|
|
2019 |
|
|
2019 |
|
|
2019-2030 |
|
1 Volumes for power, natural gas and liquids derivatives are in
GWh, Bcf and MMBbls, respectively.
Unrealized and realized (losses)/gains on derivative
instrumentsThe following summary does not include hedges
of the net investment in foreign operations.
|
|
three months ended March 31 |
(unaudited -
millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Derivative Instruments Held for
Trading1 |
|
|
|
|
Amount of unrealized
(losses)/gains in the period |
|
|
|
|
Commodities2 |
|
(88 |
) |
|
(109 |
) |
Foreign
exchange |
|
120 |
|
|
(79 |
) |
Amount of realized
gains/(losses) in the period |
|
|
|
|
Commodities |
|
107 |
|
|
110 |
|
Foreign
exchange |
|
(29 |
) |
|
15 |
|
Derivative
Instruments in Hedging Relationships |
|
|
|
|
Amount of realized
(losses)/gains in the period |
|
|
|
|
Commodities |
|
(7 |
) |
|
3 |
|
Interest rate |
|
— |
|
|
1 |
|
1 Realized and unrealized gains and losses on held-for-trading
derivative instruments used to purchase and sell commodities are
included on a net basis in Revenues. Realized and unrealized gains
and losses on interest rate and foreign exchange held-for-trading
derivative instruments are included on a net basis in Interest
expense and Interest income and other, respectively.2 In the three
months ended March 31, 2019 and 2018, there were no gains or
losses included in Net income relating to discontinued cash flow
hedges where it was probable that the anticipated transaction would
not occur.
Derivatives in cash flow hedging
relationshipsThe components of OCI (Note 9) related to the
change in fair value of derivatives in cash flow hedging
relationships before tax and including the portion attributable to
non-controlling interests are as follows:
|
|
three months ended March 31 |
(unaudited - millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Change in fair value of
derivative instruments recognized in OCI (effective portion)1 |
|
|
|
|
Commodities |
|
(3 |
) |
|
(3 |
) |
Interest rate |
|
(19 |
) |
|
9 |
|
|
|
(22 |
) |
|
6 |
|
1 No amounts have been excluded from the assessment of hedge
effectiveness. Amounts in parentheses indicate losses recorded to
OCI and AOCI.
Effect of fair value and cash flow hedging
relationshipsThe following table details amounts presented
on the Condensed consolidated statement of income in which the
effects of fair value or cash flow hedging relationships are
recorded.
|
|
three months ended March 31 |
|
|
Revenues (Power and Storage) |
|
Interest Expense |
(unaudited -
millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
2019 |
|
|
2018 |
|
|
|
|
|
|
|
|
|
|
Total Amount
Presented in the Condensed Consolidated Statement of
Income |
|
336 |
|
|
675 |
|
|
(586 |
) |
|
(527 |
) |
Fair Value
Hedges |
|
|
|
|
|
|
|
|
Interest rate
contracts |
|
|
|
|
|
|
|
|
Hedged
items |
|
— |
|
|
— |
|
|
(6 |
) |
|
(20 |
) |
Derivatives
designated as hedging instruments |
|
— |
|
|
— |
|
|
(1 |
) |
|
— |
|
Cash Flow
Hedges |
|
|
|
|
|
|
|
|
Reclassification of
gains/(losses) on derivative instruments from AOCI to net income1,
2 |
|
|
|
|
|
|
|
|
Interest
rate contracts |
|
— |
|
|
— |
|
|
4 |
|
|
5 |
|
Commodity contracts |
|
— |
|
|
(1 |
) |
|
— |
|
|
— |
|
1 Refer to Note 9, Other comprehensive (loss)/income and
accumulated other comprehensive loss, for the components of OCI
related to derivatives in cash flow hedging relationships including
the portion attributable to non-controlling interests.2 There are
no amounts recognized in earnings that were excluded from
effectiveness testing.
Offsetting of derivative instrumentsThe Company
enters into derivative contracts with the right to offset in the
normal course of business as well as in the event of default.
TransCanada has no master netting agreements, however, similar
contracts are entered into containing rights to offset. The Company
has elected to present the fair value of derivative instruments
with the right to offset on a gross basis in the Condensed
consolidated balance sheet. The following table shows the impact on
the presentation of the fair value of derivative instrument assets
and liabilities had the Company elected to present these contracts
on a net basis:
at March
31, 2019 |
|
Gross derivative instruments |
|
|
Amounts available for offset1 |
|
|
Net amounts |
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
|
|
|
|
|
Derivative instrument
assets |
|
|
|
|
|
|
Commodities |
|
322 |
|
|
(267 |
) |
|
55 |
|
Foreign
exchange |
|
18 |
|
|
(18 |
) |
|
— |
|
Interest rate |
|
8 |
|
|
(3 |
) |
|
5 |
|
|
|
348 |
|
|
(288 |
) |
|
60 |
|
Derivative instrument
liabilities |
|
|
|
|
|
|
Commodities |
|
(301 |
) |
|
267 |
|
|
(34 |
) |
Foreign
exchange |
|
(111 |
) |
|
18 |
|
|
(93 |
) |
Interest rate |
|
(26 |
) |
|
3 |
|
|
(23 |
) |
|
|
(438 |
) |
|
288 |
|
|
(150 |
) |
1 Amounts available for offset do not include cash collateral
pledged or received.
at
December 31, 2018 |
|
Gross derivative instruments |
|
|
Amounts available for offset1 |
|
|
Net amounts |
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
|
|
|
|
|
Derivative instrument
assets |
|
|
|
|
|
|
Commodities |
|
768 |
|
|
(626 |
) |
|
142 |
|
Foreign
exchange |
|
18 |
|
|
(18 |
) |
|
— |
|
Interest rate |
|
12 |
|
|
(4 |
) |
|
8 |
|
|
|
798 |
|
|
(648 |
) |
|
150 |
|
Derivative instrument
liabilities |
|
|
|
|
|
|
Commodities |
|
(654 |
) |
|
626 |
|
|
(28 |
) |
Foreign
exchange |
|
(295 |
) |
|
18 |
|
|
(277 |
) |
Interest rate |
|
(15 |
) |
|
4 |
|
|
(11 |
) |
|
|
(964 |
) |
|
648 |
|
|
(316 |
) |
1 Amounts available for offset do not include cash collateral
pledged or received.
With respect to the derivative instruments presented above, the
Company provided cash collateral of $118 million and letters of
credit of $37 million as at March 31, 2019 (December 31,
2018 – $143 million and $22 million) to its counterparties. At
March 31, 2019, the Company held no cash collateral and $1
million in letters of credit (December 31, 2018 – nil and $1
million) from counterparties on asset exposures.
Credit-risk-related contingent features of derivative
instrumentsDerivative contracts entered into to manage
market risk often contain financial assurance provisions that allow
parties to the contracts to manage credit risk. These provisions
may require collateral to be provided if a credit-risk-related
contingent event occurs, such as a downgrade in the Company’s
credit rating to non-investment grade. The Company may also need to
provide collateral if the fair value of its derivative financial
instruments exceeds pre-defined exposure limits.
Based on contracts in place and market prices at March 31,
2019, the aggregate fair value of all derivative instruments with
credit-risk-related contingent features that were in a net
liability position was $4 million (December 31, 2018 – $6
million), for which the Company has provided no collateral in the
normal course of business. If the credit-risk-related contingent
features in these agreements were triggered on March 31, 2019,
the Company would have been required to provide collateral of $4
million (December 31, 2018 – $6 million) to its
counterparties. Collateral may also need to be provided should the
fair value of derivative instruments exceed pre-defined contractual
exposure limit thresholds.
The Company has sufficient liquidity in the form of cash and
undrawn committed revolving credit facilities to meet these
contingent obligations should they arise.
FAIR VALUE HIERARCHYThe Company’s financial
assets and liabilities recorded at fair value have been categorized
into three categories based on a fair value hierarchy.
Levels |
How fair
value has been determined |
Level I |
Quoted prices in active markets for identical assets and
liabilities that the Company has the ability to access at the
measurement date. An active market is a market in which frequency
and volume of transactions provides pricing information on an
ongoing basis. |
Level II |
This category includes interest rate and foreign exchange
derivative assets and liabilities where fair value is determined
using the income approach and commodity derivatives where fair
value is determined using the market approach. Inputs include
published exchange rates, interest rates, interest rate swap
curves, yield curves and broker quotes from external data service
providers. |
Level III |
This category mainly includes long-dated commodity transactions in
certain markets where liquidity is low and the Company uses the
most observable inputs available or, if not available, long-term
broker quotes to estimate the fair value for these transactions.
There is uncertainty caused by using unobservable market data which
may not accurately reflect possible future changes in fair
value. |
The fair value of the Company’s derivative assets and
liabilities measured on a recurring basis, including both current
and non-current portions are categorized as follows:
at March 31, 2019 |
|
Quoted prices in active markets |
|
|
Significant other observable inputs |
|
|
Significant unobservable inputs |
|
|
|
(unaudited -
millions of Canadian $) |
|
(Level
I) |
|
|
(Level
II)1 |
|
|
(Level
III)1 |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
Derivative instrument
assets |
|
|
|
|
|
|
|
|
Commodities |
|
235 |
|
|
86 |
|
|
1 |
|
|
322 |
|
Foreign
exchange |
|
— |
|
|
18 |
|
|
— |
|
|
18 |
|
Interest
rate |
|
— |
|
|
8 |
|
|
— |
|
|
8 |
|
Derivative instrument
liabilities |
|
|
|
|
|
|
|
|
Commodities |
|
(229 |
) |
|
(67 |
) |
|
(5 |
) |
|
(301 |
) |
Foreign
exchange |
|
— |
|
|
(111 |
) |
|
— |
|
|
(111 |
) |
Interest
rate |
|
— |
|
|
(26 |
) |
|
— |
|
|
(26 |
) |
|
|
6 |
|
|
(92 |
) |
|
(4 |
) |
|
(90 |
) |
1 There were no transfers from Level II to Level III for the
three months ended March 31, 2019.
at December 31, 2018 |
|
Quoted prices in active markets |
|
|
Significant other observable inputs |
|
|
Significant unobservable inputs |
|
|
|
(unaudited -
millions of Canadian $) |
|
(Level
I) |
|
|
(Level
II)1 |
|
|
(Level
III)1 |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
Derivative instrument
assets |
|
|
|
|
|
|
|
|
Commodities |
|
581 |
|
|
187 |
|
|
— |
|
|
768 |
|
Foreign
exchange |
|
— |
|
|
18 |
|
|
— |
|
|
18 |
|
Interest
rate |
|
— |
|
|
12 |
|
|
— |
|
|
12 |
|
Derivative instrument
liabilities |
|
|
|
|
|
|
|
|
Commodities |
|
(555 |
) |
|
(95 |
) |
|
(4 |
) |
|
(654 |
) |
Foreign
exchange |
|
— |
|
|
(295 |
) |
|
— |
|
|
(295 |
) |
Interest
rate |
|
— |
|
|
(15 |
) |
|
— |
|
|
(15 |
) |
|
|
26 |
|
|
(188 |
) |
|
(4 |
) |
|
(166 |
) |
1 There were no transfers from Level II to Level III for the
year ended December 31, 2018.
The following table presents the net change in fair value of
derivative assets and liabilities classified as Level III of the
fair value hierarchy:
|
|
three months ended March 31 |
(unaudited -
millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Balance at beginning of
period |
|
(4 |
) |
|
(7 |
) |
Total losses included
in Net income |
|
— |
|
|
(2 |
) |
Settlements |
|
— |
|
|
(9 |
) |
Balance at end of period1 |
|
(4 |
) |
|
(18 |
) |
1 For the three months ended March 31, 2019, Revenues
included unrealized gains of less than $1 million attributed to
derivatives in the Level III category that were still held at
March 31, 2019 (2018 – unrealized losses of $11 million).
12. Contingencies and guarantees
CONTINGENCIESTransCanada and its subsidiaries
are subject to various legal proceedings, arbitrations and actions
arising in the normal course of business. While the final
outcome of such legal proceedings and actions cannot be predicted
with certainty, it is the opinion of management that the resolution
of such proceedings and actions will not have a material impact on
the Company’s consolidated financial position or results of
operations.
GUARANTEESTransCanada and its partner on the
Sur de Texas pipeline, IEnova, have jointly guaranteed the
financial performance of this entity. Such agreements include a
guarantee and a letter of credit which are primarily related to
construction services and the delivery of natural gas.
TransCanada and its joint venture partner on Bruce Power, BPC
Generation Infrastructure Trust, have each severally guaranteed
certain contingent financial obligations of Bruce Power related to
a lease agreement and contractor and supplier services.
The Company and its partners in certain other jointly owned
entities have either (i) jointly and severally, (ii) jointly or
(iii) severally guaranteed the financial performance of these
entities. Such agreements include guarantees and letters of credit
which are primarily related to delivery of natural gas,
construction services and the payment of liabilities. For certain
of these entities, any payments made by TransCanada under these
guarantees in excess of its ownership interest are to be reimbursed
by its partners.
The carrying value of these guarantees has been included in
Other long-term liabilities on the Condensed consolidated balance
sheet. Information regarding the Company’s guarantees is as
follows:
|
|
|
|
at March 31, 2019 |
|
at December 31, 2018 |
(unaudited - millions of Canadian $) |
|
Term |
|
Potential exposure1 |
|
|
Carryingvalue |
|
|
Potential exposure1 |
|
|
Carrying value |
|
|
|
|
|
|
|
|
|
|
|
|
Sur de Texas |
|
ranging
to 2020 |
|
174 |
|
|
1 |
|
|
183 |
|
|
1 |
|
Bruce Power |
|
ranging
to 2021 |
|
88 |
|
|
— |
|
|
88 |
|
|
— |
|
Other
jointly-owned entities |
|
ranging to 2059 |
|
102 |
|
|
11 |
|
|
104 |
|
|
11 |
|
|
|
|
|
364 |
|
|
12 |
|
|
375 |
|
|
12 |
|
1 TransCanada’s share of the potential estimated current or
contingent exposure.
13. Variable interest entities
A VIE is a legal entity that does not have sufficient equity at
risk to finance its activities without additional subordinated
financial support or is structured such that equity investors lack
the ability to make significant decisions relating to the entity’s
operations through voting rights or do not substantively
participate in the gains and losses of the entity.
In the normal course of business, the Company consolidates VIEs
in which it has a variable interest and for which it is considered
to be the primary beneficiary. VIEs in which the Company has a
variable interest but is not the primary beneficiary are considered
non-consolidated VIEs and are accounted for as equity
investments.
Consolidated VIEsThe Company's consolidated
VIEs consist of legal entities where the Company is the primary
beneficiary. As the primary beneficiary, the Company has the power,
through voting or similar rights, to direct the activities of the
VIE that most significantly impact economic performance including
purchasing or selling significant assets; maintenance and
operations of assets; incurring additional indebtedness; or
determining the strategic operating direction of the entity. In
addition, the Company has the obligation to absorb losses or the
right to receive benefits from the consolidated VIE that could
potentially be significant to the VIE.
A significant portion of the Company’s assets are held through
VIEs in which the Company holds a 100 per cent voting interest, the
VIE meets the definition of a business and the VIE’s assets can be
used for general corporate purposes. The Consolidated VIEs whose
assets cannot be used for purposes other than the settlement of the
VIE’s obligations are as follows:
|
|
March
31, |
|
|
December
31, |
|
(unaudited - millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
ASSETS |
|
|
|
|
Current
Assets |
|
|
|
|
Cash and cash
equivalents |
|
69 |
|
|
45 |
|
Accounts
receivable |
|
69 |
|
|
79 |
|
Inventories |
|
26 |
|
|
24 |
|
Other |
|
9 |
|
|
13 |
|
|
|
173 |
|
|
161 |
|
Plant, Property
and Equipment |
|
2,949 |
|
|
3,026 |
|
Equity
Investments |
|
847 |
|
|
965 |
|
Goodwill |
|
444 |
|
|
453 |
|
Intangible and Other Assets |
|
3 |
|
|
8 |
|
|
|
4,416 |
|
|
4,613 |
|
LIABILITIES |
|
|
|
|
Current
Liabilities |
|
|
|
|
Accounts payable and
other |
|
79 |
|
|
88 |
|
Accrued interest |
|
31 |
|
|
24 |
|
Current
portion of long-term debt |
|
76 |
|
|
79 |
|
|
|
186 |
|
|
191 |
|
Regulatory
Liabilities |
|
42 |
|
|
43 |
|
Other Long-Term
Liabilities |
|
4 |
|
|
3 |
|
Deferred Income
Tax Liabilities |
|
12 |
|
|
13 |
|
Long-Term Debt |
|
3,003 |
|
|
3,125 |
|
|
|
3,247 |
|
|
3,375 |
|
Non-Consolidated VIEsThe Company’s
non-consolidated VIEs consist of legal entities where the Company
is not the primary beneficiary as it does not have the power to
direct the activities that most significantly impact the economic
performance of these VIEs or where this power is shared with third
parties. The Company contributes capital to these VIEs and receives
ownership interests that provide it with residual claims on assets
after liabilities are paid.
The carrying value of these VIEs and the maximum exposure to
loss as a result of the Company's involvement with these VIEs are
as follows:
|
|
March
31, |
|
|
December
31, |
|
(unaudited - millions of Canadian $) |
|
2019 |
|
|
2018 |
|
|
|
|
|
|
Balance
sheet |
|
|
|
|
Equity
investments |
|
4,487 |
|
|
4,575 |
|
Off-balance
sheet |
|
|
|
|
Potential exposure to guarantees |
|
168 |
|
|
170 |
|
Maximum exposure to loss |
|
4,655 |
|
|
4,745 |
|
14. Subsequent Event
Long-term debt issuanceOn April 10, 2019, TCPL
issued $1.0 billion of Medium Term Notes, due in October 2049,
bearing interest at a fixed rate of 4.34 per cent.
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