Funding Complete for 2018 Capital
Program
CALGARY, Alberta, Nov. 01, 2018 (GLOBE NEWSWIRE) -- TransCanada
Corporation (TSX, NYSE: TRP) (TransCanada or the Company) today
announced net income attributable to common shares for third
quarter 2018 of $928 million or $1.02 per share compared to net
income of $612 million or $0.70 per share for the same period in
2017. Comparable earnings for third quarter 2018 were $902 million
or $1.00 per share compared to $614 million or $0.70 per share for
the same period in 2017. TransCanada's Board of Directors also
declared a quarterly dividend of $0.69 per common share for the
quarter ending December 31, 2018, equivalent to $2.76 per common
share on an annualized basis.
"During the third quarter of 2018, our diversified portfolio of
critical energy infrastructure assets continued to perform
extremely well," said Russ Girling, TransCanada's president and
chief executive officer. "Comparable earnings of $1.00 per share
increased 43 per cent compared to the same period last year
reflecting the strong performance of our legacy assets,
contributions from approximately $7 billion of growth projects that
entered service over the last twelve months and the positive impact
of U.S. Tax Reform. For the nine months ended September 30, 2018,
comparable earnings were $2.82 per share, an increase of 24 per
cent over the same period last year despite the sale of our U.S.
Northeast power generation and Ontario solar assets in 2017 and
necessary financing activities that have us on track to return to
long-term targeted credit metrics post the Columbia
acquisition."
"With our existing asset portfolio benefiting from strong
underlying market fundamentals and approximately $36 billion of
secured growth projects underway including Coastal GasLink, NGTL's
2022 expansion program and Bruce Power's Unit 6 refurbishment,
earnings and cash flow are forecast to continue to rise. This is
expected to support annual dividend growth of eight to ten per cent
through 2021,” added Girling. "With approximately $10 billion of
new projects expected to enter service by early 2019, we are well
positioned to fund the remainder of our secured growth program
through internally generated cash flow, access to capital markets
and further portfolio management activities. Through the end of
October, we placed approximately $6.1 billion of long-term debt on
compelling terms and raised approximately $2.0 billion of common
equity through our dividend reinvestment plan and at-the-market
program. We also completed the sale of our interests in the Cartier
Wind power facilities for proceeds of approximately $630 million
and expect to be reimbursed for approximately $400 million of
Coastal GasLink pre-development costs. Collectively these
initiatives have raised $9.1 billion which, when combined with our
growing internally generated cash flow, means our 2018 financing
requirements are fully funded. We view ATM issuance as being
complete at this time while our dividend reinvestment plan will
operate for some portion of 2019. Going forward, we will continue
to evaluate share count growth against further portfolio management
activities."
"Looking ahead, we continue to methodically advance more than
$20 billion of projects under development including Keystone XL and
the Bruce Power life extension agreement. Success in advancing
these and/or other growth initiatives associated with our vast,
well-positioned North American footprint 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)
- Third quarter 2018 financial results
- Net income attributable to common shares of $928 million or
$1.02 per common share
- Comparable earnings of $902 million or $1.00 per common
share
- Comparable earnings before interest, taxes, depreciation and
amortization of $2.1 billion
- Net cash provided by operations of $1.3 billion
- Comparable funds generated from operations of $1.6 billion
- Comparable distributable cash flow of $1.4 billion or $1.56 per
common share reflecting only non-recoverable maintenance capital
expenditures
- Declared a quarterly dividend of $0.69 per common share for the
quarter ending December 31, 2018
- Announced that we will proceed with construction of the $6.2
billion Coastal GasLink pipeline project
- Announced $1.5 billion NGTL 2022 Expansion Program
- Bruce Power submitted a final estimate for the Unit 6 Major
Component Replacement (MCR) program to the Independent Electricity
System Operator (IESO) in September 2018; we expect to invest
approximately $2.2 billion in this and the ongoing Asset Management
program through 2023
- Issued $1.0 billion of 10- and 30-year fixed-rate medium-term
notes in July 2018
- Raised US$1.4 billion of 10- and 30-year fixed-rate senior
notes in October 2018
- Completed the sale of our interests in Cartier Wind for
approximately $630 million in October 2018
- Expect to be reimbursed for $399 million of Coastal GasLink
pre-development costs in fourth quarter 2018.
Net income attributable to common shares increased by $316
million or $0.32 per common share to $928 million or $1.02 per
share for the three months ended September 30, 2018 compared to the
same period last year. Per share results in 2018 reflect the
dilutive effect of common shares issued in 2017 and 2018 under our
DRP and Corporate ATM program. Third quarter 2018 results included
after-tax income of $8 million related to our U.S. Northeast power
marketing contracts which were excluded from comparable earnings as
we do not consider their wind-down part of our underlying
operations. Third quarter 2017 results included a $12 million
after-tax loss 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 and an after-tax charge of $8 million related to the
maintenance of Keystone XL assets. All of these specific items, as
well as unrealized gains and losses from changes in risk management
activities, are excluded from comparable earnings.
Comparable earnings for third quarter 2018 were $902 million or
$1.00 per common share compared to $614 million or $0.70 per common
share for the same period in 2017, an increase of $288 million or
$0.30 per share and was primarily due to the net effect of:
- higher contribution from U.S. Natural Gas Pipelines mainly due
to increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service, additional contract sales on ANR and
Great Lakes and the amortization of net regulatory liabilities
recognized as a result of U.S. Tax Reform
- higher contribution from Liquids Pipelines primarily due to
earnings from intra-Alberta pipelines placed in service in the
second half of 2017, increased earnings from liquids marketing
activities, and higher volumes on the Keystone Pipeline System
- lower income tax expense primarily due to lower income tax
rates as a result of U.S. Tax Reform
- higher revenues from our Mexico operations as a result of
changes in timing of revenue recognition
- higher interest expense primarily as a result of long-term debt
and junior subordinated notes issuances, net of maturities, and
lower capitalized interest.
Notable recent developments include:
Canadian Natural Gas Pipelines:
- Coastal GasLink Pipeline (CGL) Project: On October 2,
2018, we announced that we will proceed with construction of the
CGL pipeline project following the LNG Canada joint venture
participants' announcement that they have reached a positive Final
Investment Decision (FID) to build the LNG Canada natural gas
liquefaction facility in Kitimat, BC. CGL will provide the
natural gas supply to the LNG Canada facility and is underpinned by
25-year transportation services agreements (with additional renewal
provisions) with the LNG Canada participants. CGL is a 670 km (420
miles) pipeline with an initial capacity of approximately 2.2 PJ/d
(2.1 Bcf/d) with potential expansion capacity up to 5.4 PJ/d (5.0
Bcf/d). All necessary regulatory permits have been received to
allow us to proceed with construction activities which are expected
to begin in January 2019, with a planned in-service date in 2023.
CGL has signed project and community agreements with all 20 elected
Indigenous bands along the pipeline route, confirming strong
support from Indigenous communities across the province of B.C.
On July 30, 2018, an individual asked the National Energy Board
(NEB) to consider whether the CGL pipeline should be federally
regulated by the NEB. On October 22, 2018 the NEB advised that it
would consider the question of jurisdiction. In the same letter,
the NEB set a process to determine whether the individual who
raised the question has standing, and to decide on the standing of
any other interested parties. The process to consider the
jurisdictional question is to be determined and the permits to
construct remain valid.
The capital cost estimate is $6.2 billion with the majority of the
construction spend occurring in 2020 and 2021. Subject to terms and
conditions, differences between the estimated capital cost and
final cost of the project will be recovered in future pipeline
tolls. As part of the CGL funding plan, we intend to explore
joint venture partners and project financing for the project.
The total capital cost estimate includes pre-development costs to
date of approximately $470 million. In accordance with provisions
in the agreements with the LNG Canada joint venture participants,
to date, four parties have elected to reimburse us for their share
of pre-development costs, totaling $399 million of cost
reimbursement, with payments due by November 30, 2018.
- NGTL System: On October 31, 2018, we announced
the NGTL 2022 Expansion Program to meet capacity requirements for
incremental firm receipt and intra-basin delivery services to
commence in November 2021 and April 2022. This $1.5 billion
expansion of the NGTL System consists of approximately 197 km (122
miles) of new pipeline, three compressor units, meter stations and
associated facilities. Applications for approvals to construct and
operate the facilities are expected to be filed with the NEB in
second quarter 2019 and, pending receipt of regulatory approvals,
construction would start as early as third quarter 2020.
The NGTL capital program, excluding maintenance capital
expenditures, is now approximately $9.1 billion including the $1.5
billion 2022 Expansion Program.
- Canadian Mainline: On October 9, 2018, we
concluded the written hearing process for the Canadian Mainline
2018-2020 toll review with the filing of our reply evidence to the
NEB. We have requested a decision by December 31, 2018.
U.S. Natural Gas Pipelines:
- WB XPress: The Western Build of the WB XPress (WBX)
project was placed into service on October 5, 2018. The Eastern
Build of WBX remains to be completed, as planned, in fourth
quarter 2018.
- 2018 FERC Actions: On March 15, 2018, the Federal
Energy Regulatory Commission (FERC) issued (1) a Revised
Policy Statement to address the treatment of income taxes for
rate-making purposes for master limited partnerships; (2) a Notice
of Proposed Rulemaking (NOPR) proposing natural gas pipeline and
storage entities file a one-time report to quantify the impact of
the federal income tax rate reduction and the impact of
the Revised Policy Statement on each entity's return on equity
assuming a single-issue adjustment to an entity's rates; and (3) a
notice of inquiry seeking comment on how FERC should address
changes related to accumulated deferred income taxes and bonus
depreciation. On July 18, 2018, FERC issued (1) an Order on
Rehearing of the Revised Policy Statement dismissing rehearing
requests and (2) a Final Rule adopting and revising procedures
from, and clarifying aspects of, the NOPR (Final Rule),
(collectively, the “2018 FERC Actions”). The Final Rule became
effective September 13, 2018, and is subject to requests for
further rehearing and clarification. Each is described more fully
in our management's discussion and analysis (MD&A).
Our U.S. natural gas pipelines are held through a number of
different ownership structures. We do not anticipate that
the earnings and cash flows from our directly-held U.S. natural gas
pipelines, including ANR, Columbia Gas and Columbia Gulf, will be
materially impacted by the Revised Policy Statement as a
significant proportion of their overall revenues are earned under
non-recourse rates.
For more information on the impact of the 2018 FERC Actions on TC
PipeLines, LP and our U.S. natural gas pipelines held through TC
PipeLines, LP, please refer to our MD&A in the 2018 FERC
Actions section. As our ownership interest in TC PipeLines, LP is
approximately 25 per cent, the impact of the 2018 FERC Actions
related to TC PipeLines, LP is not expected to be significant to
our consolidated earnings or cash flows.
- Rate Settlements: In October 2018, Gas Transmission
Northwest LLC (GTN) filed with FERC an uncontested settlement with
its customers. Please refer to our MD&A in the 2018 FERC
Actions section for additional detail.
Mexico Natural Gas Pipelines:
- Sur de Texas: Offshore construction was completed in
May 2018 and the project continues to progress toward an
anticipated in-service date at the end of 2018. An amending
agreement has been signed with the Comisión Federal de Electricidad
(CFE) that recognizes force majeure events and the commencement of
payments of fixed capacity charges beginning October 31, 2018.
- Tula and Villa de Reyes: The CFE has approved the
recognition of force majeure events for both of these pipelines,
including the continuation of the payment of fixed capacity charges
to us that began in first quarter 2018. Construction of the Villa
de Reyes project is ongoing and it is anticipated to be in service
by the second half of 2019.
Liquids Pipelines:
- Keystone XL: In December 2017, an appeal to Nebraska's
Court of Appeals was filed by intervenors after the Nebraska Public
Service Commission (PSC) issued an approval of an alternative route
for the Keystone XL project in November 2017. In March 2018, the
Nebraska Supreme Court, on its own motion, agreed to bypass the
Court of Appeals and directly hear the appeal case against the
PSC’s alternative route. Legal briefs on the appeal were submitted
in May 2018. Oral argument before the Nebraska Supreme Court has
been set for November 1, 2018. We expect the Nebraska Supreme
Court, as the final arbiter, could reach a decision by first
quarter 2019.
The Keystone XL Presidential Permit, issued in March 2017, has been
challenged in two separate lawsuits commenced in Montana. Together
with the U.S. Department of Justice (DOJ), we are actively
participating in these lawsuits to defend both the issuance of the
permit and the exhaustive environmental assessments that support
the U.S. President’s actions. Legal arguments addressing the merits
of these lawsuits were heard in May 2018 and we believe the court’s
decisions on certain elements of these legal challenges may be
issued by the end of 2018.
On August 15, 2018, the U.S. District Court in Montana issued a
Partial Order requiring the DOJ and the U.S. Department of State
(DOS) (the Federal Defendants) to prepare a supplemental
environmental impact statement (SEIS) to the 2014 Final
Supplemental Environmental Impact Statement and a proposed schedule
for the completion of the SEIS. On September 4, 2018, the Federal
Defendants responded to this Partial Order by filing the required
schedule which reflected the issuance of the final SEIS in December
2018. On September 21, 2018, the DOS issued a draft SEIS which
concluded that implementation of the mainline alternative route
would have no significant direct, indirect or cumulative effect on
the quality of the natural or human environments, having
consideration for the mitigation plans proposed by TransCanada. The
draft SEIS is open for public comment for a period of 45 days. The
Federal Defendants also indicated that the U.S. Bureau of Land
Management and the U.S. Army Corps of Engineers would likely issue
decisions regarding their respective federal permitting activities
in first quarter 2019.
In September 2018, two U.S. Native American communities filed a
lawsuit in Montana challenging the Keystone XL Presidential Permit.
It is uncertain how and when this lawsuit will proceed.
Energy:
- Cartier Wind: On October 24, 2018, we completed
the sale of our interests in the Cartier Wind power facilities in
Québec to Innergex Renewable Energy Inc. for gross proceeds of
approximately $630 million before closing adjustments resulting in
an estimated gain of $170 million ($135 million after tax) to be
recorded in fourth quarter 2018.
- Bruce Power - Life Extension: On September 28, 2018,
Bruce Power submitted its final cost and schedule duration estimate
(basis of estimate) for the Unit 6 MCR program to the IESO. The
IESO has up to three months to review and verify the basis of
estimate. As the cost and schedule duration are both less than the
thresholds defined in the program's life extension and
refurbishment agreement, no further approvals from the IESO or
government are required to proceed with the Unit 6 MCR outage in
early 2020. The Unit 6 MCR outage is expected to be completed in
late 2023.
As a result of this filing, we have updated our project cost
estimates in our Capital Program tables to reflect our expected
investment of approximately $2.2 billion (in nominal dollars) in
Bruce Power's Unit 6 MCR program and ongoing Asset Management (AM)
program through 2023, and approximately $6.0 billion (in 2018
dollars) for the remaining five-unit MCR program and the AM program
beyond 2023. Future MCR investments will be subject to discrete
decisions for each unit with specified off-ramps available for
Bruce Power and the IESO.
Bruce Power's current contract price of approximately $68 per MWh
will be increased in April 2019 to reflect capital to be invested
under the Unit 6 MCR program and the AM program as well as normal
annual inflation adjustments.
- Napanee: Construction continues on our 900 MW natural
gas-fired power plant at Ontario Power Generation's (OPG) Lennox
site in eastern Ontario in the town of Greater Napanee. We expect
our total investment in the Napanee facility will be approximately
$1.6 billion and commercial operations are expected to begin in
first quarter 2019. Costs have increased due to delays in the
construction schedule. Once in service, production from the
facility is fully contracted with the IESO for a 20-year
period.
Corporate:
- Common Share Dividend: Our Board of Directors declared
a quarterly dividend of $0.69 per share for the quarter ending
December 31, 2018 on TransCanada's outstanding common shares. The
quarterly amount is equivalent to $2.76 per common share on an
annualized basis.
- Issuance of Long-term Debt: In October 2018, TCPL
issued US$1.0 billion of Senior Unsecured Notes due in March 2049
bearing interest at a fixed rate of 5.10 per cent and US$400
million of Senior Unsecured Notes due in May 2028 bearing interest
at a fixed rate of 4.25 per cent.
In third quarter 2018, TCPL issued $800 million of Medium Term
Notes due in July 2048 bearing interest at a fixed rate of 4.18 per
cent and $200 million of Medium Term Notes due in March 2028
bearing interest at a fixed rate of 3.39 per cent.
The net proceeds of the above debt issuances were used for general
corporate purposes, to fund our capital program and to pre-fund
2019 senior note maturities.
In third quarter 2018, TCPL repaid US$850 million of Senior
Unsecured Notes bearing interest at a fixed rate of 6.50 per
cent.
- Dividend Reinvestment Plan: In third quarter 2018, the
DRP participation rate amongst common shareholders was
approximately 34 per cent, resulting in $213 million reinvested in
common equity under the program. Year-to-date in 2018, the
participation rate amongst common shareholders has been
approximately 35 per cent, resulting in $655 million of dividends
reinvested.
- ATM Equity Program: In third quarter 2018, 6.1 million
common shares were issued under our Corporate ATM program at an
average price of $57.75 per common share for proceeds of $351
million, net of related commissions and fees of approximately $3
million. In the nine months ended September 30, 2018, 20.0 million
common shares have been issued under our Corporate ATM program at
an average price of $56.13 per common share for proceeds of $1.1
billion, net of approximately $10 million of related commissions
and fees.
Teleconference and Webcast:
We will hold a teleconference and webcast on Thursday, November
1, 2018 to discuss our third quarter 2018 financial results. Russ
Girling, President and Chief Executive Officer, and Don Marchand,
Executive Vice-President and Chief Financial Officer, along with
other members of the TransCanada executive leadership team, will
discuss the financial results and Company developments at 8 a.m.
(MT) / 10 a.m. (ET).
Members of the investment community and other interested parties
are invited to participate by calling 800.377.0758 or 416.340.2219
(Toronto area). Please dial in 10 minutes prior to the start of the
call. No pass code is required. A live webcast of the
teleconference will be available at www.transcanada.com or via the following URL:
www.gowebcasting.com/9680.
A replay of the teleconference will be available two hours after
the conclusion of the call until midnight (ET) on November 8, 2018.
Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter
pass code 1642917#.
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 the TransCanada website at www.transcanada.com.
With more than 65 years' experience, TransCanada is a leader in
the responsible development and reliable
operation of North American energy infrastructure including natural
gas and liquids pipelines, power generation and gas storage
facilities. TransCanada operates one of the largest natural gas
transmission networks that extends more than 91,900 kilometres
(57,100 miles), tapping into virtually all major gas supply basins
in North America. TransCanada is a leading provider of gas storage
and related services with 653 billion cubic feet of storage
capacity. A large independent power producer, TransCanada owns or
has interests in approximately 5,700 megawatts of power generation
in Canada and the United States. TransCanada is also the developer
and operator of one of North America's leading liquids pipeline
systems that extends approximately 4,900 kilometres (3,000 miles),
connecting growing continental oil supplies to key markets and
refineries. TransCanada's common shares trade on the Toronto and
New York stock exchanges under the symbol TRP. Visit www.transcanada.com to learn more, or connect with us on social media.
Forward Looking Information
This release contains certain information that is forward-looking
and is subject to important risks and uncertainties (such
statements are usually accompanied by words such as "anticipate",
"expect", "believe", "may", "will", "should", "estimate", "intend"
or other similar words). Forward-looking statements in this
document are intended to provide TransCanada security holders and
potential investors with information regarding TransCanada and its
subsidiaries, including management's assessment of TransCanada's
and its subsidiaries' future plans and financial outlook. All
forward-looking statements reflect TransCanada's beliefs and
assumptions based on information available at the time the
statements were made and as such are not guarantees of future
performance. Readers are cautioned not to place undue reliance on
this forward-looking information, which is given as of the date it
is expressed in this news release, and not to use future-oriented
information or financial outlooks for anything other than their
intended purpose. TransCanada undertakes no obligation to update or
revise any forward-looking information except as required by law.
For additional information on the assumptions made, and the risks
and uncertainties which could cause actual results to differ from
the anticipated results, refer to the Quarterly Report to
Shareholders dated October 31, 2018 and the 2017 Annual Report
filed under TransCanada's profile on SEDAR at www.sedar.com and with the U.S. Securities and
Exchange Commission at www.sec.gov.
Non-GAAP Measures
This news release contains references to non-GAAP measures,
including comparable earnings, comparable earnings per common
share, comparable EBITDA, comparable distributable cash flow,
comparable distributable cash flow per common share and comparable
funds generated from operations, that do not have any standardized
meaning as prescribed by U.S. GAAP and therefore are unlikely to be
comparable to similar measures presented by other companies. These
non-GAAP measures are calculated on a consistent basis from period
to period and are adjusted for specific items in each period, as
applicable except as otherwise described in the Condensed
consolidated financial statements and MD&A. For more
information on non-GAAP measures, refer to TransCanada's Quarterly
Report to Shareholders dated October 31, 2018.
Media Enquiries:
Grady Semmens
403.920.7859 or 800.608.7859
Investor & Analyst
Enquiries:
David Moneta / Duane Alexander
403.920.7911 or 800.361.6522
Quarterly report to shareholders
Third quarter 2018
Financial highlights
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $, except per share amounts) |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
Income |
|
|
|
|
|
|
|
|
Revenues |
|
|
3,156 |
|
|
|
3,195 |
|
|
|
9,775 |
|
|
|
9,832 |
|
Net income attributable
to common shares |
|
|
928 |
|
|
|
612 |
|
|
|
2,447 |
|
|
|
2,136 |
|
per
common share – basic |
|
$1.02 |
|
|
$0.70 |
|
|
$2.72 |
|
|
$2.46 |
|
– diluted |
|
$1.02 |
|
|
$0.70 |
|
|
$2.72 |
|
|
$2.45 |
|
Comparable
EBITDA1 |
|
|
2,056 |
|
|
|
1,667 |
|
|
|
6,110 |
|
|
|
5,474 |
|
Comparable
earnings1 |
|
|
902 |
|
|
|
614 |
|
|
|
2,534 |
|
|
|
1,971 |
|
per
common share1 |
|
$1.00 |
|
|
$0.70 |
|
|
$2.82 |
|
|
$2.27 |
|
|
|
|
|
|
|
|
|
|
Cash
flows |
|
|
|
|
|
|
|
|
Net cash provided by
operations |
|
|
1,299 |
|
|
|
1,185 |
|
|
|
4,516 |
|
|
|
3,840 |
|
Comparable funds
generated from operations1 |
|
|
1,571 |
|
|
|
1,316 |
|
|
|
4,641 |
|
|
|
4,191 |
|
Comparable
distributable cash flow1 |
|
|
1,413 |
|
|
|
1,170 |
|
|
|
4,158 |
|
|
|
3,691 |
|
per
common share1 |
|
$1.56 |
|
|
$1.34 |
|
|
$4.63 |
|
|
$4.24 |
|
Capital
spending2 |
|
|
2,798 |
|
|
|
2,543 |
|
|
|
7,491 |
|
|
|
6,658 |
|
|
|
|
|
|
|
|
|
|
Dividends
declared |
|
|
|
|
|
|
|
|
Per common share |
|
$0.69 |
|
|
$0.625 |
|
|
$2.07 |
|
|
$1.875 |
|
Basic common
shares outstanding (millions) |
|
|
|
|
|
|
|
|
–
weighted average for the period |
|
|
906 |
|
|
|
873 |
|
|
|
898 |
|
|
|
870 |
|
– issued and outstanding at end of period |
|
|
914 |
|
|
|
874 |
|
|
|
914 |
|
|
|
874 |
|
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.
See 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
October 31, 2018
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 and nine
months ended September 30, 2018, and should be read with the
accompanying unaudited condensed consolidated financial statements
for the three and nine months ended September 30, 2018, which
have been prepared in accordance with U.S. GAAP.
This MD&A should also be read in conjunction with our
December 31, 2017 audited consolidated financial statements
and notes and the MD&A in our 2017 Annual
Report. Capitalized and abbreviated terms that are used but
not otherwise defined herein are identified in our 2017 Annual
Report. Certain comparative figures have been adjusted to reflect
the current period’s presentation.
FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and
potential investors understand management’s assessment of our
future plans and financial outlook, and our future prospects
overall.
Statements that are forward-looking are based on
certain assumptions and on what we know and expect today. These
statements 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:
- planned changes in our business
- our financial and operational performance, including the
performance of our subsidiaries
- expectations or projections about strategies and goals for
growth and expansion
- expected cash flows and future financing options available to
us
- expected dividend growth
- expected costs for planned projects, including projects under
construction, permitting and in development
- expected schedules for planned projects (including anticipated
construction and completion dates)
- expected regulatory processes and outcomes, including the
expected impact of the 2018 FERC Actions
- expected outcomes with respect to legal proceedings, including
arbitration and insurance claims
- expected capital expenditures and contractual obligations
- expected operating and financial results
- expected impact of future accounting changes, commitments and
contingent liabilities
- expected impact of U.S. Tax Reform
- 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 is subject to the following risks and
uncertainties:
Assumptions
- continued wind-down of our U.S. Northeast power marketing
business
- inflation rates and commodity prices
- nature and scope of hedging activities
- regulatory decisions and outcomes, including those related to
the 2018 FERC Actions
- interest, tax and foreign exchange rates, including the impact
of U.S. Tax Reform
- planned and unplanned outages and the use of our pipeline and
energy assets
- integrity and reliability of our assets
- access to capital markets
- anticipated construction costs, schedules and completion
dates.
Risks and uncertainties
- our ability to successfully implement our strategic priorities
and whether they will yield the expected benefits
- the operating performance of our pipeline and energy
assets
- amount of capacity sold and rates achieved in our pipeline
businesses
- the availability and price of energy commodities
- the amount of capacity payments and revenues from our energy
business
- regulatory decisions and outcomes, including those related to
the 2018 FERC Actions
- outcomes of legal proceedings, including arbitration and
insurance claims
- performance and credit risk of our counterparties
- changes in market commodity prices
- changes in the regulatory environment
- changes in the political environment
- changes in environmental and other laws and regulations
- competitive factors in the pipeline and energy sectors
- construction and completion of capital projects
- costs for labour, equipment and materials
- access to capital markets
- interest, tax and foreign exchange rates, including the impact
of U.S. Tax Reform
- weather
- cyber security
- technological developments
- economic conditions in North America as well as globally.
You can read more about these factors and others in this
MD&A and in other disclosure documents we have filed with
Canadian securities regulators and the SEC, including the MD&A
in our 2017 Annual Report.
As actual results could vary significantly from the
forward-looking information, you should not put undue reliance on
forward-looking information and should not use future-oriented
information or financial outlooks for anything other than their
intended purpose. We do not update our forward-looking statements
due to new information or future events, unless we are required to
by law.
FOR MORE INFORMATION
You can find more information about TransCanada in our Annual
Information Form and other disclosure documents, which are
available on SEDAR (www.sedar.com).
NON-GAAP MEASURES
This MD&A references the following non-GAAP measures:
- comparable earnings
- comparable earnings per common share
- comparable EBITDA
- comparable EBIT
- 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 similar to measures
presented by other entities.
Comparable measures
We 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. 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 and changes 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 property, plant and equipment, goodwill,
investments and other assets including certain ongoing maintenance
and liquidation costs
- acquisition and integration costs.
We exclude the unrealized gains and losses from changes in the
fair value of derivatives used to reduce our exposure to certain
financial and commodity price risks. These derivatives generally
provide effective economic hedges but do not meet the criteria for
hedge accounting. As a result, the changes in fair value are
recorded in net income. As these amounts do not accurately reflect
the gains and losses that will be realized at settlement, we do not
consider them reflective of our underlying operations.
The following table identifies our non-GAAP measures against
their most directly comparable GAAP measures.
Comparable measure |
Original measure |
|
|
comparable earnings |
net income attributable to common shares |
comparable earnings per common share |
net income per common share |
comparable EBITDA |
segmented earnings |
comparable EBIT |
segmented earnings |
comparable funds generated from operations |
net cash provided by operations |
comparable distributable cash flow |
net cash provided by operations |
Comparable earnings and comparable earnings per common
share
Comparable earnings represents earnings or loss attributable to
common shareholders on a consolidated basis, adjusted for specific
items. Comparable earnings is comprised of segmented earnings,
interest expense, AFUDC, interest income and other, income taxes
and non-controlling interests, adjusted for specific items. See the
Consolidated results section for reconciliations to net income
attributable to common shares and net income per common share.
Comparable EBIT and comparable EBITDA
Comparable EBIT represents segmented earnings, adjusted for
specific items. We use comparable EBIT as a measure of our earnings
from ongoing operations as it is a useful indicator of our
performance and an effective tool for evaluating trends in each
segment. Comparable EBITDA is calculated the same way as comparable
EBIT but excludes the non-cash charges for depreciation and
amortization. See the Reconciliation of non-GAAP measures section
for a reconciliation to segmented earnings.
Funds generated from operations and comparable funds
generated from operations
Funds generated from operations reflects net cash provided by
operations before changes in operating working capital. We believe
it is a useful measure of our consolidated operating cash flow
because it does not include fluctuations from working capital
balances, which do not necessarily reflect underlying operations in
the same period, and is used to provide a consistent measure of the
cash generating performance of our assets. Comparable funds
generated from operations is adjusted for the cash impact of
specific items. See the Financial condition section for a
reconciliation to net cash provided by operations.
Comparable distributable cash flow and comparable
distributable cash flow per common share
We believe comparable distributable cash flow is a useful
supplemental measure of performance that defines cash available to
common shareholders before capital allocation. Comparable
distributable cash flow is defined as comparable funds generated
from operations less preferred share dividends, distributions to
non-controlling interests and non-recoverable maintenance capital
expenditures.
Maintenance capital expenditures are expenditures incurred to
maintain our operating capacity, asset integrity and reliability,
and include amounts attributable to our proportionate share of
maintenance capital expenditures on our equity investments. We
have the opportunity to recover effectively all of our pipeline
maintenance capital expenditures in Canadian Natural Gas Pipelines,
U.S. Natural Gas Pipelines and Liquids Pipelines through tolls.
Canadian natural gas pipelines maintenance capital expenditures are
reflected in rate bases, on which we earn a regulated return and
subsequently recover in tolls. Our U.S. natural gas pipelines can
recover maintenance capital expenditures through tolls under
current rate settlements, or have the ability to recover such
expenditures through tolls established in future rate cases or
settlements. Tolling arrangements in our liquids pipelines provide
for the recovery of maintenance capital expenditures. As such, in
2018 our presentation of comparable distributable cash flow and
comparable distributable cash flow per common share only includes a
reduction for non-recoverable maintenance capital expenditures in
their respective calculations. Comparative figures have been
adjusted to reflect this presentation.
See the Financial condition section for a reconciliation to net
cash provided by operations.
Consolidated results - third quarter 2018
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $, except per share amounts) |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
|
267 |
|
|
|
316 |
|
|
|
800 |
|
|
|
903 |
|
U.S. Natural Gas
Pipelines |
|
|
545 |
|
|
|
337 |
|
|
|
1,734 |
|
|
|
1,299 |
|
Mexico Natural Gas
Pipelines |
|
|
127 |
|
|
|
95 |
|
|
|
382 |
|
|
|
333 |
|
Liquids Pipelines |
|
|
316 |
|
|
|
203 |
|
|
|
1,047 |
|
|
|
681 |
|
Energy |
|
|
223 |
|
|
|
237 |
|
|
|
464 |
|
|
|
1,080 |
|
Corporate |
|
|
(68 |
) |
|
|
(29 |
) |
|
|
(77 |
) |
|
|
(102 |
) |
Total segmented
earnings |
|
|
1,410 |
|
|
|
1,159 |
|
|
|
4,350 |
|
|
|
4,194 |
|
Interest expense |
|
|
(577 |
) |
|
|
(504 |
) |
|
|
(1,662 |
) |
|
|
(1,528 |
) |
Allowance for funds
used during construction |
|
|
147 |
|
|
|
145 |
|
|
|
365 |
|
|
|
367 |
|
Interest
income and other |
|
|
168 |
|
|
|
84 |
|
|
|
139 |
|
|
|
193 |
|
Income before
income taxes |
|
|
1,148 |
|
|
|
884 |
|
|
|
3,192 |
|
|
|
3,226 |
|
Income
tax expense |
|
|
(120 |
) |
|
|
(188 |
) |
|
|
(394 |
) |
|
|
(781 |
) |
Net
income |
|
|
1,028 |
|
|
|
696 |
|
|
|
2,798 |
|
|
|
2,445 |
|
Net
income attributable to non-controlling interests |
|
|
(59 |
) |
|
|
(44 |
) |
|
|
(229 |
) |
|
|
(189 |
) |
Net income
attributable to controlling interests |
|
|
969 |
|
|
|
652 |
|
|
|
2,569 |
|
|
|
2,256 |
|
Preferred
share dividends |
|
|
(41 |
) |
|
|
(40 |
) |
|
|
(122 |
) |
|
|
(120 |
) |
Net income attributable to common shares |
|
|
928 |
|
|
|
612 |
|
|
|
2,447 |
|
|
|
2,136 |
|
Net income per
common share — basic |
|
$1.02 |
|
|
$0.70 |
|
|
$2.72 |
|
|
$2.46 |
|
— diluted |
|
$1.02 |
|
|
$0.70 |
|
|
$2.72 |
|
|
$2.45 |
|
Net income attributable to common shares increased by $316
million and $311 million, or $0.32 and $0.26 per common share, for
the three and nine months ended September 30, 2018 compared to
the same periods in 2017. Net income per common share in 2018
reflects the dilutive impact of common shares issued in 2017
and 2018 under our DRP and Corporate ATM program.
Net income in both periods 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.
2018 results included:
- after-tax income of $8 million and $3 million for the three and
nine months ended September 30, 2018 related to our U.S.
Northeast power marketing contracts primarily due to income
recognized on the sale of our retail contracts in first quarter and
earnings from the remaining contracts. These amounts have been
excluded from Energy's comparable earnings effective January 1,
2018 as we do not consider the wind-down of the remaining contracts
part of our underlying operations. The contract portfolio is
scheduled to run-off through to mid-2020.
2017 results included:
- a $12 million after-tax loss and a $243 million after-tax gain,
for the three and nine months ended September 30, 2017, related to
the monetization of our U.S. Northeast power generation assets.
This included a $440 million after-tax gain on the sale of TC
Hydro, an incremental loss of $183 million after tax recorded on
the sale of the thermal and wind package and $14 million
year-to-date of after-tax disposition costs and income tax
adjustments
- an after-tax charge of $30 million in third quarter and $69
million year-to-date for integration-related costs associated with
the acquisition of Columbia
- an after-tax charge of $8 million in third quarter and $19
million year-to-date related to the maintenance of Keystone XL
assets which was expensed in 2017 pending further advancement of
the project. In 2018, Keystone XL expenditures are being
capitalized
- a $7 million income tax recovery in first quarter related to
the realized loss on a third-party sale of Keystone XL project
assets.
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
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $, except per share amounts) |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
Net income
attributable to common shares |
|
|
928 |
|
|
|
612 |
|
|
|
2,447 |
|
|
|
2,136 |
|
Specific items
(net of tax): |
|
|
|
|
|
|
|
|
U.S.
Northeast power marketing contracts |
|
|
(8 |
) |
|
|
— |
|
|
|
(3 |
) |
|
|
— |
|
Net
loss/(gain) on sales of U.S. Northeast power generation assets |
|
|
— |
|
|
|
12 |
|
|
|
— |
|
|
|
(243 |
) |
Integration and acquisition related costs – Columbia |
|
|
— |
|
|
|
30 |
|
|
|
— |
|
|
|
69 |
|
Keystone
XL asset costs |
|
|
— |
|
|
|
8 |
|
|
|
— |
|
|
|
19 |
|
Keystone
XL income tax recoveries |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(7 |
) |
Risk management activities1 |
|
|
(18 |
) |
|
|
(48 |
) |
|
|
90 |
|
|
|
(3 |
) |
Comparable earnings |
|
|
902 |
|
|
|
614 |
|
|
|
2,534 |
|
|
|
1,971 |
|
Net income per
common share — basic |
|
$1.02 |
|
$0.70 |
|
$2.72 |
|
|
$2.46 |
|
Specific items
(net of tax): |
|
|
|
|
|
|
|
|
U.S.
Northeast power marketing contracts |
|
|
(0.01 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Net
loss/(gain) on sales of U.S. Northeast power generation assets |
|
|
— |
|
|
|
0.01 |
|
|
|
— |
|
|
|
(0.28 |
) |
Integration and acquisition related costs – Columbia |
|
|
— |
|
|
|
0.03 |
|
|
|
— |
|
|
|
0.08 |
|
Keystone
XL asset costs |
|
|
— |
|
|
|
0.01 |
|
|
|
— |
|
|
|
0.02 |
|
Keystone
XL income tax recoveries |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(0.01 |
) |
Risk management activities |
|
|
(0.01 |
) |
|
|
(0.05 |
) |
|
|
0.10 |
|
|
|
— |
|
Comparable earnings per common share |
|
$1.00 |
|
|
$0.70 |
|
$2.82 |
|
|
$2.27 |
|
1 |
|
Risk management
activities |
|
three months ended
September 30 |
|
nine months ended
September 30 |
|
|
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Power |
|
— |
|
|
1 |
|
|
3 |
|
|
5 |
|
|
|
U.S. Power |
|
31 |
|
|
59 |
|
|
(31 |
) |
|
(97 |
) |
|
|
Liquids marketing |
|
(65 |
) |
|
(19 |
) |
|
(10 |
) |
|
(15 |
) |
|
|
Natural Gas Storage |
|
— |
|
|
4 |
|
|
(6 |
) |
|
5 |
|
|
|
Interest rate |
|
— |
|
|
(1 |
) |
|
— |
|
|
(1 |
) |
|
|
Foreign exchange |
|
60 |
|
|
33 |
|
|
(79 |
) |
|
89 |
|
|
|
Income tax attributable to risk management activities |
|
(8 |
) |
|
(29 |
) |
|
33 |
|
|
17 |
|
|
|
Total unrealized gains/(losses) from
risk management activities |
|
18 |
|
|
48 |
|
|
(90 |
) |
|
3 |
|
Comparable earnings increased by $288 million or $0.30 per
common share for the three months ended September 30, 2018
compared to the same period in 2017 and was primarily the net
effect of:
- higher contribution from U.S. Natural Gas Pipelines mainly due
to increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service, additional contract sales on ANR and
Great Lakes and the amortization of net regulatory liabilities
recognized as a result of U.S. Tax Reform
- higher contribution from Liquids Pipelines primarily due to
earnings from intra-Alberta pipelines placed in service in the
second half of 2017, increased earnings from liquids marketing
activities, and higher volumes on the Keystone Pipeline System
- lower income tax expense primarily due to lower income tax
rates as a result of U.S. Tax Reform
- higher revenues from our Mexico operations as a result of
changes in timing of revenue recognition
- higher interest expense primarily as a result of long-term debt
and junior subordinated notes issuances, net of maturities, and
lower capitalized interest.
Comparable earnings increased by $563 million or $0.55 per
common share for the nine months ended September 30, 2018
compared to the same period in 2017 and was primarily the net
effect of:
- higher contribution from U.S. Natural Gas Pipelines mainly due
to increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service, additional contract sales on ANR and
Great Lakes and amortization of net regulatory liabilities
recognized as a result of U.S. Tax Reform
- higher contribution from Liquids Pipelines primarily due to
earnings from intra-Alberta pipelines placed in service in the
second half of 2017, increased earnings from liquids marketing
activities, and higher volumes on the Keystone Pipeline System
- lower income tax expense primarily due to lower income tax
rates as a result of U.S. Tax Reform
- higher revenues from our Mexico operations as a result of
changes in timing of revenue recognition
- increased Western Power results due to higher realized margins
on higher generation volumes
- lower earnings from U.S. Power mainly due to the sales of the
U.S. Northeast power generation assets in second quarter 2017
combined with the U.S. Northeast Power marketing results being
excluded from comparable earnings in 2018
- higher interest expense primarily as a result of long-term debt
and junior subordinated notes issuances, net of maturities, and
lower capitalized interest, partially offset by the repayment of
the Columbia acquisition bridge facilities in June 2017
- lower earnings from Bruce Power primarily due to lower volumes
resulting from increased outage days and lower earnings from
contracting activities
- lower Eastern Power results mainly due to the sale of our
Ontario solar assets in December 2017.
Comparable earnings per common share for the three and nine
months ended September 30, 2018 also reflect the
dilutive impact of common shares issued in 2017 and 2018 under
our DRP and our Corporate ATM program.
2018 FERC Actions
BACKGROUND
In December 2016, FERC issued a Notice of Inquiry (NOI) seeking
comment on how to address the issue of whether its existing
policies resulted in a ‘double recovery’ of income taxes in a
pass-through entity such as a master limited partnership (MLP).
This NOI was in response to a decision by the U.S. Court of Appeals
for the District of Columbia Circuit in July 2016 in United
Airlines, Inc., et al. v. FERC (the United case), directing
FERC to address the issue.
On December 22, 2017, U.S. Tax Reform was signed resulting in
significant changes to U.S. tax law including a decrease in the
U.S. federal corporate income tax rate from 35 per cent to 21 per
cent effective January 1, 2018. As a result of this change,
accumulated deferred income tax (ADIT) assets and liabilities
related to our U.S. businesses, including amounts related to our
proportionate share of assets held in TC PipeLines, LP, were
remeasured as at December 31, 2017 to reflect the new lower
U.S. federal corporate income tax rate. With respect to our U.S.
rate-regulated natural gas pipelines and storage entities, the
impact of this remeasurement was recorded as a net
regulatory liability.
On March 15, 2018, FERC issued (1) a Revised Policy
Statement to address the treatment of income taxes for
rate-making purposes for MLPs; (2) a Notice of Proposed Rulemaking
(NOPR) proposing natural gas pipeline and storage entities file a
one-time report to quantify the impact of the federal income tax
rate reduction and the impact of the Revised Policy Statement
on each entity's ROE assuming a single-issue adjustment to an
entity's rates; and (3) a NOI seeking comment on how FERC should
address changes related to ADIT and bonus depreciation. On July 18,
2018, FERC issued (1) an Order on Rehearing of the Revised Policy
Statement dismissing rehearing requests; and (2) a Final Rule
adopting and revising procedures from, and clarifying aspects of,
the NOPR (Final Rule), (collectively, the “2018 FERC
Actions”). The Final Rule became effective September 13, 2018,
and is subject to requests for further rehearing and
clarification. The impacts of the Final Rule relate to both
FERC-regulated natural gas pipeline and gas storage assets.
Discussion within this 2018 FERC Actions section describes the
impact to our natural gas pipelines, but also applies to our
FERC-regulated natural gas storage assets.
FERC Revised Policy Statement on Treatment of Income
Taxes for MLPs
The Revised Policy Statement changes FERC's long-standing policy
allowing income tax amounts to be included in rates subject to
cost-of-service rate regulation for pipelines owned by an MLP. The
Revised Policy Statement creates a presumption that entities whose
earnings are not taxed through a corporation should not be
permitted to recover an income tax allowance in their
regulated cost-of-service rates. On July 18, 2018, FERC dismissed
requests for rehearing and provided clarification of the Revised
Policy Statement. In this Order on Rehearing, FERC noted that an
MLP is not automatically precluded in a future proceeding from
arguing and providing evidentiary support that it is entitled to an
income tax allowance in its cost-of-service rates. Additionally,
FERC provided guidance with regard to ADIT for MLP pipelines and
other pass-through entities. FERC found that to the extent an
entity’s income tax allowance should be eliminated from rates, it
must also eliminate its existing ADIT balance from its rate
base. As a result, the Revised Policy Statement also precludes the
recognition and subsequent amortization of any related regulatory
assets or liabilities that might have otherwise impacted rates
charged to customers as a refund or collection of excess or
deficient deferred income tax assets or liabilities.
Final Rule on Tax Law Changes for Interstate
Natural Gas Pipelines and Storage Entities
The Final Rule established a schedule by which
interstate pipelines must either (i) file a new uncontested rate
settlement or (ii) file a one-time report, called FERC Form 501-G,
that quantifies the isolated rate impact of U.S. Tax Reform on
FERC-regulated pipelines and the impact of the Revised Policy
Statement on pipelines held by MLPs. A pipeline filing the FERC
Form 501-G must do so by established dates in fourth quarter 2018
and will have four options:
- make a limited Natural Gas Act (NGA) Section 4 filing to reduce
its rates by the reduction in its cost-of-service shown
in its FERC Form 501-G. For any pipeline electing this option,
FERC guarantees a three-year moratorium on NGA Section 5 rate
investigations if the pipeline’s FERC Form 501-G shows the
pipeline’s estimated ROE as being 12 per cent or less. Under
the Final Rule, and notwithstanding the Revised Policy Statement
discussed above, a pipeline organized as an MLP is not required to
eliminate its income tax allowance, but instead can reduce its
rates to reflect the reduction in the maximum corporate tax
rate. Alternatively, the MLP pipeline can eliminate its
tax allowance along with its ADIT used for rate-making
purposes. In situations where the ADIT balance is a liability,
this elimination would have the effect of increasing
the pipeline’s rate base for rate-making purposes
- commit to file either a pre-packaged uncontested rate
settlement or a general Section 4 rate case if it believes that
using the limited Section 4 option will not result in just and
reasonable rates. If the pipeline commits to file either by
December 31, 2018, FERC will not initiate a Section 5 investigation
of its rates prior to that date
- file a statement explaining its rationale for why it does not
believe the pipeline's rates must change; or
- take no other action. FERC will consider whether to initiate a
Section 5 investigation of any pipeline that has not submitted a
limited Section 4 rate filing or committed to file a general
Section 4 rate case.
NOI Regarding the Effect of U.S. Tax Reform on
Commission-Jurisdictional Rates
In the NOI, FERC sought comment on the effects of U.S.
Tax Reform to determine additional action, if any, required by FERC
related to ADIT balances that were reserved in anticipation
of being paid to or refunded by the Internal Revenue
Service, but which no longer accurately reflect the future income
tax liability or asset. The NOI also sought comment on
the elimination of bonus depreciation for regulated natural gas
pipelines and other effects of U.S. Tax Reform on regulated rates
or earnings.
As noted above, FERC's Order on Rehearing of the Revised Policy
Statement provided guidance with regard to ADIT for MLP pipelines,
finding that if an MLP pipeline's income tax allowance is
eliminated from its cost-of-service rates, then its
existing ADIT balance used for rate-making purposes should
also be eliminated from its rate base.
IMPACT OF 2018 FERC ACTIONS ON TRANSCANADA
Our U.S. natural gas pipelines are held through a number of
different ownership structures. We do not anticipate that
the earnings and cash flows from our directly-held U.S. natural gas
pipelines, including ANR, Columbia Gas and Columbia Gulf, will be
materially impacted by the Revised Policy Statement as a
significant proportion of their overall revenues are earned under
non-recourse rates. Columbia Gas is required under existing
settlements to adjust certain of its recourse rates for the
decrease in the U.S. federal corporate income tax rate enacted
December 22, 2017, with the changes implemented January 1, 2018. As
ANR, Columbia Gas, Columbia Gulf and other wholly-owned regulated
assets undergo future rate proceedings, future rates may be
impacted prospectively as a result of U.S. Tax Reform, but the
impact is expected to be largely mitigated by lower
corporate income tax rates. Therefore, the impact on earnings and
cash flows resulting from the 2018 FERC Actions on our U.S. natural
gas pipelines held outside of TC PipeLines, LP is expected to be
limited in comparison to pre-U.S. Tax Reform.
The following is an update on our filings outside of TC
Pipelines, LP, in response to the Final Rule subsequent to
September 30, 2018:
- Millennium Pipeline filed its Form 501-G October 11, 2018
- ANR, ANR Storage, Columbia Gas, Columbia Gulf and Crossroads
are scheduled to file their respective Form 501-Gs on December 6,
2018 unless new uncontested rate settlements are filed
- Hardy Storage and Blue Lake Storage have reached rate
settlements in principle. We expect to file the settlement
agreements with FERC in fourth quarter 2018. As outlined in 2018
FERC Actions, pipeline and storage assets that file an uncontested
settlement will be relieved of their obligations to file a Form
501-G.
The Revised Policy Statement also prohibits an income tax
allowance for liquids pipelines held in MLP structures. We do not
expect an impact on our U.S. liquids pipelines as they
are not held in MLP form.
Financing
In March 2018, as a result of the initially proposed 2018 FERC
Actions, further drop downs of assets into TC PipeLines, LP were
considered to no longer be a viable funding lever. In addition, the
TC PipeLines, LP ATM program ceased to be utilized. Pursuant
to the 2018 FERC Actions issued on July 18, 2018, it is yet to be
determined if and when in the future these might be
restored as competitive financing options. Regardless,
we believe we have the financial capacity to fund our existing
capital program through predictable and growing cash flow generated
from operations, access to capital markets including through our
Corporate ATM program and our DRP, portfolio management, cash on
hand and substantial committed credit facilities.
Impact of 2018 FERC Actions on TC PipeLines,
LP
On October 16, 2018, GTN filed with FERC an uncontested settlement
with its customers to address the changes proposed by the 2018 FERC
Actions via an amendment to its prior settlement in 2015 (“2018 GTN
Settlement”). Among the terms of the latest settlement, GTN has
agreed to (i) a refund of US$10 million to its firm customers in
2018, (ii) a reduction to its existing maximum system reservation
rates by 10 per cent effective January 1, 2019, and (iii) an
additional 6.6 per cent reduction effective January 1, 2020 through
December 31, 2021. GTN and its customers have also agreed upon a
moratorium on further rate changes prior to January 1, 2022. The
uncontested settlement, subject to approval by the FERC, will
relieve GTN of its obligation to file a Form 501-G.
The following is an update on other TC PipeLines, LP filings in
response to the Final Rule subsequent to September 30, 2018:
- PNGTS filed its Form 501-G with FERC along with an explanation
why no rate change is needed
- North Baja elected to make a limited NGA Section 4 filing and
reduce its recourse rates by approximately 11 per cent, which is
the percentage reduction in the cost of service per the FERC Form
501-G
- Iroquois requested a waiver of its requirement to file a Form
501-G from FERC based on its existing moratorium precluding rate
changes prior to September 2020
- Bison is scheduled to file its response by November 8, 2018 and
Northern Border, Great Lakes and Tuscarora are scheduled to file by
December 6, 2018.
Following the 2018 GTN Settlement, TC PipeLines, LP’s earnings,
cash flows and financial position are less adversely impacted by
the 2018 FERC Actions than initially expected. A number of
uncertainties still exist with respect to the variability of
outcomes around the ultimate resolution of the issues arising from
the 2018 FERC Actions, but any additional impact in 2018 is
expected to be limited for TC PipeLines, LP while subsequent
periods could be more significantly affected. Mitigating this
impact, approximately half of TC PipeLines, LP’s revenues,
including those of equity investments, are earned under
non-recourse rates which are not expected to be impacted by the
2018 FERC Actions. Furthermore, as our ownership in TC PipeLines,
LP is approximately 25 per cent, the impact of the 2018 FERC
Actions related to TC PipeLines, LP is not expected to be
significant to TransCanada's consolidated earnings or cash
flows.
Individual pipelines owned by TC PipeLines, LP do not currently
have a requirement to file for new rates until 2022, however, that
timing may be accelerated by the Final Rule, except where moratoria
exist. As noted above, the change in the Final Rule to allow MLPs
to remove the ADIT liability from rate base, thus increasing
rate base in general, is expected to further mitigate the loss of
the tax allowance in cost-of-service based rates.
As a result of the 2018 FERC Actions initially proposed in March
2018, and in order to retain cash in anticipation of a possible
reduction of revenues, TC PipeLines, LP reduced its quarterly
distribution to common unitholders by 35 per cent to US$0.65 per
unit beginning with its first quarter 2018 distribution.
Impairment Considerations
We review plant, property and equipment and equity investments for
impairment whenever events or changes in circumstances indicate the
carrying value of the asset may not be recoverable.
Goodwill is tested for impairment on an annual basis, or more
frequently if events or changes in circumstance indicate that it
might be impaired. We can initially make this assessment based on
qualitative factors. If we conclude that it is not more likely than
not that the fair value of the reporting unit is less than its
carrying value, then an impairment test is not performed.
We continue to monitor developments following the Final Rule on
the 2018 FERC Actions. We will incorporate results to date, future
filings for individual pipelines, as well as FERC responses to
others in the industry into our annual goodwill impairment tests as
well as our normal review of plant, property and equipment and
equity investments for recoverability.
As at September 30, 2018, the goodwill balances related to Great
Lakes and Tuscarora are US$573 million and US$82 million
(December 31, 2017 – US$573 million and US$82 million),
respectively. At December 31, 2017, the estimated fair value of
Great Lakes exceeded its carrying value by less than 10 per cent.
There is a risk that the goodwill balances related to both of these
assets could be negatively impacted by the FERC developments, once
finalized, or by other changes in management's estimates of fair
value resulting in a goodwill impairment charge.
U.S. Tax Reform
Pursuant to the enactment of U.S. Tax Reform, we recorded net
regulatory liabilities and a corresponding reduction in net
deferred income tax liabilities in the amount of $1,686 million at
December 31, 2017 related to our U.S. natural gas pipelines subject
to RRA. Amounts recorded to adjust income taxes remain provisional
as our interpretation, assessment and presentation of the impact of
U.S. Tax Reform may be further clarified with additional guidance
from tax authorities. Should additional guidance be provided by tax
authorities during the one-year measurement period permitted by the
SEC, we will review the provisional amounts and adjust as
appropriate.
Commencing January 1, 2018, we have amortized the net regulatory
liabilities using the Reverse South Georgia methodology. Under this
methodology, rate-regulated entities determine and immediately
begin recording amortization based on their composite depreciation
rates. For the three and nine months ended September 30, 2018,
amortization of the net regulatory liabilities in the amount of $12
million and $36 million was recorded and included in Revenues. Once
the final impact of the 2018 FERC Actions is determined there may
be prospective adjustments to our net regulatory liabilities.
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 $36 billion of
secured projects and approximately $20 billion of projects under
development. Our secured projects include commercially supported,
committed projects that are either under construction or that are
in or preparing to commence the permitting stage but are not yet
fully approved. Our projects under development are commercially
supported except where noted, but have greater uncertainty with
respect to timing and estimated project costs and are subject to
certain approvals.
Three years of maintenance capital expenditures for all of our
businesses are also included in the secured projects table.
Maintenance capital expenditures on our regulated Canadian and U.S.
natural gas pipelines 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 Liquids
Pipelines 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
September 30, 2018 |
(unaudited - billions of $) |
|
|
|
|
|
|
|
Canadian Natural Gas Pipelines |
|
|
|
|
|
|
Canadian Mainline |
|
2018-2021 |
|
0.2 |
|
|
0.1 |
|
NGTL System |
|
2018 |
|
0.6 |
|
|
0.5 |
|
|
|
2019 |
|
2.8 |
|
|
0.8 |
|
|
|
2020 |
|
1.7 |
|
|
0.1 |
|
|
|
2021 |
|
2.5 |
|
|
— |
|
|
|
2022 |
|
1.5 |
|
|
— |
|
Coastal GasLink2,3 |
|
2023 |
|
6.2 |
|
|
0.5 |
|
Regulated maintenance capital expenditures |
|
2018-2020 |
|
1.9 |
|
|
0.5 |
|
U.S. Natural Gas Pipelines |
|
|
|
|
|
|
Columbia Gas |
|
|
|
|
|
|
Mountaineer XPress |
|
2018 |
|
US 3.0 |
|
|
US 2.2 |
|
WB XPress |
|
2018 |
|
US 0.9 |
|
|
US 0.8 |
|
Modernization II |
|
2018-2020 |
|
US 1.1 |
|
|
US 0.4 |
|
Buckeye XPress |
|
2020 |
|
US 0.2 |
|
|
— |
|
Columbia Gulf |
|
|
|
|
|
|
Gulf XPress |
|
2018 |
|
US 0.6 |
|
|
US 0.5 |
|
Other |
|
2018-2020 |
|
US 0.3 |
|
|
US 0.2 |
|
Regulated maintenance capital expenditures |
|
2018-2020 |
|
US 1.9 |
|
|
US 0.4 |
|
Mexico Natural Gas Pipelines |
|
|
|
|
|
|
Sur de Texas4 |
|
2018 |
|
US 1.4 |
|
|
US 1.3 |
|
Villa de Reyes4 |
|
2019 |
|
US 0.8 |
|
|
US 0.6 |
|
Tula4 |
|
2020 |
|
US 0.7 |
|
|
US 0.6 |
|
Liquids Pipelines |
|
|
|
|
|
|
White Spruce |
|
2019 |
|
0.2 |
|
|
0.1 |
|
Recoverable maintenance capital expenditures |
|
2018-2020 |
|
0.1 |
|
|
— |
|
Energy |
|
|
|
|
|
|
Napanee |
|
2019 |
|
1.6 |
|
|
1.4 |
|
Bruce Power – life extension5 |
|
2018-2023 |
|
2.2 |
|
|
0.5 |
|
Other |
|
|
|
|
|
|
Non-recoverable maintenance capital
expenditures6 |
|
2018-2020 |
|
0.8 |
|
|
0.2 |
|
|
|
|
|
33.2 |
|
|
11.7 |
|
Foreign exchange impact on secured
projects7 |
|
|
|
3.2 |
|
|
2.0 |
|
Total secured projects
(Cdn$) |
|
|
|
36.4 |
|
|
13.7 |
|
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 excludes the reduction for the fourth
quarter 2018 elections made to date by certain LNG Canada
participants to reimburse approximately $0.4 billion of
pre-development costs pursuant to project agreements. Refer to the
Recent Developments section for additional details.
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. These payments will begin to
be recognized as revenue when the pipelines are placed in
service.
5 Reflects our proportionate share of the Unit 6 Major
Component Replacement program costs, expected to be in service in
2023 and amounts to be invested under the Asset Management program
through 2023.
6 Includes non-recoverable maintenance capital
expenditures from all segments and is primarily comprised of our
proportionate share of maintenance capital expenditures for Bruce
Power and other Energy amounts.
7 Reflects U.S./Canada foreign exchange rate of 1.29 at
September 30, 2018.
Projects under development
The costs provided in the table below reflect the most recent
estimates for each project as filed with the various regulatory
authorities or otherwise determined.
|
|
Estimated
project cost1 |
|
Carrying
value
at September 30, 2018 |
(unaudited - billions of $) |
|
|
|
|
|
Canadian Natural Gas Pipelines |
|
|
|
|
NGTL System – Merrick |
|
1.9 |
|
|
— |
|
Liquids Pipelines |
|
|
|
|
Heartland and TC Terminals2,3 |
|
0.9 |
|
|
0.1 |
|
Grand Rapids Phase 22,3 |
|
0.7 |
|
|
— |
|
Keystone XL4 |
|
US 8.0 |
|
|
US 0.4 |
|
Keystone Hardisty Terminal2,3,4 |
|
0.3 |
|
|
0.1 |
|
Energy |
|
|
|
|
Bruce Power – life extension5 |
|
6.0 |
|
|
— |
|
|
|
17.8 |
|
|
0.6 |
|
Foreign exchange impact on projects under
development6 |
|
2.3 |
|
|
0.1 |
|
Total projects under
development (Cdn$) |
|
20.1 |
|
|
0.7 |
|
1 Amounts reflect our proportionate share of joint
venture costs where applicable and 100 per cent of costs related to
wholly-owned assets.
2 Regulatory approvals have been obtained.
3 Additional commercial support is being pursued.
4 Carrying value reflects amount remaining after
impairment charge recorded in 2015, along with additional amounts
capitalized from January 1, 2018.
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 1.29 at
September 30, 2018.
Outlook
Consolidated comparable earnings
In fourth quarter 2018, we expect continued strong performance
across our business segments consistent with the results reported
in the first nine months of 2018. Our overall comparable
earnings outlook for 2018 has increased compared to what was
included in the 2017 Annual Report primarily due to the net effect
of:
- improved earnings from additional contract sales in U.S.
Natural Gas Pipelines
- higher contracted and uncontracted volumes on the Keystone
Pipeline System as well as higher contributions from liquids
marketing activities
- increased revenues in Mexico Natural Gas Pipelines
- increased benefit from and better visibility into the impacts
of U.S. Tax Reform
- the sale of our 62 per cent share of the Cartier Wind power
facilities.
The 2018 FERC Actions are not anticipated to have a significant
impact on our earnings or cash flows in 2018. Refer to the 2018
FERC Actions section for additional details.
Consolidated capital spending
We expect to spend approximately $10.5 billion in 2018 on growth
projects, maintenance capital expenditures and contributions to
equity investments. The increase from the amount included in the
2017 Annual Report primarily reflects incremental spending required
to complete construction of our secured projects capital program in
2018, as well as the capitalization of costs to further advance our
projects under development.
Canadian Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
NGTL System |
|
302 |
|
|
256 |
|
|
884 |
|
|
722 |
|
Canadian Mainline |
|
195 |
|
|
263 |
|
|
592 |
|
|
774 |
|
Other1 |
|
25 |
|
|
25 |
|
|
85 |
|
|
79 |
|
Comparable EBITDA |
|
522 |
|
|
544 |
|
|
1,561 |
|
|
1,575 |
|
Depreciation and amortization |
|
(255 |
) |
|
(228 |
) |
|
(761 |
) |
|
(672 |
) |
Comparable EBIT and segmented
earnings |
|
267 |
|
|
316 |
|
|
800 |
|
|
903 |
|
1 Includes results from Foothills, Ventures LP, Great
Lakes Canada, and our share of equity income from our investment in
TQM as well as general and administrative and business development
costs related to our Canadian Natural Gas Pipelines.
Canadian Natural Gas Pipelines segmented earnings decreased by
$49 million and $103 million for the three and nine months ended
September 30, 2018 compared to the same periods in 2017 and
are equivalent to comparable EBIT.
Net income and comparable EBITDA for our rate-regulated Canadian
natural gas pipelines are generally affected by our approved ROE,
our investment base, our level of deemed common equity and
incentive earnings or losses. Changes in depreciation, financial
charges and income taxes also impact comparable EBITDA but do not
have a significant impact on net income as they are almost entirely
recovered in revenues on a flow-through basis.
NET INCOME AND AVERAGE INVESTMENT BASE
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Net Income |
|
|
|
|
|
|
|
|
NGTL System |
|
101 |
|
|
92 |
|
|
289 |
|
|
261 |
|
Canadian Mainline |
|
40 |
|
|
49 |
|
|
121 |
|
|
149 |
|
Average investment base |
|
|
|
|
|
|
|
|
NGTL System |
|
|
|
|
|
9,419 |
|
|
8,210 |
|
Canadian Mainline |
|
|
|
|
|
3,855 |
|
|
4,165 |
|
Net income for the NGTL System increased by $9 million and $28
million for the three and nine months ended September 30, 2018
compared to the same periods in 2017 mainly due to a higher average
investment base resulting from continued system expansions,
partially offset by lower OM&A incentive earnings. On June 19,
2018, the NEB approved NGTL's 2018-2019 Revenue Requirement
Settlement Application (the 2018-2019 Settlement). This settlement,
which is effective from January 1, 2018 to December 31, 2019,
includes an ROE of 10.1 per cent on 40 per cent deemed equity, a
mechanism for sharing variances above and below a fixed annual
OM&A amount, flow-through treatment of all other costs and an
increase in depreciation rates. See the Recent developments section
for additional details.
Net income for the Canadian Mainline decreased by $9 million and
$28 million for the three and nine months ended September 30,
2018 compared to the same periods in 2017 primarily due to
incentive earnings recorded in 2017. Incentive earnings have not
been recognized in 2018 pending an NEB decision on the 2018-2020
Tolls Review. As a result of the pending decision, the Canadian
Mainline earnings to date reflect the last approved ROE of 10.1 per
cent on 40 per cent deemed equity.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $27 million and $89
million for the three and nine months ended September 30, 2018
compared to the same periods in 2017 mainly due to NGTL System
facilities that were placed in service and an increase in the
approved depreciation rates in the 2018-2019 Settlement.
U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of US$, unless noted otherwise) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Columbia Gas |
|
204 |
|
|
125 |
|
|
637 |
|
|
446 |
|
ANR |
|
111 |
|
|
86 |
|
|
370 |
|
|
301 |
|
TC PipeLines,
LP1,2,3 |
|
30 |
|
|
28 |
|
|
102 |
|
|
87 |
|
Great
Lakes4 |
|
18 |
|
|
9 |
|
|
74 |
|
|
49 |
|
Midstream |
|
42 |
|
|
27 |
|
|
101 |
|
|
70 |
|
Columbia Gulf |
|
34 |
|
|
16 |
|
|
90 |
|
|
55 |
|
Other U.S.
pipelines3,5 |
|
19 |
|
|
14 |
|
|
50 |
|
|
64 |
|
Non-controlling
interests6 |
|
89 |
|
|
80 |
|
|
304 |
|
|
266 |
|
Comparable EBITDA |
|
547 |
|
|
385 |
|
|
1,728 |
|
|
1,338 |
|
Depreciation and amortization |
|
(130 |
) |
|
(116 |
) |
|
(380 |
) |
|
(340 |
) |
Comparable
EBIT |
|
417 |
|
|
269 |
|
|
1,348 |
|
|
998 |
|
Foreign
exchange impact |
|
128 |
|
|
68 |
|
|
386 |
|
|
311 |
|
Comparable
EBIT (Cdn$) |
|
545 |
|
|
337 |
|
|
1,734 |
|
|
1,309 |
|
Specific item: |
|
|
|
|
|
|
|
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
— |
|
|
— |
|
|
(10 |
) |
Segmented earnings (Cdn$) |
|
545 |
|
|
337 |
|
|
1,734 |
|
|
1,299 |
|
1 Results reflect our earnings from TC PipeLines,
LP’s ownership interests in GTN, Great Lakes, Iroquois, Northern
Border, Bison, PNGTS, North Baja and Tuscarora, as well as general
and administrative costs related to TC PipeLines, LP.
2 TC PipeLines, LP periodically conducts ATM equity
issuances which decrease our ownership in TC PipeLines, LP. For the
three months ended September 30, 2018, our ownership interest
in TC PipeLines, LP was 25.5 per cent compared to 26.0 per cent for
the same period in 2017. Our ownership interest for the nine months
ended September 30, 2018, was 25.5 per cent compared to a
range of 26.5 to 26.0 per cent for the same period in 2017.
3 TC PipeLines, LP acquired 49.34 per cent of our 50 per
cent interest in Iroquois and our remaining 11.81 per cent interest
in PNGTS on June 1, 2017.
4 Results reflect our 53.55 per cent direct interest in
Great Lakes. The remaining 46.45 per cent is held by TC PipeLines,
LP.
5 Results reflect earnings from our direct ownership
interests in Crossroads, as well as Iroquois and PNGTS until June
1, 2017, and 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.
6 Results reflect earnings attributable to portions of
TC PipeLines, LP, PNGTS (until June 1, 2017) and CPPL (until
February 17, 2017) that we do not own.
U.S. Natural Gas Pipelines segmented earnings increased by $208
million and $435 million for the three and nine months ended
September 30, 2018 compared to the same periods in 2017.
Segmented earnings for the nine months ended September 30,
2017 included a $10 million pre-tax charge for integration and
acquisition related costs associated with the Columbia acquisition.
This amount has been excluded from our calculation of comparable
EBIT. A weaker U.S. dollar in 2018 had a negative impact on the
Canadian dollar equivalent segmented earnings from our U.S.
operations compared to the same period in 2017, although the U.S.
dollar was stronger in third quarter 2018 compared to the same
period in 2017.
Earnings from our U.S. Natural Gas Pipelines operations are
generally affected by contracted volume levels, volumes delivered
and the rates charged as well as by the cost of providing services.
Columbia Gas and ANR results are also affected by the contracting
and pricing of their storage capacity and commodity sales.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by
US$162 million and US$390 million for the three and nine months
ended September 30, 2018 compared to the same periods in
2017. This was primarily the net effect of:
- increased earnings from Columbia Gas and Columbia Gulf growth
projects placed in service, additional contract sales on ANR and
Great Lakes and improved commodity prices and throughput volumes in
Midstream
- increased earnings due to the amortization of the net
regulatory liabilities recognized in 2017, partially offset by a
reduction in certain rates on Columbia Gas, as a result of U.S. Tax
Reform
- a US$10 million refund from GTN to its recourse rate customers
as per the 2018 GTN Settlement. Refer to the 2018 FERC Actions
section for additional details.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$14 million and US$40
million for the three and nine months ended September 30, 2018
compared to the same periods in 2017 mainly due to new projects
placed in service.
Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of US$, unless noted
otherwise) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Topolobampo |
|
42 |
|
|
39 |
|
|
128 |
|
|
119 |
|
Tamazunchale |
|
33 |
|
|
29 |
|
|
96 |
|
|
85 |
|
Mazatlán |
|
19 |
|
|
16 |
|
|
58 |
|
|
49 |
|
Guadalajara |
|
18 |
|
|
17 |
|
|
53 |
|
|
51 |
|
Sur de Texas1 |
|
4 |
|
|
3 |
|
|
14 |
|
|
14 |
|
Other |
|
— |
|
|
(10 |
) |
|
4 |
|
|
(10 |
) |
Comparable EBITDA |
|
116 |
|
|
94 |
|
|
353 |
|
|
308 |
|
Depreciation and amortization |
|
(19 |
) |
|
(18 |
) |
|
(56 |
) |
|
(54 |
) |
Comparable EBIT |
|
97 |
|
|
76 |
|
|
297 |
|
|
254 |
|
Foreign exchange impact |
|
30 |
|
|
19 |
|
|
85 |
|
|
79 |
|
Comparable EBIT and segmented
earnings (Cdn$) |
|
127 |
|
|
95 |
|
|
382 |
|
|
333 |
|
1 Represents equity income from our 60 per cent
interest.
Mexico Natural Gas Pipelines segmented earnings
increased by $32 million and $49 million for the three and nine
months ended September 30, 2018 compared to the same periods
in 2017 and are equivalent to comparable EBIT. Earnings from our
Mexico operations are underpinned by long-term, stable, primarily
U.S. dollar-denominated revenue contracts, and are affected by the
cost of providing service. A weaker U.S. dollar in the first nine
months of 2018 had a negative impact on Canadian dollar equivalent
segmented earnings from our Mexico operations compared to the same
period in 2017, although the U.S. dollar was stronger in third
quarter 2018 compared to the same period in 2017.
Comparable EBITDA for Mexico Natural Gas
Pipelines increased by US$22 million and US$45 million for the
three and nine months ended September 30, 2018 compared to the
same periods in 2017 as a result of:
- higher revenues from operations as a result of changes in
timing of revenue recognition
- the impairment of our equity investment in TransGas in third
quarter 2017.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization remained largely consistent for the
three and nine months ended September 30, 2018 compared to the
same periods in 2017.
Liquids Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Keystone Pipeline System |
|
350 |
|
|
302 |
|
|
1,042 |
|
|
937 |
|
Intra-Alberta pipelines |
|
46 |
|
|
4 |
|
|
122 |
|
|
4 |
|
Liquids marketing and other |
|
71 |
|
|
(3 |
) |
|
147 |
|
|
6 |
|
Comparable EBITDA |
|
467 |
|
|
303 |
|
|
1,311 |
|
|
947 |
|
Depreciation and amortization |
|
(86 |
) |
|
(71 |
) |
|
(254 |
) |
|
(228 |
) |
Comparable EBIT |
|
381 |
|
|
232 |
|
|
1,057 |
|
|
719 |
|
Specific items: |
|
|
|
|
|
|
|
|
Keystone XL asset costs |
|
— |
|
|
(10 |
) |
|
— |
|
|
(23 |
) |
Risk management activities |
|
(65 |
) |
|
(19 |
) |
|
(10 |
) |
|
(15 |
) |
Segmented earnings |
|
316 |
|
|
203 |
|
|
1,047 |
|
|
681 |
|
|
|
|
|
|
|
|
|
|
Comparable EBIT denominated as follows: |
|
|
|
|
|
|
|
|
Canadian dollars |
|
96 |
|
|
63 |
|
|
278 |
|
|
175 |
|
U.S. dollars |
|
218 |
|
|
135 |
|
|
605 |
|
|
416 |
|
Foreign exchange impact |
|
67 |
|
|
34 |
|
|
174 |
|
|
128 |
|
|
|
381 |
|
|
232 |
|
|
1,057 |
|
|
719 |
|
Liquids Pipelines segmented earnings increased by $113 million
and $366 million for the three and nine months ended
September 30, 2018 compared to the same periods in 2017 and
included the following specific items:
- pre-tax charges related to the maintenance of Keystone XL
assets which were expensed in 2017 pending further advancement of
the project. In 2018, Keystone XL expenditures are being
capitalized
- unrealized losses from changes in the fair value of derivatives
related to our liquids marketing business.
Liquids Pipelines earnings are generated primarily by providing
pipeline capacity to shippers for fixed monthly payments that are
not linked to actual throughput volumes. The Keystone Pipeline
System also offers uncontracted capacity to the market on a spot
basis which provides opportunities to generate incremental
earnings. Our liquids marketing business provides customers with a
variety of crude oil marketing services including transportation,
storage, and crude oil supply, primarily transacted through the
purchase and sale of crude oil.
Comparable EBITDA for Liquids Pipelines increased by $164
million and $364 million for the three and nine months ended
September 30, 2018 compared to the same periods in 2017 and
was the net effect of:
- contributions from intra-Alberta pipelines, Grand Rapids and
Northern Courier, which began operations in the second half of
2017
- a higher contribution from liquids marketing activities
- higher contracted and uncontracted volumes on the Keystone
Pipeline System
- foreign exchange impact on the Canadian dollar equivalent
earnings from our U.S. operations.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $15 million and $26
million for the three and nine months ended September 30, 2018
compared to the same periods in 2017 as a result of new facilities
being placed in service.
Energy
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
most directly comparable GAAP measure).
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of Canadian $, unless
noted otherwise) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Canadian Power |
|
|
|
|
|
|
|
|
Western Power |
|
37 |
|
|
24 |
|
|
108 |
|
|
77 |
|
Eastern Power1 |
|
69 |
|
|
75 |
|
|
221 |
|
|
252 |
|
Bruce Power1 |
|
100 |
|
|
91 |
|
|
245 |
|
|
314 |
|
U.S. Power (US$)2 |
|
— |
|
|
22 |
|
|
— |
|
|
108 |
|
Foreign exchange impact on U.S. Power |
|
— |
|
|
7 |
|
|
— |
|
|
34 |
|
Natural Gas Storage and other |
|
4 |
|
|
8 |
|
|
21 |
|
|
40 |
|
Business Development |
|
(3 |
) |
|
(3 |
) |
|
(10 |
) |
|
(9 |
) |
Comparable EBITDA |
|
207 |
|
|
224 |
|
|
585 |
|
|
816 |
|
Depreciation and amortization |
|
(27 |
) |
|
(39 |
) |
|
(92 |
) |
|
(118 |
) |
Comparable EBIT |
|
180 |
|
|
185 |
|
|
493 |
|
|
698 |
|
Specific items: |
|
|
|
|
|
|
|
|
U.S. Northeast power marketing contracts |
|
12 |
|
|
— |
|
|
5 |
|
|
— |
|
Net (loss)/gain on sales of U.S. Northeast power
generation assets |
|
— |
|
|
(12 |
) |
|
— |
|
|
469 |
|
Risk management activities |
|
31 |
|
|
64 |
|
|
(34 |
) |
|
(87 |
) |
Segmented earnings |
|
223 |
|
|
237 |
|
|
464 |
|
|
1,080 |
|
1 Includes our share of equity income from our
investments in Portlands Energy and Bruce Power.
2 In second quarter 2017, we completed the sales of our
U.S. Northeast power generation assets.
Energy segmented earnings decreased by $14 million and $616
million for the three and nine months ended September 30, 2018
compared to the same periods in 2017 and included the following
specific items:
- a gain of $12 million and $5 million for the three and nine
months ended September 30, 2018 related to our U.S. Northeast
power marketing contracts. The year-to-date amount includes a gain
in first quarter 2018 on the sale of our retail contracts. These
amounts have been excluded from Energy's comparable earnings
effective January 1, 2018 as we do not consider the wind-down of
the remaining contracts part of our underlying operations. The
contract portfolio is scheduled to run-off through to mid-2020
- a net loss of $12 million and a net gain of $469 million before
tax for the three and nine months ended September 30, 2017
related to the monetization of our U.S. Northeast power generation
assets
- unrealized gains and losses from changes in the fair value of
derivatives used to reduce our exposure to certain commodity price
risks, as noted in the table below.
Risk management
activities |
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $, pre-tax) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Canadian Power |
|
— |
|
|
1 |
|
|
3 |
|
|
5 |
|
U.S. Power |
|
31 |
|
|
59 |
|
|
(31 |
) |
|
(97 |
) |
Natural Gas Storage and Other |
|
— |
|
|
4 |
|
|
(6 |
) |
|
5 |
|
Total unrealized gains/(losses) from
risk management activities |
|
31 |
|
|
64 |
|
|
(34 |
) |
|
(87 |
) |
Comparable EBITDA for Energy decreased by $17 million and $231
million for the three and nine months ended September 30, 2018
compared to the same periods in 2017 primarily due to the net
effect of:
- lower earnings from U.S. Power mainly due to the sales of the
U.S. Northeast power generation assets in second quarter 2017
- decreased Bruce Power year-to-date earnings primarily due to
lower volumes resulting from higher outage days and lower results
from contracting activities. Additional financial and operating
information on Bruce Power is provided below
- lower Eastern Power results due to the sale of our Ontario
solar assets in December 2017
- increased Western Power results due to higher realized margins
on higher generation volumes
- decreased Natural Gas Storage results primarily due to lower
realized natural gas storage price spreads.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization decreased by $12 million and $26
million for the three and nine months ended September 30, 2018
compared to the same periods in 2017 primarily due to the sale of
our Ontario solar assets in December 2017 as well as the cessation
of depreciation on our Cartier Wind power facilities upon
classification as held for sale on June 30, 2018.
BRUCE POWER
The following reflects our proportionate share of the components of
comparable EBITDA and comparable EBIT.
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $, unless noted otherwise) |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
Equity income included
in comparable EBITDA and EBIT comprised of: |
|
|
|
|
|
|
|
|
Revenues |
|
|
397 |
|
|
|
383 |
|
|
|
1,153 |
|
|
|
1,212 |
|
Operating
expenses |
|
|
(204 |
) |
|
|
(205 |
) |
|
|
(640 |
) |
|
|
(638 |
) |
Depreciation and other |
|
|
(93 |
) |
|
|
(87 |
) |
|
|
(268 |
) |
|
|
(260 |
) |
Comparable EBITDA and EBIT1 |
|
|
100 |
|
|
|
91 |
|
|
|
245 |
|
|
|
314 |
|
Bruce
Power – other information |
|
|
|
|
|
|
|
|
Plant
availability2 |
|
|
89 |
% |
|
|
86 |
% |
|
|
88 |
% |
|
|
89 |
% |
Planned outage
days |
|
|
30 |
|
|
|
81 |
|
|
|
180 |
|
|
|
178 |
|
Unplanned outage
days |
|
|
43 |
|
|
|
19 |
|
|
|
77 |
|
|
|
39 |
|
Sales volumes
(GWh)1 |
|
|
6,087 |
|
|
|
5,801 |
|
|
|
17,810 |
|
|
|
18,093 |
|
Realized
sales price per MWh3 |
|
$67 |
|
|
$67 |
|
|
$67 |
|
|
$67 |
|
1 Represents our 48.3 per cent (2017 - 48.4 per cent)
ownership interest in Bruce Power. Sales volumes include deemed
generation.
2 The percentage of time the plant was available to
generate power, regardless of whether it was running.
3 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 outage work on Unit 1 and Unit 4 was completed in the
first half of 2018. Planned maintenance on Unit 8 began in
September 2018 and is scheduled to be completed in fourth quarter
2018. Planned maintenance is expected to begin on Unit 3 in fourth
quarter 2018 and continue into early 2019. The overall average
plant availability percentage in 2018 is expected to be in the high
80 per cent range.
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
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Comparable EBITDA and EBIT |
|
(8 |
) |
|
(4 |
) |
|
(25 |
) |
|
(20 |
) |
Specific items: |
|
|
|
|
|
|
|
|
Foreign exchange (loss)/gain – inter-affiliate
loan1 |
|
(60 |
) |
|
7 |
|
|
(52 |
) |
|
(1 |
) |
Integration and acquisition related costs –
Columbia |
|
— |
|
|
(32 |
) |
|
— |
|
|
(81 |
) |
Segmented losses |
|
(68 |
) |
|
(29 |
) |
|
(77 |
) |
|
(102 |
) |
1 Reported in Income from equity investments in our
Corporate segment.
Corporate segmented losses increased by $39 million and
decreased by $25 million for the three and nine months ended
September 30, 2018 compared to the same periods in 2017. These
results included the following specific items that have been
excluded from comparable EBIT:
- foreign exchange losses and gains on a peso-denominated
inter-affiliate loan to the Sur de Texas project for our
proportionate share of the affiliate's project financing. There are
corresponding foreign exchange gains and losses included in
Interest income and other on the inter-affiliate loan receivable
which fully offset these amounts
- in 2017, integration-related costs associated with the
acquisition of Columbia.
OTHER INCOME STATEMENT ITEMS
Interest expense
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Interest on long-term debt and junior subordinated
notes |
|
|
|
|
|
|
|
|
Canadian dollar-denominated |
|
(142 |
) |
|
(130 |
) |
|
(407 |
) |
|
(356 |
) |
U.S. dollar-denominated |
|
(335 |
) |
|
(314 |
) |
|
(981 |
) |
|
(954 |
) |
Foreign exchange impact |
|
(103 |
) |
|
(79 |
) |
|
(283 |
) |
|
(293 |
) |
|
|
(580 |
) |
|
(523 |
) |
|
(1,671 |
) |
|
(1,603 |
) |
Other interest and amortization expense |
|
(30 |
) |
|
(29 |
) |
|
(80 |
) |
|
(74 |
) |
Capitalized interest |
|
33 |
|
|
49 |
|
|
89 |
|
|
150 |
|
Interest expense included in comparable
earnings |
|
(577 |
) |
|
(503 |
) |
|
(1,662 |
) |
|
(1,527 |
) |
Specific Item: |
|
|
|
|
|
|
|
|
Risk management activities |
|
— |
|
|
(1 |
) |
|
— |
|
|
(1 |
) |
Interest expense |
|
(577 |
) |
|
(504 |
) |
|
(1,662 |
) |
|
(1,528 |
) |
Interest expense increased by $73 million and $134 million for
the three and nine months ended September 30, 2018 compared to
the same periods in 2017 and primarily reflects the net effect
of:
- long-term debt and junior subordinated notes issuances, net of
maturities
- lower capitalized interest primarily due to the completion of
Grand Rapids and Northern Courier in the second half of 2017,
partially offset by ongoing construction at Napanee and the
recommencement of capitalization of Keystone XL costs in 2018
- final repayment of the Columbia acquisition bridge facilities
in June 2017 resulting in lower interest and debt amortization
expense
- foreign exchange impact on translation of U.S.
dollar-denominated interest.
Allowance for funds used during
construction
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Canadian dollar-denominated |
|
27 |
|
|
44 |
|
|
68 |
|
|
149 |
|
U.S. dollar-denominated |
|
91 |
|
|
81 |
|
|
230 |
|
|
168 |
|
Foreign exchange impact |
|
29 |
|
|
20 |
|
|
67 |
|
|
50 |
|
Allowance for funds used during
construction |
|
147 |
|
|
145 |
|
|
365 |
|
|
367 |
|
AFUDC increased by $2 million and decreased by $2 million for
the three and nine months ended September 30, 2018 compared to
the same periods in 2017.
The decrease in Canadian dollar-denominated AFUDC is primarily
due to the October 2017 decision not to proceed with the Energy
East pipeline project and completion of various expansion programs
in first quarter 2018.
The increase in U.S. dollar-denominated AFUDC is primarily due
to additional investment in and higher AFUDC rates on Columbia Gas
and Columbia Gulf growth projects and continued investment in
Mexico projects, partially offset by the commercial in-service of
Leach Xpress and Cameron Access in first quarter 2018.
Interest income and other
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Interest income and other included in comparable
earnings |
|
48 |
|
|
58 |
|
|
166 |
|
|
103 |
|
Specific items: |
|
|
|
|
|
|
|
|
Foreign exchange gain/(loss) – inter-affiliate
loan |
|
60 |
|
|
(7 |
) |
|
52 |
|
|
1 |
|
Risk management activities |
|
60 |
|
|
33 |
|
|
(79 |
) |
|
89 |
|
Interest income and
other |
|
168 |
|
|
84 |
|
|
139 |
|
|
193 |
|
Interest income and other increased by $84
million for the three months ended September 30, 2018 compared
to the same period in 2017 and was primarily the net effect of:
- higher interest income and a $60 million foreign exchange gain
compared to a $7 million loss in 2017 related to an inter-affiliate
loan receivable from the Sur de Texas joint venture. The
corresponding interest expense and foreign exchange loss are
reflected in Income from equity investments in the Mexico Natural
Gas Pipelines and Corporate segments, respectively. The offsetting
currency-related gain and loss amounts are excluded from comparable
earnings
- higher unrealized gains on risk management activities in 2018
compared to 2017. These amounts have been excluded from comparable
earnings
- realized losses in 2018 compared to realized gains in 2017 on
derivatives used to manage our net exposure to foreign exchange
rate fluctuations on U.S. dollar-denominated income
- income of $10 million recognized in 2017 on termination of the
PRGT project, related to the recovery of carrying costs.
Interest income and other decreased by $54 million for the nine
months ended September 30, 2018 compared to the same period in
2017 and was primarily the net effect of:
- higher interest income and a $52 million 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 are reflected in Income from equity investments in
the Mexico Natural Gas Pipelines and Corporate segments,
respectively. The offsetting currency-related gain and loss amounts
are excluded from comparable earnings
- unrealized losses on risk management activities in 2018
compared to unrealized gains in 2017. These amounts have been
excluded from comparable earnings
- income of $20 million related to reimbursement of Coastal
GasLink (CGL) project costs in 2017
- income of $10 million recognized in 2017, on termination of the
PRGT project, related to the recovery of carrying costs.
Income tax expense
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Income tax expense included in comparable
earnings |
|
(108 |
) |
|
(163 |
) |
|
(425 |
) |
|
(605 |
) |
Specific items: |
|
|
|
|
|
|
|
|
U.S. Northeast power marketing contracts |
|
(4 |
) |
|
— |
|
|
(2 |
) |
|
— |
|
Integration and acquisition related costs –
Columbia |
|
— |
|
|
2 |
|
|
— |
|
|
22 |
|
Keystone XL asset costs |
|
— |
|
|
2 |
|
|
— |
|
|
4 |
|
Net gain on sales of U.S. Northeast power generation
assets |
|
— |
|
|
— |
|
|
— |
|
|
(226 |
) |
Keystone XL income tax recoveries |
|
— |
|
|
— |
|
|
— |
|
|
7 |
|
Risk management activities |
|
(8 |
) |
|
(29 |
) |
|
33 |
|
|
17 |
|
Income tax expense |
|
(120 |
) |
|
(188 |
) |
|
(394 |
) |
|
(781 |
) |
Income tax expense included in comparable earnings decreased by
$55 million and $180 million for the three and nine months ended
September 30, 2018 compared to the same periods in
2017. This was primarily due to lower income tax rates as a
result of U.S. Tax Reform and lower flow-through income taxes in
Canadian rate-regulated pipelines, partially offset by higher
comparable earnings before income taxes.
Net income attributable to non-controlling
interests
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Net income attributable to
non-controlling interests |
|
(59 |
) |
|
(44 |
) |
|
(229 |
) |
|
(189 |
) |
Net income attributable to non-controlling interests increased
by $15 million and $40 million for the three and nine months ended
September 30, 2018 compared to the same periods in 2017
primarily due to higher earnings in TC PipeLines, LP. Higher net
income attributable to non-controlling interests for the nine
months ended September 30, 2018 was partially offset by our
acquisition of the remaining outstanding publicly held common units
of CPPL in February 2017.
Preferred share dividends
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Preferred share
dividends |
|
(41 |
) |
|
(40 |
) |
|
(122 |
) |
|
(120 |
) |
Preferred share dividends remained largely consistent for the
three and nine months ended September 30, 2018 compared to the
same periods in 2017.
Recent developments
CANADIAN NATURAL GAS PIPELINES
Coastal GasLink Pipeline Project
On October 2, 2018, we announced that we will proceed with
construction of the CGL pipeline project following the LNG Canada
joint venture participants' announcement that they have reached a
positive FID to build the LNG Canada natural gas liquefaction
facility in Kitimat, B.C. CGL will provide the natural gas
supply to the LNG Canada facility and is underpinned by 25-year
TSAs (with additional renewal provisions) with the LNG Canada
participants. CGL is a 670 km (420 miles) pipeline with an initial
capacity of approximately 2.2 PJ/d (2.1 Bcf/d) with potential
expansion capacity up to 5.4PJ/d (5.0 Bcf/d). All necessary
regulatory permits have been received to allow us to proceed with
construction activities which are expected to begin in January
2019, with a planned in-service date in 2023. CGL has signed
project and community agreements with all 20 elected Indigenous
bands along the pipeline route, confirming strong support from
Indigenous communities across the province of B.C.
On July 30, 2018, an individual asked the NEB to consider
whether the CGL pipeline should be federally regulated by the NEB.
On October 22, 2018, the NEB advised that it would consider the
question of jurisdiction. In the same letter, the NEB set a process
to determine whether the individual who raised the question has
standing, and to decide on the standing of any other interested
parties. The process to consider the jurisdiction question is to be
determined and the permits to construct remain valid.
The capital cost estimate is $6.2 billion with the majority of
the construction spend occurring in 2020 and 2021. Subject to terms
and conditions, differences between the estimated capital cost and
final cost of the project will be recovered in future pipeline
tolls. As part of the CGL funding plan, we intend to explore
joint venture partners and project financing for the project.
The total capital cost includes pre-development costs to date of
approximately $470 million. In accordance with provisions in the
agreements with the LNG Canada joint venture participants, to date,
four parties have elected to reimburse us for their share of
pre-development costs, totaling $399 million of cost reimbursement,
with payments due by November 30, 2018.
NGTL System
2022 NGTL System Expansion Program
On October 31, 2018, we announced the NGTL 2022 Expansion Program
to meet capacity requirements for incremental firm receipt and
intra-basin delivery services to commence in November 2021 and
April 2022. This $1.5 billion expansion of the NGTL System consists
of approximately 197 km (122 miles) of new pipeline, three
compressor units, meter stations and associated facilities.
Applications for approvals to construct and operate the facilities
are expected to be filed with the NEB in second quarter 2019 and,
pending receipt of regulatory approvals, construction would start
as early as third quarter 2020.
2021 NGTL System Expansion Program
Application
On June 20, 2018, we filed an application with the NEB for approval
to construct and operate the 2021 Expansion Program. The program,
with an estimated capital cost of $2.3 billion, consists of
approximately 344 km (214 miles) of new pipeline, three compressors
and a control valve. The expansion is required to accept increasing
supply from the west side of the system and deliver gas to
increasing market demand on the east side of the system. The
anticipated in-service date for the expansion is the first half of
2021.
North Montney Project Approval
In July 2018, the NEB issued an amending order, following Federal
government approval of our application, to the existing North
Montney project approvals to remove the condition requiring a
positive FID for the Pacific Northwest LNG project prior to
commencement of construction.
The North Montney project consists of approximately 206 km (128
miles) of new pipeline, three compressor units and 14 meter
stations. The current estimated project cost has increased by $0.2
billion to $1.6 billion mainly due to construction schedule delays
and an increase in market-dependent construction costs.
The NEB directed NGTL to seek approval for a revised tolling
methodology for the project following a provisional period defined
as one year after the receipt of the Federal government decision,
or otherwise impose stand-alone tolling as a default. NGTL is
working with its shippers to address this requirement and is
confident an appropriate tolling mechanism can be achieved.
The first phase of the project is anticipated to be in service
by fourth quarter 2019 and the second phase by second quarter
2020.
Other Projects
Our 2019 capital program has increased by approximately $0.2
billion primarily due to higher construction costs related to the
Saddle West project.
On April 9, 2018, we announced that the Sundre Crossover project
was placed in service. The $100 million pipeline project increases
NGTL System capacity at our Alberta / B.C. export delivery point by
approximately 245 TJ/d (228 MMcf/d), enhancing connectivity to key
downstream markets in the Pacific Northwest and California.
On April 2, 2018, we announced that the Northwest Mainline
Loop-Boundary Lake project was placed in service. The $160 million
project added approximately 230 km (143 miles) of new pipeline
along with compression facilities and increased the NGTL System
capacity by approximately 535 TJ/d (500 MMcf/d).
On March 20, 2018, we announced the successful completion of an
open season for additional expansion capacity at the Empress /
McNeill Export Delivery Point for service expected to commence in
November 2021. The offering of 300 TJ/d (280 MMcf/d) was
oversubscribed, with an average awarded contract term of
approximately 22 years. The facilities and capital requirements for
the expansion are estimated to be approximately $0.1 billion.
NGTL 2018-2019 Revenue Requirement Settlement
Approval
On June 19, 2018, the NEB approved the 2018-2019 Settlement, as
filed, for final 2018 tolls. The 2018-2019 Settlement fixes ROE at
10.1 per cent on 40 per cent deemed equity and increases the
composite depreciation rate from 3.18 per cent to 3.45 per cent.
OM&A costs are fixed at $225 million for 2018 and $230 million
for 2019 with a 50/50 sharing mechanism for any variances between
the fixed amounts and actual OM&A costs. All other costs,
including pipeline integrity expenses and emissions costs, are
treated as flow-through expenses.
Canadian Mainline
Canadian Mainline 2018-2020 Toll Review
On October 9, 2018, we concluded the written hearing process for
the Canadian Mainline 2018-2020 toll review with the filing of our
reply evidence to the NEB. We have requested a decision by December
31, 2018.
Maple Compressor Expansion Project
On April 27, 2018, we received NEB approval to proceed with
construction of this approximate $110 million compressor unit
addition project. Work continues as planned to meet a November 1,
2019 in-service date.
U.S. NATURAL GAS PIPELINES
Nixon Ridge
On June 7, 2018, a natural gas pipeline rupture on Columbia Gas
occurred on Nixon Ridge in Marshall County, West
Virginia. Emergency response procedures were enacted and the
segment of impacted pipeline was isolated shortly thereafter. There
were no injuries involved with this incident and no material damage
to surrounding structures. The pipeline was placed back in
service on July 15, 2018. The preliminary investigation, as noted
in the PHMSA Proposed Safety Order, suggests that the rupture was a
result of land subsidence. The investigation remains ongoing and we
are fully cooperating with PHMSA to determine the root cause of the
incident. We do not expect this event to have a significant
impact on our financial results.
Cameron Access
The Cameron Access project, a Columbia Gulf project designed to
transport approximately 0.9 PJ/d (0.8 Bcf/d) of gas supply to the
Cameron LNG export terminal in Louisiana, was placed in service on
March 13, 2018.
WB XPress and Mountaineer XPress
The Western Build of the WB Xpress (WBX) project was placed into
service on October 5, 2018. The Eastern Build of WBX remains to be
completed, as planned, in fourth quarter 2018. In first quarter
2018, estimated project costs were revised upwards to US$0.9
billion for WBX and US$3.0 billion for MXP. These increases,
primarily in MXP, reflect the impact of delays of various
regulatory approvals from FERC and other agencies, increased
contractor construction costs due to unusually high demand for
construction resources in the region, and modifications to
contractor work plans to mitigate construction delays associated
with these impacts. Unusually high instances of inclement weather
throughout construction has placed continued cost and schedule
pressures on these projects.
U.S. Pipelines Rate Settlements
In February 2018, FERC approved the 2017 Great Lakes Rate
Settlement and the 2017 Northern Border Rate Settlement, both of
which were uncontested. The rates established under both of these
settlements are subject to change upon the final outcome of the
filings in response to the 2018 FERC Actions.
In October 2018, GTN filed with FERC an uncontested settlement
with its customers. Refer to the 2018 FERC Actions for additional
detail.
MEXICO NATURAL GAS PIPELINES
Topolobampo
On June 29, 2018, the Topolobampo pipeline was placed in service.
The 560 km (348 miles) pipeline provides capacity of 720 TJ/d (670
MMcf/d), receiving natural gas from upstream pipelines near El
Encino, in the state of Chihuahua, and delivering to points along
the pipeline route including our Mazatlán pipeline at El Oro, in
the state of Sinaloa. Under the force majeure terms of the TSA, we
began collecting and recognizing revenue from the original TSA
service commencement date of July 2016.
Sur de Texas
Offshore construction was completed in May 2018 and the project
continues to progress toward an anticipated in-service date at the
end of 2018. An amending agreement has been signed with the CFE
that recognizes force majeure events and the commencement of
payments of fixed capacity charges beginning October 31, 2018.
Tula and Villa de Reyes
The CFE has approved the recognition of force majeure events for
both of these pipelines, including the continuation of the payment
of fixed capacity charges to us that began in first quarter 2018.
Construction for the Villa de Reyes project is ongoing and is
anticipated to be in service by the second half of 2019.
LIQUIDS PIPELINES
Keystone XL
In December 2017, an appeal to Nebraska's Court of Appeals was
filed by intervenors after the Nebraska PSC issued an approval of
an alternative route for the Keystone XL project in November 2017.
In March 2018, the Nebraska Supreme Court, on its own motion,
agreed to bypass the Court of Appeals and directly hear the appeal
case against the PSC’s alternative route. Legal briefs on the
appeal were submitted in May 2018 and oral argument before the
Nebraska Supreme Court has been set for November 1, 2018. We expect
the Nebraska Supreme Court, as the final arbiter, could reach a
decision by first quarter 2019.
The Keystone XL Presidential Permit, issued in March 2017, has
been challenged in two separate lawsuits commenced in Montana.
Together with the U.S. Department of Justice (DOJ), we are actively
participating in these lawsuits to defend both the issuance of the
permit and the exhaustive environmental assessments that support
the U.S. President’s actions. Legal arguments addressing the merits
of these lawsuits were heard in May 2018 and we believe the court’s
decisions on certain elements of these legal challenges may be
issued by the end of 2018.
In May 2018, the U.S. Department of State (DOS) filed a notice
of its intent to prepare an environmental assessment for the
Keystone XL mainline alternative route in Nebraska. Public comments
were received in June 2018 and in July 2018 the DOS issued a draft
environmental assessment. However, on August 15, 2018, the U.S.
District Court in Montana issued a Partial Order requiring the DOJ
and the DOS (the Federal Defendants) to prepare a supplemental
environmental impact statement (SEIS) to the 2014 Final
Supplemental Environmental Impact Statement and a proposed schedule
for the completion of the SEIS. On September 4, 2018, the Federal
Defendants responded to this Partial Order by filing the required
schedule which reflected the issuance of the final SEIS in December
2018. On September 21, 2018, the DOS issued a draft SEIS which
concluded that implementation of the mainline alternative route
would have no significant direct, indirect or cumulative effect on
the quality of the natural or human environments, having
consideration for the mitigation plans proposed by TransCanada. The
draft SEIS is open for public comment for a period of 45 days. The
Federal Defendants also indicated that the U.S. Bureau of Land
Management and the U.S. Army Corps of Engineers would likely issue
decisions regarding their respective federal permitting activities
in first quarter 2019.
In September 2018, two U.S. Native American communities filed a
lawsuit in Montana challenging the Keystone XL Presidential Permit.
It is uncertain how and when this lawsuit will proceed.
The South Dakota Public Utilities Commission permit for the
Keystone XL project was issued in June 2010 and recertified in
January 2016. An appeal of that recertification was denied in
June 2017 and that decision was further appealed to the South
Dakota Supreme Court. On June 13, 2018, the Supreme Court dismissed
the appeal against the recertification of the Keystone XL project
finding that the lower court lacked jurisdiction to hear the case.
This decision is final as there can be no further appeals from this
decision by the Supreme Court.
White Spruce
In February 2018, the AER issued a permit for
the construction of the White Spruce pipeline. Construction has
commenced with an anticipated in-service date in second quarter
2019.
ENERGY
Cartier Wind
On October 24, 2018, we completed the sale of our interests in the
Cartier Wind power facilities in Québec to Innergex Renewable
Energy Inc. for gross proceeds of approximately $630 million before
closing adjustments resulting in an estimated gain of $170 million
($135 million after tax) to be recorded in fourth quarter 2018.
Bruce Power - Life Extension
On September 28, 2018, Bruce Power submitted its final cost and
schedule duration estimate (basis of estimate) for the Unit 6 Major
Component Replacement (MCR) program to the IESO. The IESO has up to
three months to review and verify the basis of estimate. As the
cost and schedule duration are both less than the thresholds
defined in the program's life extension and refurbishment
agreement, no further approvals from the IESO or the government are
required to proceed with the Unit 6 MCR outage in early 2020. The
Unit 6 MCR outage is expected to be completed in late 2023.
As a result of this filing, we have updated our project cost
estimates in our Capital Program tables to reflect our expected
investment of approximately $2.2 billion (in nominal dollars) in
Bruce Power's Unit 6 MCR program and ongoing Asset Management (AM)
program through 2023, and approximately $6.0 billion (in 2018
dollars) for the remaining five-unit MCR program and the AM program
beyond 2023. Future MCR investments will be subject to discrete
decisions for each unit with specified off-ramps available for
Bruce Power and the IESO.
Bruce Power's current contract price of approximately $68 per
MWh will be increased in April 2019 to reflect capital to be
invested under the Unit 6 MCR program and the AM program as well as
normal annual inflation adjustments.
Napanee
Construction continues on our 900 MW natural gas-fired power plant
at OPG's Lennox site in eastern Ontario in the town of Greater
Napanee. We expect our total investment in the Napanee facility
will be approximately $1.6 billion and commercial operations are
expected to begin in first quarter 2019. Costs have increased due
to delays in the construction schedule. Once in service, production
from the facility is fully contracted with the IESO for a 20-year
period.
Monetization of U.S. Northeast power marketing
business
On March 1, 2018, as part of the continued wind-down of our U.S.
Northeast power marketing contracts, we closed the sale of our U.S.
power retail contracts for proceeds of approximately US$23 million
and recognized income of US$10 million (US$7 million after
tax).
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 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 our predictable and growing cash flow from
operations, access to capital markets, including through our
Corporate ATM program and our DRP, portfolio management, cash on
hand and substantial committed credit facilities. Annually, in
fourth quarter, we extend and renew our credit facilities as
required. In light of the 2018 FERC Actions initially proposed in
March 2018, further drop downs of assets into TC PipeLines, LP were
considered to no longer be a viable funding lever. In addition, the
TC PipeLines, LP ATM program ceased to be utilized. Pursuant to the
2018 FERC Actions on July 18, 2018, it is yet to be determined
if and when in the future these might be restored as
competitive financing options. See the 2018 FERC Actions
section for further information.
At September 30, 2018, our current assets totaled $5.1
billion and current liabilities amounted to $11.0 billion, leaving
us with a working capital deficit of $5.9 billion compared to $5.2
billion at December 31, 2017. Our working capital deficit is
considered to be in the normal course of business and is managed
through:
- our ability to generate cash flow from operations
- our access to capital markets
- approximately $9.5 billion of unutilized, unsecured credit
facilities.
CASH PROVIDED BY OPERATING ACTIVITIES
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $, except per share amounts) |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
Net cash provided by
operations |
|
|
1,299 |
|
|
|
1,185 |
|
|
|
4,516 |
|
|
|
3,840 |
|
Increase in operating
working capital |
|
|
284 |
|
|
|
86 |
|
|
|
130 |
|
|
|
224 |
|
Funds generated from operations1 |
|
|
1,583 |
|
|
|
1,271 |
|
|
|
4,646 |
|
|
|
4,064 |
|
Specific items: |
|
|
|
|
|
|
|
|
U.S.
Northeast power marketing contracts |
|
|
(12 |
) |
|
|
— |
|
|
|
(5 |
) |
|
|
— |
|
Integration and acquisition related costs – Columbia |
|
|
— |
|
|
|
32 |
|
|
|
— |
|
|
|
84 |
|
Keystone
XL asset costs |
|
|
— |
|
|
|
10 |
|
|
|
— |
|
|
|
23 |
|
Net loss
on sales of U.S. Northeast power generation assets |
|
|
— |
|
|
|
3 |
|
|
|
— |
|
|
|
20 |
|
Comparable funds generated from
operations1 |
|
|
1,571 |
|
|
|
1,316 |
|
|
|
4,641 |
|
|
|
4,191 |
|
Dividends on preferred
shares |
|
|
(40 |
) |
|
|
(39 |
) |
|
|
(118 |
) |
|
|
(116 |
) |
Distributions paid to
non-controlling interests |
|
|
(57 |
) |
|
|
(66 |
) |
|
|
(174 |
) |
|
|
(215 |
) |
Non-recoverable maintenance capital expenditures2 |
|
|
(61 |
) |
|
|
(41 |
) |
|
|
(191 |
) |
|
|
(169 |
) |
Comparable
distributable cash flow1 |
|
|
1,413 |
|
|
|
1,170 |
|
|
|
4,158 |
|
|
|
3,691 |
|
Comparable distributable cash flow per common
share1 |
|
|
$1.56 |
|
|
|
$1.34 |
|
|
|
$4.63 |
|
|
|
$4.24 |
|
1 See the Non-GAAP measures section of this MD&A
for further discussion of funds generated from operations,
comparable funds generated from operations, comparable
distributable cash flow and comparable distributable cash flow per
common share.
2 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.
COMPARABLE FUNDS GENERATED FROM OPERATIONS
Comparable funds generated from operations, a non-GAAP measure,
helps us assess the cash generating ability of our operations by
excluding the timing effects of working capital changes.
Despite the sales of our U.S. Northeast power generation assets
in second quarter 2017 and the continued wind-down of our U.S.
Northeast power marketing contracts, comparable funds generated
from operations increased by $255 million and $450 million for the
three and nine months ended September 30, 2018 compared to the
same periods in 2017. These increases are primarily due to higher
comparable earnings.
COMPARABLE DISTRIBUTABLE CASH FLOW
Comparable distributable cash flow, a non-GAAP measure, helps us
assess the cash available to common shareholders before capital
allocation.
The increase in comparable distributable cash flow for the three
and nine months ended September 30, 2018 compared to the same
periods in 2017 reflects higher comparable funds generated from
operations, as described above. Comparable distributable cash flow
per common share for the three and nine months ended
September 30, 2018 also reflects the dilutive impact of
common shares issued under the Corporate ATM program and DRP in
2017 and 2018.
Beginning in 2018, our determination of comparable distributable
cash flow has been revised to exclude the deduction of maintenance
capital expenditures for assets for which we have the ability to
recover these costs in pipeline tolls. Comparative periods
presented in the table below have been adjusted accordingly. We
believe that including only non-recoverable maintenance capital
expenditures in the calculation of distributable cash flow presents
the best depiction of the cash available for reinvestment or
distribution to shareholders. For our rate-regulated Canadian and
U.S. natural gas pipelines, we have the opportunity to recover and
earn a return on maintenance capital expenditures through current
and future tolls. Tolling arrangements in our liquids pipelines
provide for the recovery of maintenance capital expenditures.
Therefore, we have not deducted the recoverable maintenance capital
expenditures for these businesses in the calculation of comparable
distributable cash flow.
CASH USED IN INVESTING ACTIVITIES
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Capital spending |
|
|
|
|
|
|
|
|
Capital expenditures |
|
(2,435 |
) |
|
(2,031 |
) |
|
(6,474 |
) |
|
(5,383 |
) |
Capital projects in development |
|
(127 |
) |
|
(37 |
) |
|
(239 |
) |
|
(135 |
) |
Contributions to equity investments |
|
(236 |
) |
|
(475 |
) |
|
(778 |
) |
|
(1,140 |
) |
|
|
(2,798 |
) |
|
(2,543 |
) |
|
(7,491 |
) |
|
(6,658 |
) |
Proceeds from sales of assets, net of transaction costs |
|
— |
|
|
— |
|
|
— |
|
|
4,147 |
|
Other distributions from equity investments |
|
— |
|
|
— |
|
|
121 |
|
|
362 |
|
Deferred amounts and other |
|
(16 |
) |
|
165 |
|
|
78 |
|
|
(87 |
) |
Net cash used in investing
activities |
|
(2,814 |
) |
|
(2,378 |
) |
|
(7,292 |
) |
|
(2,236 |
) |
Capital expenditures in 2018 were incurred primarily for the
expansion of the Columbia Gas, Columbia Gulf and NGTL System
natural gas pipelines along with the construction of the Napanee
power generating facility and Mexico natural gas pipelines.
Costs incurred on capital projects in development in 2018 were
predominantly related to spending on Keystone XL.
Contributions to equity investments in 2018 principally involve
contributions to Bruce Power and Millennium as well as Sur de Texas
which includes our proportionate share of debt financing
requirements.
Other distributions from equity investments in 2018
primarily reflect our proportionate share of Bruce Power financings
undertaken to fund its capital program and to make distributions to
its partners. In first quarter 2018, Bruce Power issued senior
notes in capital markets which resulted in distributions totaling
$121 million to us.
In second quarter 2017, we closed the sales of our U.S.
Northeast power generation assets for net proceeds of $4,147
million.
CASH PROVIDED BY/(USED IN) FINANCING
ACTIVITIES
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Notes payable issued, net |
|
1,421 |
|
|
451 |
|
|
1,906 |
|
|
1,232 |
|
Long-term debt issued, net of issue costs1 |
|
1,026 |
|
|
1,151 |
|
|
4,359 |
|
|
1,968 |
|
Long-term debt repaid1 |
|
(1,232 |
) |
|
(46 |
) |
|
(3,266 |
) |
|
(5,515 |
) |
Junior subordinated notes issued, net of issue costs |
|
— |
|
|
(3 |
) |
|
— |
|
|
3,468 |
|
Dividends and distributions paid |
|
(513 |
) |
|
(459 |
) |
|
(1,446 |
) |
|
(1,313 |
) |
Common shares issued, net of issue costs |
|
354 |
|
|
6 |
|
|
1,139 |
|
|
42 |
|
Partnership units of TC PipeLines, LP issued, net of issue
costs |
|
— |
|
|
43 |
|
|
49 |
|
|
162 |
|
Common units of Columbia Pipeline Partners LP acquired |
|
— |
|
|
— |
|
|
— |
|
|
(1,205 |
) |
Net cash provided by/(used in)
financing activities |
|
1,056 |
|
|
1,143 |
|
|
2,741 |
|
|
(1,161 |
) |
1 Includes draws and repayments on unsecured loan
facility by TC PipeLines, LP.
LONG-TERM DEBT ISSUED
The following table outlines significant debt issuances in
2018:
(unaudited - millions of Canadian
$, unless noted otherwise) |
|
|
|
|
|
|
|
|
|
Company |
|
Issue date |
|
Type |
|
Maturity Date |
|
Amount |
|
Interest
rate |
|
|
|
|
|
|
|
|
|
|
|
TRANSCANADA PIPELINES LIMITED |
|
|
|
|
|
|
|
|
|
|
October 2018 |
|
Senior Unsecured Notes |
|
March 2049 |
|
US 1,000 |
|
|
5.10 |
% |
|
|
October 2018 |
|
Senior Unsecured Notes |
|
May
2028 |
|
US 400 |
|
|
4.25 |
% |
|
|
July 2018 |
|
Medium Term Notes |
|
July 2048 |
|
800 |
|
|
4.18 |
% |
|
|
July 2018 |
|
Medium Term Notes |
|
March 2028 |
|
200 |
|
|
3.39 |
% |
|
|
May
2018 |
|
Senior Unsecured Notes |
|
May
2028 |
|
US 1,000 |
|
|
4.25 |
% |
|
|
May
2018 |
|
Senior Unsecured Notes |
|
May
2038 |
|
US 500 |
|
|
4.75 |
% |
|
|
May 2018 |
|
Senior Unsecured Notes |
|
May 2048 |
|
US 1,000 |
|
|
4.875 |
% |
The net proceeds of the above debt issuances were used for
general corporate purposes, to fund our capital program and to
prefund 2019 senior note maturities.
LONG-TERM DEBT REPAID
The following table outlines significant debt repaid in 2018:
(unaudited -
millions of Canadian $, unless noted otherwise) |
|
|
|
|
|
|
|
|
Company |
|
Retirement date |
|
Type |
|
Amount |
|
Interest rate |
|
|
|
|
|
|
|
|
|
COLUMBIA PIPELINE GROUP, INC. |
|
|
|
|
|
|
|
|
June 2018 |
|
Senior Unsecured
Notes |
|
US 500 |
|
|
2.45 |
% |
PORTLAND NATURAL GAS TRANSMISSION SYSTEM |
|
|
|
|
|
|
|
|
May 2018 |
|
Senior Secured
Notes |
|
US
18 |
|
|
5.90 |
% |
TRANSCANADA PIPELINES LIMITED |
|
|
|
|
|
|
|
|
August 2018 |
|
Senior Unsecured
Notes |
|
US
850 |
|
|
6.50 |
% |
|
|
March 2018 |
|
Debentures |
|
150 |
|
|
9.45 |
% |
|
|
January 2018 |
|
Senior Unsecured
Notes |
|
US
500 |
|
|
1.875 |
% |
|
|
January 2018 |
|
Senior Unsecured
Notes |
|
US
250 |
|
|
Floating |
|
GREAT LAKES GAS TRANSMISSION LIMITED
PARTNERSHIP |
|
|
|
|
|
|
March
2018 |
|
Senior
Unsecured Notes |
|
US 9 |
|
|
6.73 |
% |
DIVIDEND REINVESTMENT PLAN
With respect to dividends declared on August 1, 2018, the DRP
participation rate amongst common shareholders was approximately 34
per cent, resulting in $213 million reinvested in common equity
under the program. Year-to-date in 2018, the participation rate
amongst common shareholders has been approximately 35 per cent,
resulting in $655 million of dividends reinvested.
TRANSCANADA CORPORATION ATM EQUITY PROGRAM
In the three months ended September 30, 2018, 6.1 million
common shares were issued under our Corporate ATM program at an
average price of $57.75 per common share for proceeds of $351
million, net of related commissions and fees of approximately $3
million. In the nine months ended September 30, 2018, 20.0
million common shares have been issued under our Corporate ATM
program at an average price of $56.13 per common share for proceeds
of $1.1 billion, net of approximately $10 million of related
commissions and fees.
In June 2018, we announced that the Company replenished the
capacity available under our existing Corporate ATM program. This
will allow us to issue additional common shares from treasury
having an aggregate gross sales price of up to $1.0 billion, for a
revised total of $2.0 billion or its U.S. dollar equivalent, to the
public from time to time at the prevailing market price when sold
through the TSX, the NYSE or on any other existing trading market
for the common shares in Canada or the United States. The Corporate
ATM program, as amended, is effective to July 23, 2019, and may be
utilized at our discretion if and as required based on the spend
profile of our capital program and relative cost of other funding
options.
TC PIPELINES, LP ATM EQUITY ISSUANCE
PROGRAM
In the nine months ended September 30, 2018, 0.7 million
common units were issued under the TC PipeLines, LP ATM program
generating net proceeds of approximately US$39 million. At
September 30, 2018, our ownership interest in TC PipeLines, LP
was 25.5 per cent giving effect to issuances under the ATM program
resulting in dilution of our ownership interest.
As a result of the 2018 FERC Actions initially proposed in March
2018, the TC PipeLines, LP ATM program ceased to be utilized. As a
result of uncertainties that remain after the 2018 FERC Actions
were finalized in July 2018, it is yet to be determined if and when
in the future the program might be reactivated.
DIVIDENDS
On October 31, 2018, we declared quarterly dividends as
follows:
Quarterly dividend on our
common shares |
|
|
$0.69 per share |
Payable on January 31, 2019 to
shareholders of record at the close of business on December 31,
2018. |
Quarterly dividends on our
preferred shares |
|
|
Series 1 |
$0.204125 |
Series 2 |
$0.22077123 |
Series 3 |
$0.1345 |
Series 4 |
$0.17956575 |
Payable on December 31, 2018 to shareholders of
record at the close of business on November 30, 2018. |
Series 5 |
$0.1414375 |
Series 6 |
$0.19446027 |
Series 7 |
$0.25 |
Series 9 |
$0.265625 |
Payable on January 30, 2019 to shareholders of
record at the close of business on December 31, 2018. |
Series 11 |
$0.2375 |
Series 13 |
$0.34375 |
Series 15 |
$0.30625 |
Payable on November 30, 2018 to
shareholders of record at the close of business on November 15,
2018. |
SHARE INFORMATION
as at October 29, 2018 |
|
|
|
|
|
Common shares |
Issued and outstanding |
|
|
914 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 7 |
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 |
8 million |
CREDIT FACILITIES
We 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 October 29, 2018, we had a total of $11.3 billion of
committed revolving and demand credit facilities, including:
Amount |
Unused
capacity |
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 for
general corporate purposes |
|
December 2022 |
US$2.0 billion |
US$2.0 billion |
TCPL |
Supports TCPL's U.S. dollar commercial paper program and for
general corporate purposes |
|
December 2018 |
US$1.0 billion |
US$1.0 billion |
TCPL USA |
Used for TCPL USA general corporate purposes, guaranteed by
TCPL |
|
December 2018 |
US$1.0 billion |
US$0.2 billion |
Columbia |
Used for Columbia general corporate purposes, guaranteed by
TCPL |
|
December 2018 |
US$0.5 billion |
US$0.5 billion |
TAIL |
Supports TAIL's U.S. dollar commercial paper program and for
general corporate purposes, guaranteed by TCPL |
|
December 2018 |
Demand senior unsecured revolving credit
facilities |
$2.1 billion |
$0.9 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$4.5 billion |
Mexican subsidiary |
Used for Mexico general corporate purposes,
guaranteed by TCPL |
|
Demand |
At October 29, 2018, our operated affiliates had an additional
$0.7 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 OBLIGATIONS
Our capital expenditure commitments have risen by approximately
$4.5 billion since December 31, 2017. This increase is primarily
due to commitments related to the construction of the CGL pipeline,
Columbia Gas growth projects, NGTL System, Keystone XL and our
proportionate share of commitments for Bruce Power's life extension
program. This increase is partially offset by decreased commitments
for the Sur de Texas natural gas pipeline and the Napanee power
generating facility.
There were no other material changes to our contractual
obligations in third quarter 2018 or to payments due in the next
five years or after. See the MD&A in our 2017 Annual Report for
more information about our contractual obligations.
Financial risks and financial instruments
We are exposed to liquidity risk, counterparty credit risk and
market risk, and have strategies, policies and limits in place to
mitigate their impact on our earnings, cash flow and, ultimately,
shareholder value. These are designed to ensure our risks and
related exposures are in line with our business objectives and risk
tolerance.
See our 2017 Annual Report for more information about the risks
we face in our business. Our risks have not changed substantially
since December 31, 2017, other than as described below.
On March 1, 2018, as part of the continued wind-down of our U.S.
Northeast power marketing contracts, we closed the sale of our U.S.
Northeast power retail contracts for proceeds of approximately
US$23 million and recognized income of US$10 million (US$7 million
after tax). We expect to realize the value of the remaining
marketing contracts and working capital over time. As a result, our
exposure to commodity risk has been reduced.
LIQUIDITY RISK
We manage our liquidity risk by continuously forecasting our cash
flow for a 12-month period to ensure 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.
COUNTERPARTY CREDIT RISK
We 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
- loans receivable.
We review our accounts receivable regularly and record
allowances for doubtful accounts using the specific identification
method. At September 30, 2018, 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.
LOAN RECEIVABLE FROM AFFILIATE
We 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. Draws on the credit
facility result in a loan receivable from the joint venture
representing our proportionate share of the debt financing
requirements advanced to the joint venture. At September 30,
2018, the balance of our loan receivable from the joint venture
totaled MXN$18.0 billion or $1.2 billion (December 31, 2017 -
MXN$14.4 billion or $919 million) and Interest income and other
included $32 million and $88 million of interest income on this
loan receivable for the three and nine months ended
September 30, 2018 (2017 - $11 million and $14 million).
Amounts recognized in Interest income and other are offset by a
corresponding proportionate share of interest expense recorded in
Income from equity investments in our Mexico Natural Gas Pipelines
segment.
INTEREST RATE RISK
We utilize short-term and long-term debt to finance our operations
which subjects 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 mitigate our interest rate
risk using a combination of interest rate swaps and option
derivatives.
FOREIGN EXCHANGE
We 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. The majority
of this risk is offset by interest expense on U.S.
dollar-denominated debt and by using foreign exchange
derivatives.
Average exchange rate - U.S. to Canadian
dollars
The average exchange rate for one U.S. dollar converted into
Canadian dollars was as follows:
three
months ended September 30, 2018 |
1.31 |
|
three months ended September 30, 2017 |
1.25 |
|
nine
months ended September 30, 2018 |
1.29 |
|
nine months ended September 30, 2017 |
1.31 |
|
The impact of changes in the value of the U.S. dollar on our
U.S. operations is partially offset by interest on U.S.
dollar-denominated long-term debt, as set out in the table below.
Comparable EBIT is a non-GAAP measure. See our Reconciliation of
non-GAAP measures section for more information.
Significant U.S. dollar-denominated amounts
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of US $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
U.S. Natural Gas Pipelines comparable EBIT |
|
417 |
|
|
269 |
|
|
1,348 |
|
|
998 |
|
Mexico Natural Gas Pipelines comparable EBIT1 |
|
122 |
|
|
76 |
|
|
366 |
|
|
254 |
|
U.S. Liquids Pipelines comparable EBIT |
|
218 |
|
|
135 |
|
|
605 |
|
|
416 |
|
U.S. Power comparable EBIT2 |
|
— |
|
|
22 |
|
|
— |
|
|
108 |
|
AFUDC on U.S. dollar-denominated projects |
|
91 |
|
|
81 |
|
|
230 |
|
|
168 |
|
Interest on U.S. dollar-denominated long-term debt |
|
(335 |
) |
|
(314 |
) |
|
(981 |
) |
|
(954 |
) |
Capitalized interest on U.S. dollar-denominated capital
expenditures |
|
4 |
|
|
1 |
|
|
10 |
|
|
2 |
|
U.S. dollar non-controlling interests and other |
|
(50 |
) |
|
(39 |
) |
|
(195 |
) |
|
(146 |
) |
|
|
467 |
|
|
231 |
|
|
1,383 |
|
|
846 |
|
1 Excludes interest expense on our inter-affiliate
loan with Sur de Texas which is offset in Interest income and
other.
2 Effective January 1, 2018, U.S. Power is no longer
included in comparable EBIT.
Net investment hedge
We hedge our net investment in foreign operations (on an after-tax
basis) with U.S. dollar-denominated debt, cross-currency interest
rate swaps, foreign exchange forward contracts and foreign exchange
options.
The fair values and notional amounts for the derivatives
designated as a net investment hedge were as follows:
|
|
September 30,
2018 |
|
December 31,
2017 |
(unaudited - millions of Canadian $, unless
noted otherwise) |
|
Fair
value1,2 |
|
Notional amount |
|
Fair
value1,2 |
|
Notional amount |
|
|
|
|
|
|
|
|
|
U.S. dollar cross-currency interest rate swaps (maturing 2018 to
2019)3 |
|
(42 |
) |
|
US 300 |
|
(199 |
) |
|
US 1,200 |
U.S. dollar foreign exchange options (maturing 2018 to 2019) |
|
(2 |
) |
|
US 2,000 |
|
5 |
|
|
US 500 |
|
|
(44 |
) |
|
US 2,300 |
|
(194 |
) |
|
US 1,700 |
1 Fair values equal carrying values.
2 No amounts have been excluded from the assessment of
hedge effectiveness.
3 In the three and nine months ended September 30,
2018, Net income includes net realized gains of nil and $1 million,
respectively (2017 - $1 million and $3 million, respectively)
related to the interest component of cross-currency swap
settlements which are reported within Interest expense.
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
noted otherwise) |
|
September 30, 2018 |
|
December 31, 2017 |
|
|
|
|
|
Notional amount |
|
28,300 (US 21,900) |
|
25,400 (US 20,200) |
Fair value |
|
30,200 (US 23,300) |
|
28,900 (US 23,100) |
FINANCIAL INSTRUMENTS
With 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 instruments
We use derivative instruments to reduce volatility associated with
fluctuations in commodity prices, interest rates and foreign
exchange rates. We apply hedge accounting to derivative
instruments that qualify and are designated for hedge accounting
treatment.
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 (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
instruments
The balance sheet classification of the fair value of derivative
instruments is as follows:
(unaudited - millions of $) |
|
September 30,
2018 |
|
December 31,
2017 |
|
|
|
|
|
Other current assets |
|
372 |
|
|
332 |
|
Intangible and other assets |
|
83 |
|
|
73 |
|
Accounts payable and other |
|
(418 |
) |
|
(387 |
) |
Other long-term liabilities |
|
(43 |
) |
|
(72 |
) |
|
|
(6 |
) |
|
(54 |
) |
Unrealized and realized (losses)/gains of derivative
instruments
The following summary does not include hedges of our net investment
in foreign operations.
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Derivative instruments held for
trading1 |
|
|
|
|
|
|
|
|
Amount of unrealized (losses)/gains in the period |
|
|
|
|
|
|
|
|
Commodities2 |
|
(31 |
) |
|
45 |
|
|
(41 |
) |
|
(102 |
) |
Foreign exchange |
|
60 |
|
|
33 |
|
|
(79 |
) |
|
89 |
|
Interest rate |
|
— |
|
|
(1 |
) |
|
— |
|
|
(1 |
) |
Amount of realized gains/(losses) in the period |
|
|
|
|
|
|
|
|
Commodities |
|
81 |
|
|
(82 |
) |
|
210 |
|
|
(167 |
) |
Foreign exchange |
|
(5 |
) |
|
19 |
|
|
14 |
|
|
10 |
|
Interest rate |
|
— |
|
|
1 |
|
|
— |
|
|
1 |
|
Derivative instruments in hedging
relationships |
|
|
|
|
|
|
|
|
Amount of realized gains/(losses) in the period |
|
|
|
|
|
|
|
|
Commodities |
|
1 |
|
|
4 |
|
|
— |
|
|
17 |
|
Foreign exchange |
|
— |
|
|
— |
|
|
— |
|
|
5 |
|
Interest rate |
|
(2 |
) |
|
— |
|
|
(1 |
) |
|
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 and nine months ended September 30,
2018 and 2017, 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
relationships
The components of the Condensed consolidated statement of
comprehensive income related to derivatives in cash flow hedging
relationships including the portion attributable to non-controlling
interests are as follows:
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Change in fair value of derivative instruments recognized in OCI
(effective portion)1 |
|
|
|
|
|
|
|
|
Commodities |
|
3 |
|
|
2 |
|
|
(3 |
) |
|
5 |
|
Interest rate |
|
2 |
|
|
(1 |
) |
|
11 |
|
|
— |
|
|
|
5 |
|
|
1 |
|
|
8 |
|
|
5 |
|
Reclassification of gains/(losses) on derivative instruments from
AOCI to net income1 |
|
|
|
|
|
|
|
|
Commodities2 |
|
3 |
|
|
(4 |
) |
|
4 |
|
|
(15 |
) |
Interest rate3 |
|
5 |
|
|
4 |
|
|
17 |
|
|
13 |
|
|
|
8 |
|
|
— |
|
|
21 |
|
|
(2 |
) |
1 Amounts presented are pre-tax. No amounts have been
excluded from the assessment of hedge effectiveness. Amounts in
parentheses indicate losses recorded to OCI and AOCI.
2 Reported within Revenues on the Condensed consolidated
statement of income.
3 Reported within Interest expense on the Condensed
consolidated statement of income.
Credit-risk-related contingent features of derivative
instruments
Derivatives 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
September 30, 2018, the aggregate fair value of all derivative
contracts with credit-risk-related contingent features that were in
a net liability position was $2 million (December 31, 2017 -
$2 million), with no collateral provided in the normal course of
business at September 30, 2018 and December 31, 2017. If
the credit-risk-related contingent features in these agreements
were triggered on September 30, 2018, we would have been
required to provide collateral of $2 million (December 31,
2017 - $2 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 PROCEDURES
Management, including our President and CEO and our CFO,
evaluated the effectiveness of our disclosure controls and
procedures as at September 30, 2018, 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 third quarter 2018 that had or are
likely to have a material impact on our internal control over
financial reporting.
CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY
CHANGES
When 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 2017 Annual
Report.
Our significant accounting policies have remained unchanged
since December 31, 2017 other than described below. A summary
of our significant accounting policies is included in our 2017
Annual Report.
Changes in accounting policies for 2018
Revenue from contracts with customers
In 2014, the FASB issued new guidance on revenue from contracts
with customers. The new guidance requires that an entity recognize
revenue from these contracts in accordance with a prescribed model.
This model is used to depict the transfer of promised goods or
services to customers in amounts that reflect the total
consideration to which it expects to be entitled during the term of
the contract in exchange for those promised goods or services.
Goods or services that are promised to a customer are referred to
as our "performance obligations." The total consideration to which
we expect to be entitled can include fixed and variable amounts. We
have variable revenue that is subject to factors outside of our
influence, such as market prices, actions of third parties and
weather conditions. We consider this variable revenue to be
"constrained" as it cannot be reliably estimated, and therefore
recognize variable revenue when the service is provided.
The new guidance also requires additional disclosures about the
nature, amount, timing and uncertainty of revenue recognition and
related cash flows.
In the application of the new guidance, significant estimates
and judgments are used to determine the following:
- pattern of revenue recognition within a contract, based on
whether the performance obligation is satisfied at a point in time
versus over time
- term of the contract
- amount of variable consideration associated with a contract and
timing of the associated revenue recognition.
The new guidance was effective January 1, 2018, was applied
using the modified retrospective transition method, and did not
result in any material differences in the amount and timing of
revenue recognition.
Financial instruments
In January 2016, the FASB issued new guidance on the accounting for
equity investments and financial liabilities. The new guidance
changes the income statement effect of equity investments and the
recognition of changes in the fair value of financial liabilities
when the fair value option is elected. The new guidance also
requires us to assess valuation allowances for deferred tax assets
related to available for sale debt securities in combination with
our other deferred tax assets. This new guidance was effective
January 1, 2018 and did not have a material impact on our
consolidated financial statements.
Income taxes
In October 2016, the FASB issued new guidance on the income tax
effects of intra-entity transfers of assets other than inventory.
The new guidance requires the recognition of deferred and current
income taxes for intra-entity asset transfers when the transfer
occurs. The new guidance was effective January 1, 2018, was applied
using a modified retrospective approach, and did not have a
material impact on our consolidated financial statements.
Restricted cash
In November 2016, the FASB issued new guidance on restricted cash
and cash equivalents on the statement of cash flows. The new
guidance requires that the statement of cash flows explain the
change during the period in the total cash and cash equivalents
balance, and amounts generally described as restricted cash or
restricted cash equivalents. Restricted cash and cash equivalents
will be included with cash and cash equivalents when reconciling
the beginning of period and end of period total amounts on the
statement of cash flows. This new guidance was effective January 1,
2018, was applied retrospectively, and did not have an impact on
our consolidated financial statements.
Employee post-retirement benefits
In March 2017, the FASB issued new guidance that requires entities
to disaggregate the current service cost component from the other
components of net benefit cost and present it with other current
compensation costs for related employees in the income statement.
The new guidance also requires that the other components of net
benefit cost be presented elsewhere in the income statement and
excluded from income from operations if such a subtotal is
presented. In addition, the new guidance makes changes to the
components of net benefit cost that are eligible for
capitalization. Entities must use a retrospective transition method
to adopt the requirement for separate presentation in the income
statement of the components of net benefit cost, and a prospective
transition method to adopt the change to capitalization of benefit
costs. This new guidance was effective January 1, 2018 and did not
have a material impact on our consolidated financial
statements.
Hedge accounting
In August 2017, the FASB issued new guidance making more financial
and non-financial hedging strategies eligible for hedge accounting.
The new guidance also amends the presentation requirements relating
to the change in fair value of a derivative and requires additional
disclosures including cumulative basis adjustments for fair value
hedges and the effect of hedging on individual line items in the
statement of income. This new guidance is effective January 1, 2019
with early adoption permitted. This new guidance, which we elected
to adopt effective January 1, 2018, was applied prospectively and
did not have a material impact on our consolidated financial
statements.
Future accounting changes
Leases
In 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 lessor
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 12 months.
Leases will be classified as finance or operating, with
classification affecting the pattern of expense recognition in the
statement of income. The new guidance does not make extensive
changes to lessor accounting.
In January 2018, the FASB issued an optional practical
expedient, to be applied upon transition, to omit the evaluation of
land easements not previously accounted for as leases that existed
or expired prior to the entity's adoption of the new lease
guidance. An entity that elects this practical expedient is
required to apply the practical expedient consistently to all of
its existing or expired land easements not previously accounted for
as leases. We intend to apply this practical expedient upon
transition to the new standard.
The new guidance is effective January 1, 2019, with early
adoption permitted. We will adopt the new standard on its effective
date. A modified retrospective transition approach is required,
applying the new standard to all leases existing at the date of
initial application. In July 2018, the FASB issued a
transition option allowing entities to not apply the new guidance,
including disclosure requirements, to the comparative periods they
present in their financial statements in the year of adoption. We
will apply this transition option and therefore, will not be
required to update financial information and disclosures for dates
and periods prior to January 1, 2019.
We will elect the package of practical expedients which permits
entities not to reassess prior conclusions about lease
identification, lease classification and initial direct costs under
the rules of the new standard. We continue to monitor and analyze
other optional practical expedients as well as additional guidance
and clarifications provided by the FASB.
We have developed an inventory of existing lease agreements,
have substantially completed our analysis on them, but continue to
refine our view of what qualifies as a lease and evaluate the
financial impact on our consolidated financial statements. We have
also selected a system solution and continue to progress through
the testing stage of implementation. We continue to assess process
changes necessary to compile the information to meet the
recognition and disclosure requirements of the new guidance and to
analyze new contracts that may contain leases.
Measurement of credit losses on financial
instruments
In 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.
Goodwill impairment
In January 2017, the FASB issued new guidance on simplifying the
test for goodwill impairment by eliminating Step 2 of the
impairment test, which is the requirement to calculate the implied
fair value of goodwill to measure the impairment charge. Instead,
entities will record an impairment charge based on the excess of a
reporting unit’s carrying amount over its fair value. This new
guidance is effective January 1, 2020 and will be applied
prospectively, however, early adoption is permitted. We are
currently evaluating the timing and impact of the adoption of this
guidance.
Income taxes
In February 2018, the FASB issued new guidance that allows a
reclassification from AOCI to retained earnings for stranded tax
effects resulting from the U.S. Tax Reform. This new guidance is
effective January 1, 2019, however, early adoption is permitted.
This guidance can be applied either in the period of adoption or
retrospectively to each period (or periods) in which the effect of
the change is recognized. We are currently evaluating this guidance
in conjunction with our analysis of the overall impact of U.S. Tax
Reform.
Fair value measurement
In 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 are currently
evaluating the timing and impact of adoption of this guidance and
have not yet determined the effect on our consolidated financial
statements.
Defined benefit plans
In 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. We are currently evaluating the timing and
impact of the adoption of this guidance.
Implementation costs of cloud computing
arrangements
In 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.
Reconciliation of non-GAAP measures
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Comparable EBITDA |
|
|
|
|
|
|
|
|
Canadian Natural Gas Pipelines |
|
522 |
|
|
544 |
|
|
1,561 |
|
|
1,575 |
|
U.S. Natural Gas Pipelines |
|
715 |
|
|
482 |
|
|
2,223 |
|
|
1,753 |
|
Mexico Natural Gas Pipelines |
|
153 |
|
|
118 |
|
|
455 |
|
|
403 |
|
Liquids Pipelines |
|
467 |
|
|
303 |
|
|
1,311 |
|
|
947 |
|
Energy |
|
207 |
|
|
224 |
|
|
585 |
|
|
816 |
|
Corporate |
|
(8 |
) |
|
(4 |
) |
|
(25 |
) |
|
(20 |
) |
Comparable EBITDA |
|
2,056 |
|
|
1,667 |
|
|
6,110 |
|
|
5,474 |
|
Depreciation and amortization |
|
(564 |
) |
|
(506 |
) |
|
(1,669 |
) |
|
(1,532 |
) |
Comparable EBIT |
|
1,492 |
|
|
1,161 |
|
|
4,441 |
|
|
3,942 |
|
Specific items: |
|
|
|
|
|
|
|
|
Foreign exchange (loss)/gain – inter-affiliate
loan |
|
(60 |
) |
|
7 |
|
|
(52 |
) |
|
(1 |
) |
U.S. Northeast power marketing contracts |
|
12 |
|
|
— |
|
|
5 |
|
|
— |
|
Net (loss)/gain on sales of U.S. Northeast power
generation assets |
|
— |
|
|
(12 |
) |
|
— |
|
|
469 |
|
Integration and acquisition related costs –
Columbia |
|
— |
|
|
(32 |
) |
|
— |
|
|
(91 |
) |
Keystone XL asset costs |
|
— |
|
|
(10 |
) |
|
— |
|
|
(23 |
) |
Risk management activities1 |
|
(34 |
) |
|
45 |
|
|
(44 |
) |
|
(102 |
) |
Segmented earnings |
|
1,410 |
|
|
1,159 |
|
|
4,350 |
|
|
4,194 |
|
1 |
|
Risk management
activities |
|
three months ended
September 30 |
|
nine months ended
September 30 |
|
|
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Power |
|
— |
|
|
1 |
|
|
3 |
|
|
5 |
|
|
|
U.S. Power |
|
31 |
|
|
59 |
|
|
(31 |
) |
|
(97 |
) |
|
|
Liquids marketing |
|
(65 |
) |
|
(19 |
) |
|
(10 |
) |
|
(15 |
) |
|
|
Natural Gas Storage |
|
— |
|
|
4 |
|
|
(6 |
) |
|
5 |
|
|
|
Total unrealized (losses)/gains from
risk management activities |
|
(34 |
) |
|
45 |
|
|
(44 |
) |
|
(102 |
) |
Quarterly results
SELECTED QUARTERLY CONSOLIDATED FINANCIAL
DATA
|
|
2018
|
|
2017
|
|
2016
|
(unaudited - millions of $, except
per share amounts) |
|
Third |
Second |
|
First |
|
Fourth |
|
Third |
|
Second |
|
First |
|
Fourth |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
3,156 |
|
|
3,195 |
|
|
|
3,424 |
|
|
|
3,617 |
|
|
|
3,195 |
|
|
|
3,230 |
|
|
|
3,407 |
|
|
|
3,635 |
|
Net income/(loss) attributable to common shares |
|
|
928 |
|
|
785 |
|
|
|
734 |
|
|
|
861 |
|
|
|
612 |
|
|
|
881 |
|
|
|
643 |
|
|
|
(358 |
) |
Comparable earnings |
|
|
902 |
|
|
768 |
|
|
|
864 |
|
|
|
719 |
|
|
|
614 |
|
|
|
659 |
|
|
|
698 |
|
|
|
626 |
|
Per share statistics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) per common share - basic
and diluted |
|
$1.02 |
|
$0.88 |
|
|
$0.83 |
|
|
$0.98 |
|
|
$0.70 |
|
|
$1.01 |
|
|
$0.74 |
|
|
|
($0.43 |
) |
Comparable earnings per
common share |
|
$1.00 |
|
$0.86 |
|
|
$0.98 |
|
|
$0.82 |
|
|
$0.70 |
|
|
$0.76 |
|
|
$0.81 |
|
|
$0.75 |
|
Dividends declared per common share |
|
$0.69 |
|
$0.69 |
|
|
$0.69 |
|
|
$0.625 |
|
|
$0.625 |
|
|
$0.625 |
|
|
$0.625 |
|
|
$0.565 |
|
FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY
BUSINESS SEGMENT
Quarter-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
- acquisitions and divestitures
- developments outside of the normal course of operations
- newly constructed assets being placed in service.
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
- developments outside of the normal course of operations
- newly constructed assets being placed in service
- demand for uncontracted transportation services
- liquids marketing activities
- certain fair value adjustments.
In Energy, quarter-over-quarter revenues and net income are
affected by:
- weather
- customer demand
- market prices for natural gas and power
- capacity prices and payments
- planned and unplanned plant outages
- acquisitions and divestitures
- certain fair value adjustments
- developments outside of the normal course of operations
- newly constructed assets being placed in service.
FACTORS AFFECTING FINANCIAL INFORMATION BY
QUARTER
We 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 third quarter 2018, comparable earnings also excluded:
- after-tax income of $8 million related to our U.S. Northeast
power marketing contracts. These were excluded from Energy's
comparable earnings effective January 1, 2018 as the wind-down of
these contracts is not considered part of our underlying
operations.
In second quarter 2018, comparable earnings also excluded:
- an after-tax loss of $11 million related to our U.S. Northeast
power marketing contracts. These were excluded from Energy's
comparable earnings effective January 1, 2018 as the wind-down of
these contracts is not considered part of our underlying
operations.
In the first quarter 2018, comparable earnings also
excluded:
- after-tax income of $6 million related to our U.S. Northeast
power marketing contracts, primarily due to income recognized on
the sale of our retail contracts. These were excluded from Energy's
comparable earnings effective January 1, 2018 as the wind-down of
these contracts is not considered part of our underlying
operations.
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, which included an
incremental after-tax loss of $7 million recorded on the sale of
the thermal and wind package, $23 million of after-tax third-party
insurance proceeds related to a 2017 Ravenswood outage and income
tax adjustments
- 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 which were expensed pending
further advancement of the project.
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,
which included an incremental loss of $7 million after tax on the
sale of the thermal and wind package and $14 million of after-tax
disposition costs and income tax adjustments
- 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 which were being expensed pending further
advancement of the project.
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 an
additional 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 which were being expensed pending further
advancement of the project.
In first quarter 2017, comparable earnings also excluded:
- a charge of $24 million after tax for integration-related costs
associated with the acquisition of Columbia
- a charge of $10 million after tax for costs related to the
monetization of our U.S. Northeast power generation business
- a charge of $7 million after tax related to the maintenance of
Keystone XL assets which were being expensed pending further
advancement of the project
- a $7 million income tax recovery related to the realized loss
on a third-party sale of Keystone XL project assets. A provision
for the expected pre-tax loss on these assets was included in our
2015 impairment charge but the related income tax recoveries could
not be recorded until realized.
In fourth quarter 2016, comparable earnings also excluded:
- an $870 million after-tax charge related to the loss on U.S.
Northeast power assets held for sale which included an $863 million
after-tax loss on the thermal and wind package held for sale and $7
million of after-tax costs related to the monetization
- an additional $68 million after-tax loss on the transfer of
environmental credits to the Balancing Pool upon final settlement
of the Alberta PPA terminations
- an after-tax charge of $67 million for costs associated with
the acquisition of Columbia which included a $44 million deferred
tax adjustment upon acquisition and $23 million of retention,
severance and integration costs
- an after-tax charge of $18 million related to Keystone XL costs
for the maintenance and liquidation of project assets which were
being expensed pending further advancement of the project
- an after-tax restructuring charge of $6 million for additional
expected future losses under lease commitments. These charges
formed part of a restructuring initiative, which commenced in 2015,
to maximize the effectiveness and efficiency of our existing
operations and reduce overall costs.
Condensed consolidated statement of
income
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of Canadian $, except per share amounts) |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
|
934 |
|
|
|
921 |
|
|
|
2,772 |
|
|
|
2,725 |
|
U.S. Natural Gas
Pipelines |
|
|
967 |
|
|
|
811 |
|
|
|
2,988 |
|
|
|
2,684 |
|
Mexico Natural Gas
Pipelines |
|
|
156 |
|
|
|
139 |
|
|
|
460 |
|
|
|
432 |
|
Liquids Pipelines |
|
|
564 |
|
|
|
437 |
|
|
|
1,831 |
|
|
|
1,410 |
|
Energy |
|
|
535 |
|
|
|
887 |
|
|
|
1,724 |
|
|
|
2,581 |
|
|
|
|
3,156 |
|
|
|
3,195 |
|
|
|
9,775 |
|
|
|
9,832 |
|
Income from
Equity Investments |
|
|
147 |
|
|
|
156 |
|
|
|
492 |
|
|
|
527 |
|
Operating and
Other Expenses |
|
|
|
|
|
|
|
|
Plant operating costs
and other |
|
|
884 |
|
|
|
929 |
|
|
|
2,580 |
|
|
|
2,962 |
|
Commodity purchases
resold |
|
|
318 |
|
|
|
621 |
|
|
|
1,239 |
|
|
|
1,711 |
|
Property taxes |
|
|
127 |
|
|
|
127 |
|
|
|
429 |
|
|
|
442 |
|
Depreciation and
amortization |
|
|
564 |
|
|
|
506 |
|
|
|
1,669 |
|
|
|
1,539 |
|
|
|
|
1,893 |
|
|
|
2,183 |
|
|
|
5,917 |
|
|
|
6,654 |
|
(Loss)/Gain on
Sales of Assets |
|
|
— |
|
|
|
(9 |
) |
|
|
— |
|
|
|
489 |
|
Financial
Charges |
|
|
|
|
|
|
|
|
Interest expense |
|
|
577 |
|
|
|
504 |
|
|
|
1,662 |
|
|
|
1,528 |
|
Allowance for funds
used during construction |
|
|
(147 |
) |
|
|
(145 |
) |
|
|
(365 |
) |
|
|
(367 |
) |
Interest
income and other |
|
|
(168 |
) |
|
|
(84 |
) |
|
|
(139 |
) |
|
|
(193 |
) |
|
|
|
262 |
|
|
|
275 |
|
|
|
1,158 |
|
|
|
968 |
|
Income before Income Taxes |
|
|
1,148 |
|
|
|
884 |
|
|
|
3,192 |
|
|
|
3,226 |
|
Income Tax
Expense |
|
|
|
|
|
|
|
|
Current |
|
|
30 |
|
|
|
6 |
|
|
|
169 |
|
|
|
128 |
|
Deferred |
|
|
90 |
|
|
|
182 |
|
|
|
225 |
|
|
|
653 |
|
|
|
|
120 |
|
|
|
188 |
|
|
|
394 |
|
|
|
781 |
|
Net
Income |
|
|
1,028 |
|
|
|
696 |
|
|
|
2,798 |
|
|
|
2,445 |
|
Net
income attributable to non-controlling interests |
|
|
59 |
|
|
|
44 |
|
|
|
229 |
|
|
|
189 |
|
Net Income
Attributable to Controlling Interests |
|
|
969 |
|
|
|
652 |
|
|
|
2,569 |
|
|
|
2,256 |
|
Preferred
share dividends |
|
|
41 |
|
|
|
40 |
|
|
|
122 |
|
|
|
120 |
|
Net Income
Attributable to Common Shares |
|
|
928 |
|
|
|
612 |
|
|
|
2,447 |
|
|
|
2,136 |
|
Net Income per
Common Share |
|
|
|
|
|
|
|
|
Basic |
|
$1.02 |
|
|
$0.70 |
|
|
$2.72 |
|
|
$2.46 |
|
Diluted |
|
$1.02 |
|
|
$0.70 |
|
|
$2.72 |
|
|
$2.45 |
|
Dividends Declared per Common Share |
|
$0.69 |
|
|
$0.625 |
|
|
$2.07 |
|
|
$1.875 |
|
Weighted
Average Number of Common Shares (millions) |
|
|
|
|
|
|
|
|
Basic |
|
|
906 |
|
|
|
873 |
|
|
|
898 |
|
|
|
870 |
|
Diluted |
|
|
907 |
|
|
|
875 |
|
|
|
898 |
|
|
|
872 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated statement of
comprehensive income
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Net Income |
|
1,028 |
|
|
696 |
|
|
2,798 |
|
|
2,445 |
|
Other Comprehensive (Loss)/Income, Net of Income
Taxes |
|
|
|
|
|
|
|
|
Foreign currency translation gains and losses on net investment in
foreign operations |
|
(282 |
) |
|
(370 |
) |
|
409 |
|
|
(721 |
) |
Reclassification of foreign currency translation gains on net
investment on disposal of foreign operations |
|
— |
|
|
— |
|
|
— |
|
|
(77 |
) |
Change in fair value of net investment hedges |
|
9 |
|
|
(1 |
) |
|
(6 |
) |
|
(3 |
) |
Change in fair value of cash flow hedges |
|
4 |
|
|
1 |
|
|
9 |
|
|
4 |
|
Reclassification to net income of gains and losses on cash flow
hedges |
|
6 |
|
|
— |
|
|
16 |
|
|
(1 |
) |
Unrealized actuarial gains and losses on pension and other
post-retirement benefit plans |
|
— |
|
|
2 |
|
|
— |
|
|
2 |
|
Reclassification of actuarial gains and losses on pension and other
post-retirement benefit plans |
|
10 |
|
|
4 |
|
|
10 |
|
|
11 |
|
Other comprehensive income on equity
investments |
|
6 |
|
|
3 |
|
|
18 |
|
|
6 |
|
Other comprehensive (loss)/income |
|
(247 |
) |
|
(361 |
) |
|
456 |
|
|
(779 |
) |
Comprehensive Income |
|
781 |
|
|
335 |
|
|
3,254 |
|
|
1,666 |
|
Comprehensive income/(loss) attributable to
non-controlling interests |
|
28 |
|
|
(25 |
) |
|
304 |
|
|
31 |
|
Comprehensive Income Attributable to Controlling
Interests |
|
753 |
|
|
360 |
|
|
2,950 |
|
|
1,635 |
|
Preferred share dividends |
|
41 |
|
|
40 |
|
|
122 |
|
|
120 |
|
Comprehensive Income Attributable to
Common Shares |
|
712 |
|
|
320 |
|
|
2,828 |
|
|
1,515 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated statement of cash
flows
|
|
three months ended
September 30 |
|
nine months
ended September 30 |
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Cash Generated from Operations |
|
|
|
|
|
|
|
|
Net income |
|
1,028 |
|
|
696 |
|
|
2,798 |
|
|
2,445 |
|
Depreciation and amortization |
|
564 |
|
|
506 |
|
|
1,669 |
|
|
1,539 |
|
Deferred income taxes |
|
90 |
|
|
182 |
|
|
225 |
|
|
653 |
|
Income from equity investments |
|
(147 |
) |
|
(156 |
) |
|
(492 |
) |
|
(527 |
) |
Distributions received from operating activities of equity
investments |
|
296 |
|
|
296 |
|
|
761 |
|
|
743 |
|
Employee post-retirement benefits funding, net of expense |
|
(22 |
) |
|
(73 |
) |
|
(22 |
) |
|
(64 |
) |
Loss/(gain) on sales of assets |
|
— |
|
|
9 |
|
|
— |
|
|
(489 |
) |
Equity allowance for funds used during construction |
|
(104 |
) |
|
(107 |
) |
|
(261 |
) |
|
(249 |
) |
Unrealized (gains)/losses on financial instruments |
|
(29 |
) |
|
(77 |
) |
|
120 |
|
|
14 |
|
Other |
|
(93 |
) |
|
(5 |
) |
|
(152 |
) |
|
(1 |
) |
Increase in operating working capital |
|
(284 |
) |
|
(86 |
) |
|
(130 |
) |
|
(224 |
) |
Net cash provided by operations |
|
1,299 |
|
|
1,185 |
|
|
4,516 |
|
|
3,840 |
|
Investing Activities |
|
|
|
|
|
|
|
|
Capital expenditures |
|
(2,435 |
) |
|
(2,031 |
) |
|
(6,474 |
) |
|
(5,383 |
) |
Capital projects in development |
|
(127 |
) |
|
(37 |
) |
|
(239 |
) |
|
(135 |
) |
Contributions to equity investments |
|
(236 |
) |
|
(475 |
) |
|
(778 |
) |
|
(1,140 |
) |
Proceeds from sales of assets, net of transaction costs |
|
— |
|
|
— |
|
|
— |
|
|
4,147 |
|
Other distributions from equity investments |
|
— |
|
|
— |
|
|
121 |
|
|
362 |
|
Deferred amounts and other |
|
(16 |
) |
|
165 |
|
|
78 |
|
|
(87 |
) |
Net cash used in investing activities |
|
(2,814 |
) |
|
(2,378 |
) |
|
(7,292 |
) |
|
(2,236 |
) |
Financing Activities |
|
|
|
|
|
|
|
|
Notes payable issued, net |
|
1,421 |
|
|
451 |
|
|
1,906 |
|
|
1,232 |
|
Long-term debt issued, net of issue costs |
|
1,026 |
|
|
1,151 |
|
|
4,359 |
|
|
1,968 |
|
Long-term debt repaid |
|
(1,232 |
) |
|
(46 |
) |
|
(3,266 |
) |
|
(5,515 |
) |
Junior subordinated notes issued, net of issue costs |
|
— |
|
|
(3 |
) |
|
— |
|
|
3,468 |
|
Dividends on common shares |
|
(416 |
) |
|
(354 |
) |
|
(1,154 |
) |
|
(982 |
) |
Dividends on preferred shares |
|
(40 |
) |
|
(39 |
) |
|
(118 |
) |
|
(116 |
) |
Distributions paid to non-controlling interests |
|
(57 |
) |
|
(66 |
) |
|
(174 |
) |
|
(215 |
) |
Common shares issued, net of issue costs |
|
354 |
|
|
6 |
|
|
1,139 |
|
|
42 |
|
Partnership units of TC PipeLines, LP issued, net of issue
costs |
|
— |
|
|
43 |
|
|
49 |
|
|
162 |
|
Common units of Columbia Pipeline Partners LP acquired |
|
— |
|
|
— |
|
|
— |
|
|
(1,205 |
) |
Net cash provided by/(used in) financing
activities |
|
1,056 |
|
|
1,143 |
|
|
2,741 |
|
|
(1,161 |
) |
Effect of Foreign Exchange Rate
Changes on Cash and Cash Equivalents |
|
(10 |
) |
|
(16 |
) |
|
47 |
|
|
(35 |
) |
(Decrease)/increase in Cash and Cash
Equivalents |
|
(469 |
) |
|
(66 |
) |
|
12 |
|
|
408 |
|
Cash and Cash Equivalents |
|
|
|
|
|
|
|
|
Beginning of period |
|
1,570 |
|
|
1,490 |
|
|
1,089 |
|
|
1,016 |
|
Cash and Cash Equivalents |
|
|
|
|
|
|
|
|
End of period |
|
1,101 |
|
|
1,424 |
|
|
1,101 |
|
|
1,424 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated balance
sheet
|
|
September
30, |
|
December
31, |
(unaudited - millions of Canadian
$) |
|
2018 |
|
2017 |
|
|
|
|
|
ASSETS |
|
|
|
|
Current Assets |
|
|
|
|
Cash and cash equivalents |
|
1,101 |
|
|
1,089 |
|
Accounts receivable |
|
2,170 |
|
|
2,522 |
|
Inventories |
|
381 |
|
|
378 |
|
Assets held for sale |
|
458 |
|
|
— |
|
Other |
|
1,003 |
|
|
691 |
|
|
|
5,113 |
|
|
4,680 |
|
Plant, Property and Equipment |
net of accumulated depreciation of $25,206 and $23,734,
respectively |
|
63,212 |
|
|
57,277 |
|
Equity Investments |
|
6,683 |
|
|
6,366 |
|
Regulatory Assets |
|
1,391 |
|
|
1,376 |
|
Goodwill |
|
13,504 |
|
|
13,084 |
|
Loan Receivable from Affiliate |
|
1,244 |
|
|
919 |
|
Intangible and Other Assets |
|
1,929 |
|
|
1,484 |
|
Restricted
Investments |
|
1,101 |
|
|
915 |
|
|
|
94,177 |
|
|
86,101 |
|
LIABILITIES |
|
|
|
|
Current Liabilities |
|
|
|
|
Notes payable |
|
3,742 |
|
|
1,763 |
|
Accounts payable and other |
|
4,301 |
|
|
4,057 |
|
Dividends payable |
|
643 |
|
|
586 |
|
Accrued interest |
|
604 |
|
|
605 |
|
Current portion of long-term
debt |
|
1,671 |
|
|
2,866 |
|
|
|
10,961 |
|
|
9,877 |
|
Regulatory Liabilities |
|
4,603 |
|
|
4,321 |
|
Other Long-Term Liabilities |
|
637 |
|
|
727 |
|
Deferred Income Tax
Liabilities |
|
5,824 |
|
|
5,403 |
|
Long-Term Debt |
|
35,029 |
|
|
31,875 |
|
Junior Subordinated
Notes |
|
7,186 |
|
|
7,007 |
|
|
|
64,240 |
|
|
59,210 |
|
EQUITY |
|
|
|
|
Common shares, no par value |
|
22,951 |
|
|
21,167 |
|
Issued and outstanding: |
September 30, 2018 - 914 million shares |
|
|
|
|
|
December 31, 2017 - 881 million shares |
|
|
|
|
Preferred shares |
|
3,980 |
|
|
3,980 |
|
Additional paid-in capital |
|
15 |
|
|
— |
|
Retained earnings |
|
2,318 |
|
|
1,623 |
|
Accumulated other comprehensive
loss |
|
(1,350 |
) |
|
(1,731 |
) |
Controlling Interests |
|
27,914 |
|
|
25,039 |
|
Non-controlling interests |
|
2,023 |
|
|
1,852 |
|
|
|
29,937 |
|
|
26,891 |
|
|
|
94,177 |
|
|
86,101 |
|
Contingencies and Guarantees (Note 13)
Variable Interest Entities (Note 14)
Subsequent Events (Note 15)
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated statement of equity
|
nine months ended
September 30 |
(unaudited - millions of Canadian $) |
2018 |
|
2017 |
|
|
|
|
Common Shares |
|
|
|
Balance at beginning of period |
21,167 |
|
|
20,099 |
|
Shares issued: |
|
|
|
Under at-the-market equity program, net of issue
costs |
1,118 |
|
|
— |
|
Under dividend reinvestment and share purchase
plan |
640 |
|
|
599 |
|
On exercise of stock options |
26 |
|
|
46 |
|
Balance at end of period |
22,951 |
|
|
20,744 |
|
Preferred Shares |
|
|
|
Balance at beginning and end of period |
3,980 |
|
|
3,980 |
|
Additional Paid-In Capital |
|
|
|
Balance at beginning of period |
— |
|
|
— |
|
Issuance of stock options, net of exercises |
8 |
|
|
4 |
|
Dilution from TC PipeLines, LP units issued |
7 |
|
|
18 |
|
Asset drop downs to TC PipeLines, LP |
— |
|
|
(202 |
) |
Columbia Pipeline Partners LP acquisition |
— |
|
|
(171 |
) |
Reclassification of additional paid-in capital deficit to retained
earnings |
— |
|
|
351 |
|
Balance at end of period |
15 |
|
|
— |
|
Retained Earnings |
|
|
|
Balance at beginning of period |
1,623 |
|
|
1,138 |
|
Net income attributable to controlling interests |
2,569 |
|
|
2,256 |
|
Common share dividends |
(1,869 |
) |
|
(1,633 |
) |
Preferred share dividends |
(100 |
) |
|
(98 |
) |
Adjustment related to income tax effects of asset drop downs to TC
PipeLines, LP |
95 |
|
|
— |
|
Adjustment related to employee share-based payments |
— |
|
|
12 |
|
Reclassification of additional paid-in capital
deficit to retained earnings |
— |
|
|
(351 |
) |
Balance at end of period |
2,318 |
|
|
1,324 |
|
Accumulated Other Comprehensive Loss |
|
|
|
Balance at beginning of period |
(1,731 |
) |
|
(960 |
) |
Other comprehensive income/(loss) attributable to controlling
interests |
381 |
|
|
(621 |
) |
Balance at end of period |
(1,350 |
) |
|
(1,581 |
) |
Equity Attributable to Controlling
Interests |
27,914 |
|
|
24,467 |
|
Equity Attributable to Non-Controlling
Interests |
|
|
|
Balance at beginning of period |
1,852 |
|
|
1,726 |
|
Net income attributable to non-controlling interests |
229 |
|
|
189 |
|
Other comprehensive income/(loss) attributable to non-controlling
interests |
75 |
|
|
(158 |
) |
Issuance of TC PipeLines, LP units |
|
|
|
Proceeds, net of issue costs |
49 |
|
|
162 |
|
Decrease in TransCanada's ownership of TC PipeLines,
LP |
(9 |
) |
|
(29 |
) |
Distributions declared to non-controlling interests |
(173 |
) |
|
(212 |
) |
Reclassification from common units of TC PipeLines, LP subject to
rescission |
— |
|
|
106 |
|
Impact of Columbia Pipeline Partners LP
acquisition |
— |
|
|
33 |
|
Balance at end of period |
2,023 |
|
|
1,817 |
|
Total Equity |
29,937 |
|
|
26,284 |
|
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, 2017, except as described in Note 2, Accounting
changes. Capitalized and abbreviated terms that are used but not
otherwise defined herein are identified in the 2017 audited
consolidated financial statements included in TransCanada’s 2017
Annual Report.
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 2017 audited
consolidated financial statements included in TransCanada’s 2017
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 Energy 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 JUDGEMENTS
In 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 judgement 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, 2017, except as described in Note 2, Accounting
changes.
2. Accounting changes
CHANGES IN ACCOUNTING POLICIES FOR 2018
Revenue from contracts with customers
In 2014, the FASB issued new guidance on revenue from contracts
with customers. The new guidance requires that an entity recognize
revenue from these contracts in accordance with a prescribed model.
This model is used to depict the transfer of promised goods or
services to customers in amounts that reflect the total
consideration to which it expects to be entitled during the term of
the contract in exchange for those promised goods or services.
Goods or services that are promised to a customer are referred to
as the Company's "performance obligations." The total consideration
to which the Company expects to be entitled can include fixed and
variable amounts. The Company has variable revenue that is subject
to factors outside the Company’s influence, such as market prices,
actions of third parties and weather conditions. The Company
considers this variable revenue to be "constrained" as it cannot be
reliably estimated, and therefore recognizes variable revenue when
the service is provided.
The new guidance also requires additional disclosures about the
nature, amount, timing and uncertainty of revenue recognition and
related cash flows.
In the application of the new guidance, significant estimates
and judgments are used to determine the following:
- pattern of revenue recognition within a contract, based on
whether the performance obligation is satisfied at a point in time
versus over time
- term of the contract
- amount of variable consideration associated with a contract and
timing of the associated revenue recognition.
The new guidance was effective January 1, 2018, was applied
using the modified retrospective transition method, and did not
result in any material differences in the amount and timing of
revenue recognition. Refer to Note 4, Revenues, for further
information related to the impact of adopting the new guidance and
the Company's updated accounting policies related to revenue
recognition from contracts with customers.
Financial instruments
In January 2016, the FASB issued new guidance on the accounting for
equity investments and financial liabilities. The new guidance
changes the income statement effect of equity investments and the
recognition of changes in the fair value of financial liabilities
when the fair value option is elected. The new guidance also
requires the Company to assess valuation allowances for deferred
tax assets related to available for sale debt securities in
combination with their other deferred tax assets. This new guidance
was effective January 1, 2018 and did not have a material impact on
the Company's consolidated financial statements.
Income taxes
In October 2016, the FASB issued new guidance on the income tax
effects of intra-entity transfers of assets other than inventory.
The new guidance requires the recognition of deferred and current
income taxes for intra-entity asset transfers when the transfer
occurs. The new guidance was effective January 1, 2018, was applied
using a modified retrospective approach, and did not have a
material impact on the Company's consolidated financial
statements.
Restricted cash
In November 2016, the FASB issued new guidance on restricted cash
and cash equivalents on the statement of cash flows. The new
guidance requires that the statement of cash flows explain the
change during the period in the total cash and cash equivalents
balance, and amounts generally described as restricted cash or
restricted cash equivalents. Restricted cash and cash equivalents
will be included with cash and cash equivalents when reconciling
the beginning of period and end of period total amounts on the
statement of cash flows. This new guidance was effective January 1,
2018, was applied retrospectively, and did not have an impact on
the Company's consolidated financial statements.
Employee post-retirement benefits
In March 2017, the FASB issued new guidance that requires entities
to disaggregate the current service cost component from the other
components of net benefit cost and present it with other current
compensation costs for related employees in the income statement.
The new guidance also requires that the other components of net
benefit cost be presented elsewhere in the income statement and
excluded from income from operations if such a subtotal is
presented. In addition, the new guidance makes changes to the
components of net benefit cost that are eligible for
capitalization. Entities must use a retrospective transition method
to adopt the requirement for separate presentation in the income
statement of the components of net benefit cost, and a prospective
transition method to adopt the change to capitalization of benefit
costs. This new guidance was effective January 1, 2018 and did not
have a material impact on the Company's consolidated financial
statements.
Hedge accounting
In August 2017, the FASB issued new guidance making more financial
and non-financial hedging strategies eligible for hedge accounting.
The new guidance also amends the presentation requirements relating
to the change in fair value of a derivative and requires additional
disclosures including cumulative basis adjustments for fair value
hedges and the effect of hedging on individual line items in the
statement of income. This new guidance is effective January 1, 2019
with early adoption permitted. This new guidance, which the Company
elected to adopt effective January 1, 2018, was applied
prospectively and did not have a material impact on the Company's
consolidated financial statements.
FUTURE ACCOUNTING CHANGES
Leases
In 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 lessor
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 12 months.
Leases will be classified as finance or operating, with
classification affecting the pattern of expense recognition in the
statement of income. The new guidance does not make extensive
changes to lessor accounting.
In January 2018, the FASB issued an optional practical
expedient, to be applied upon transition, to omit the evaluation of
land easements not previously accounted for as leases that existed
or expired prior to the entity's adoption of the new lease
guidance. An entity that elects this practical expedient is
required to apply the practical expedient consistently to all of
its existing or expired land easements not previously accounted for
as leases. The Company intends to apply this practical expedient
upon transition to the new standard.
The new guidance is effective January 1, 2019, with early
adoption permitted. The Company will adopt the new standard on its
effective date. A modified retrospective transition approach is
required, applying the new standard to all leases existing at the
date of initial application. In July 2018, the FASB issued a
transition option allowing entities to not apply the new guidance,
including disclosure requirements, to the comparative periods they
present in their financial statements in the year of adoption. The
Company will apply this transition option and therefore will not be
required to update financial information and disclosures for dates
and periods prior to January 1, 2019.
The Company will elect the package of practical expedients which
permits entities not to reassess prior conclusions about lease
identification, lease classification and initial direct costs under
the rules of the new standard. The Company continues to monitor and
analyze other optional practical expedients as well as additional
guidance and clarifications provided by the FASB.
The Company has developed an inventory of existing lease
agreements, has substantially completed its analysis on them, but
continues to refine its view of what qualifies as a lease and
evaluate the financial impact on its consolidated financial
statements. The Company has also selected a system solution and
continues to progress through the testing stage of implementation.
The Company continues to assess process changes necessary to
compile the information to meet the recognition and disclosure
requirements of the new guidance and to analyze new contracts that
may contain leases.
Measurement of credit losses on financial
instruments
In 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.
Goodwill impairment
In January 2017, the FASB issued new guidance on simplifying the
test for goodwill impairment by eliminating Step 2 of the
impairment test, which is the requirement to calculate the implied
fair value of goodwill to measure the impairment charge. Instead,
entities will record an impairment charge based on the excess of a
reporting unit’s carrying amount over its fair value. This new
guidance is effective January 1, 2020 and will be applied
prospectively, however, early adoption is permitted. The Company is
currently evaluating the timing and impact of the adoption of this
guidance.
Income taxes
In February 2018, the FASB issued new guidance that allows a
reclassification from AOCI to retained earnings for stranded tax
effects resulting from the U.S. Tax Reform. This new guidance is
effective January 1, 2019, however, early adoption is permitted.
This guidance can be applied either in the period of adoption or
retrospectively to each period (or periods) in which the effect of
the change is recognized. The Company is currently evaluating this
guidance in conjunction with its analysis of the overall impact of
U.S. Tax Reform.
Fair value measurement
In 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 is currently
evaluating the timing and impact of adoption of this guidance and
has not yet determined the effect on its consolidated financial
statements.
Defined benefit plans
In 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. The Company is currently evaluating the timing
and impact of the adoption of this guidance.
Implementation costs of cloud computing
arrangements
In 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.
3. Segmented information
three months ended
September 30, 2018 |
|
Canadian
Natural Gas Pipelines |
|
U.S. Natural
Gas Pipelines |
|
Mexico
Natural Gas Pipelines |
|
Liquids
Pipelines |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
Energy |
|
Corporate1 |
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
934 |
|
|
967 |
|
|
156 |
|
|
564 |
|
|
535 |
|
|
— |
|
|
3,156 |
|
Intersegment revenues |
|
— |
|
|
40 |
|
|
— |
|
|
— |
|
|
3 |
|
|
(43 |
) |
2 |
— |
|
|
|
934 |
|
|
1,007 |
|
|
156 |
|
|
564 |
|
|
538 |
|
|
(43 |
) |
|
3,156 |
|
Income/(loss) from equity investments |
|
3 |
|
|
62 |
|
|
8 |
|
|
22 |
|
|
112 |
|
|
(60 |
) |
3 |
147 |
|
Plant operating costs and other |
|
(356 |
) |
|
(313 |
) |
|
(11 |
) |
|
(160 |
) |
|
(79 |
) |
|
35 |
|
2 |
(884 |
) |
Commodity purchases resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(318 |
) |
|
— |
|
|
(318 |
) |
Property taxes |
|
(59 |
) |
|
(41 |
) |
|
— |
|
|
(24 |
) |
|
(3 |
) |
|
— |
|
|
(127 |
) |
Depreciation and amortization |
|
(255 |
) |
|
(170 |
) |
|
(26 |
) |
|
(86 |
) |
|
(27 |
) |
|
— |
|
|
(564 |
) |
Segmented
Earnings/(Loss) |
|
267 |
|
|
545 |
|
|
127 |
|
|
316 |
|
|
223 |
|
|
(68 |
) |
|
1,410 |
|
Interest expense |
|
(577 |
) |
Allowance for funds used during construction |
|
147 |
|
Interest income and
other3 |
|
168 |
|
Income before income taxes |
|
1,148 |
|
Income tax expense |
|
(120 |
) |
Net Income |
|
1,028 |
|
Net income attributable to
non-controlling interests |
|
(59 |
) |
Net Income Attributable to Controlling
Interests |
|
969 |
|
Preferred share dividends |
|
(41 |
) |
Net Income Attributable
to Common Shares |
|
928 |
|
1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted
rates. For segmented reporting, these transactions are included as
Intersegment revenues in the segment providing the service and
Plant operating costs and other in the segment receiving the
service. These transactions are eliminated on consolidation.
Intersegment profit is recognized when the product or service has
been provided to third parties or otherwise realized.
3 Income/(loss) from equity investments includes foreign
exchange 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 debt financing for this joint
venture.
three months ended
September 30, 2017 |
|
Canadian
Natural Gas Pipelines |
|
U.S. Natural
Gas Pipelines |
|
Mexico
Natural Gas Pipelines |
|
Liquids
Pipelines |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
Energy |
|
Corporate1 |
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
921 |
|
|
811 |
|
|
139 |
|
|
437 |
|
|
887 |
|
|
— |
|
|
3,195 |
|
Intersegment revenues |
|
— |
|
|
10 |
|
|
— |
|
|
— |
|
|
— |
|
|
(10 |
) |
2 |
— |
|
|
|
921 |
|
|
821 |
|
|
139 |
|
|
437 |
|
|
887 |
|
|
(10 |
) |
|
3,195 |
|
Income/(loss) from equity investments |
|
4 |
|
|
53 |
|
|
(11 |
) |
|
4 |
|
|
99 |
|
|
7 |
|
3 |
156 |
|
Plant operating costs and other |
|
(318 |
) |
|
(351 |
) |
|
(10 |
) |
|
(145 |
) |
|
(79 |
) |
|
(26 |
) |
2 |
(929 |
) |
Commodity purchases resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(621 |
) |
|
— |
|
|
(621 |
) |
Property taxes |
|
(63 |
) |
|
(41 |
) |
|
— |
|
|
(22 |
) |
|
(1 |
) |
|
— |
|
|
(127 |
) |
Depreciation and amortization |
|
(228 |
) |
|
(145 |
) |
|
(23 |
) |
|
(71 |
) |
|
(39 |
) |
|
— |
|
|
(506 |
) |
Loss on sales of assets |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(9 |
) |
|
— |
|
|
(9 |
) |
Segmented
Earnings/(Loss) |
|
316 |
|
|
337 |
|
|
95 |
|
|
203 |
|
|
237 |
|
|
(29 |
) |
|
1,159 |
|
Interest expense |
|
(504 |
) |
Allowance for funds used during construction |
|
145 |
|
Interest income and
other3 |
|
84 |
|
Income before income taxes |
|
884 |
|
Income tax expense |
|
(188 |
) |
Net Income |
|
696 |
|
Net income attributable to
non-controlling interests |
|
(44 |
) |
Net Income Attributable to Controlling
Interests |
|
652 |
|
Preferred share dividends |
|
(40 |
) |
Net Income Attributable
to Common Shares |
|
612 |
|
1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted
rates. For segmented reporting, these transactions are included as
Intersegment revenues in the segment providing the service and
Plant operating costs and other in the segment receiving the
service. These transactions are eliminated on consolidation.
Intersegment profit is recognized when the product or service has
been provided to third parties or otherwise realized.
3 Income/(loss) from equity investments includes foreign
exchange gains on the Company's inter-affiliate loan with Sur de
Texas. The offsetting foreign exchange losses on the
inter-affiliate loan are included in Interest income and other. The
peso-denominated loan to the Sur de Texas joint venture represents
the Company's proportionate share of debt financing for this joint
venture.
nine months ended
September 30, 2018 |
|
Canadian
Natural Gas Pipelines |
|
U.S. Natural
Gas Pipelines |
|
Mexico
Natural Gas Pipelines |
|
Liquids
Pipelines |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
Energy |
|
Corporate1 |
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
2,772 |
|
|
2,988 |
|
|
460 |
|
|
1,831 |
|
|
1,724 |
|
|
— |
|
|
9,775 |
|
Intersegment revenues |
|
— |
|
|
121 |
|
|
— |
|
|
— |
|
|
50 |
|
|
(171 |
) |
2 |
— |
|
|
|
2,772 |
|
|
3,109 |
|
|
460 |
|
|
1,831 |
|
|
1,774 |
|
|
(171 |
) |
|
9,775 |
|
Income/(loss) from equity investments |
|
9 |
|
|
188 |
|
|
20 |
|
|
50 |
|
|
277 |
|
|
(52 |
) |
3 |
492 |
|
Plant operating costs and other |
|
(1,020 |
) |
|
(925 |
) |
|
(25 |
) |
|
(506 |
) |
|
(250 |
) |
|
146 |
|
2 |
(2,580 |
) |
Commodity purchases resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(1,239 |
) |
|
— |
|
|
(1,239 |
) |
Property taxes |
|
(200 |
) |
|
(149 |
) |
|
— |
|
|
(74 |
) |
|
(6 |
) |
|
— |
|
|
(429 |
) |
Depreciation and amortization |
|
(761 |
) |
|
(489 |
) |
|
(73 |
) |
|
(254 |
) |
|
(92 |
) |
|
— |
|
|
(1,669 |
) |
Segmented
Earnings/(Loss) |
|
800 |
|
|
1,734 |
|
|
382 |
|
|
1,047 |
|
|
464 |
|
|
(77 |
) |
|
4,350 |
|
Interest expense |
|
(1,662 |
) |
Allowance for funds used during construction |
|
365 |
|
Interest income and
other3 |
|
139 |
|
Income before income taxes |
|
3,192 |
|
Income tax expense |
|
(394 |
) |
Net Income |
|
2,798 |
|
Net income attributable to
non-controlling interests |
|
(229 |
) |
Net Income Attributable to Controlling
Interests |
|
2,569 |
|
Preferred share dividends |
|
(122 |
) |
Net Income Attributable
to Common Shares |
|
2,447 |
|
1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted
rates. For segmented reporting, these transactions are included as
Intersegment revenues in the segment providing the service and
Plant operating costs and other in the segment receiving the
service. These transactions are eliminated on consolidation.
Intersegment profit is recognized when the product or service has
been provided to third parties or otherwise realized.
3 Income/(loss) from equity investments includes foreign
exchange 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 debt financing for this joint
venture.
nine months ended
September 30, 2017 |
|
Canadian
Natural Gas Pipelines |
|
U.S. Natural
Gas Pipelines |
|
Mexico
Natural Gas Pipelines |
|
Liquids
Pipelines |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
Energy |
|
Corporate1 |
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
2,725 |
|
|
2,684 |
|
|
432 |
|
|
1,410 |
|
|
2,581 |
|
|
— |
|
|
9,832 |
|
Intersegment revenues |
|
— |
|
|
31 |
|
|
— |
|
|
— |
|
|
— |
|
|
(31 |
) |
2 |
— |
|
|
|
2,725 |
|
|
2,715 |
|
|
432 |
|
|
1,410 |
|
|
2,581 |
|
|
(31 |
) |
|
9,832 |
|
Income/(loss) from equity investments |
|
9 |
|
|
175 |
|
|
— |
|
|
3 |
|
|
341 |
|
|
(1 |
) |
3 |
527 |
|
Plant operating costs and other |
|
(958 |
) |
|
(1,004 |
) |
|
(29 |
) |
|
(437 |
) |
|
(464 |
) |
|
(70 |
) |
2 |
(2,962 |
) |
Commodity purchases resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(1,711 |
) |
|
— |
|
|
(1,711 |
) |
Property taxes |
|
(201 |
) |
|
(136 |
) |
|
— |
|
|
(67 |
) |
|
(38 |
) |
|
— |
|
|
(442 |
) |
Depreciation and amortization |
|
(672 |
) |
|
(451 |
) |
|
(70 |
) |
|
(228 |
) |
|
(118 |
) |
|
— |
|
|
(1,539 |
) |
Gain on sales of assets |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
489 |
|
|
— |
|
|
489 |
|
Segmented
Earnings/(Loss) |
|
903 |
|
|
1,299 |
|
|
333 |
|
|
681 |
|
|
1,080 |
|
|
(102 |
) |
|
4,194 |
|
Interest expense |
|
(1,528 |
) |
Allowance for funds used during construction |
|
367 |
|
Interest income and
other3 |
|
193 |
|
Income before income taxes |
|
3,226 |
|
Income tax expense |
|
(781 |
) |
Net Income |
|
2,445 |
|
Net income attributable to
non-controlling interests |
|
(189 |
) |
Net Income Attributable to Controlling
Interests |
|
2,256 |
|
Preferred share dividends |
|
(120 |
) |
Net Income Attributable
to Common Shares |
|
2,136 |
|
1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted
rates. For segmented reporting, these transactions are included as
Intersegment revenues in the segment providing the service and
Plant operating costs and other in the segment receiving the
service. These transactions are eliminated on consolidation.
Intersegment profit is recognized when the product or service has
been provided to third parties or otherwise realized.
3 Income/(loss) from equity investments includes foreign
exchange 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 debt financing for this joint
venture.
TOTAL ASSETS
(unaudited - millions of Canadian $) |
|
September 30,
2018 |
|
December 31,
2017 |
|
|
|
|
|
Canadian Natural Gas Pipelines |
|
17,900 |
|
|
16,904 |
|
U.S. Natural Gas Pipelines |
|
41,045 |
|
|
35,898 |
|
Mexico Natural Gas Pipelines |
|
6,403 |
|
|
5,716 |
|
Liquids Pipelines |
|
16,277 |
|
|
15,438 |
|
Energy |
|
8,559 |
|
|
8,503 |
|
Corporate |
|
3,993 |
|
|
3,642 |
|
|
|
94,177 |
|
|
86,101 |
|
4. Revenues
In 2014, the FASB issued new guidance on revenue from contracts
with customers. The Company adopted the new guidance on January 1,
2018 using the modified retrospective transition method for all
contracts that were in effect on the date of adoption. Results
reported for 2018 reflect the application of the new guidance,
while the 2017 comparative results were prepared and reported under
previous revenue recognition guidance which is referred to herein
as "legacy U.S. GAAP."
DISAGGREGATION OF REVENUES
The following tables summarize total Revenues for the three and
nine months ended September 30, 2018:
three months ended September 30,
2018
(unaudited - millions of Canadian $) |
Canadian
Natural
Gas
Pipelines |
U.S.
Natural
Gas
Pipelines |
Mexico
Natural
Gas
Pipelines |
Liquids
Pipelines |
Energy |
Total |
|
|
|
|
|
|
|
Revenues from contracts with customers |
|
|
|
|
|
|
Capacity arrangements and transportation |
934 |
|
788 |
|
155 |
|
511 |
|
— |
|
2,388 |
|
Power generation |
— |
|
— |
|
— |
|
— |
|
450 |
|
450 |
|
Natural gas storage and other |
— |
|
158 |
|
1 |
|
1 |
|
4 |
|
164 |
|
|
934 |
|
946 |
|
156 |
|
512 |
|
454 |
|
3,002 |
|
Other revenues1,2 |
— |
|
21 |
|
— |
|
52 |
|
81 |
|
154 |
|
|
934 |
|
967 |
|
156 |
|
564 |
|
535 |
|
3,156 |
|
1 Other revenues include income from the Company's
marketing activities, financial instruments and lease arrangements
within each operating segment. Income from lease arrangements
includes certain long term PPAs, as well as certain liquids
pipelines capacity and transportation arrangements. These
arrangements are not in the scope of the new guidance, therefore,
revenues related to these contracts are excluded from revenues from
contracts with customers. Refer to Note 12, Risk management and
financial instruments, for further information on income from
financial instruments.
2 Other revenues from U.S. Natural Gas Pipelines include
the amortization of the net regulatory liabilities resulting from
U.S. Tax Reform. Refer to Note 7, Income taxes, for further
information.
nine months ended September 30,
2018
(unaudited - millions of Canadian $) |
Canadian
Natural
Gas
Pipelines |
U.S.
Natural
Gas
Pipelines |
Mexico
Natural
Gas
Pipelines |
Liquids
Pipelines |
Energy |
Total |
|
|
|
|
|
|
|
Revenues from contracts with customers |
|
|
|
|
|
|
Capacity arrangements and transportation |
2,772 |
|
2,457 |
|
457 |
|
1,558 |
|
— |
|
7,244 |
|
Power generation |
— |
|
— |
|
— |
|
— |
|
1,455 |
|
1,455 |
|
Natural gas storage and other |
— |
|
468 |
|
3 |
|
2 |
|
65 |
|
538 |
|
|
2,772 |
|
2,925 |
|
460 |
|
1,560 |
|
1,520 |
|
9,237 |
|
Other revenues1,2 |
— |
|
63 |
|
— |
|
271 |
|
204 |
|
538 |
|
|
2,772 |
|
2,988 |
|
460 |
|
1,831 |
|
1,724 |
|
9,775 |
|
1 Other revenues include income from the Company's
marketing activities, financial instruments and lease arrangements
within each operating segment. Income from lease arrangements
includes certain long term PPAs, as well as certain liquids
pipelines capacity and transportation arrangements. These
arrangements are not in the scope of the new guidance, therefore,
revenues related to these contracts are excluded from revenues from
contracts with customers. Refer to Note 12, Risk management and
financial instruments, for further information on income from
financial instruments.
2 Other revenues from U.S. Natural Gas Pipelines include
the amortization of the net regulatory liabilities resulting from
U.S. Tax Reform. Refer to Note 7, Income taxes, for further
information.
Revenues from contracts with customers are recognized net of any
taxes collected from customers which are subsequently remitted to
governmental authorities. The Company's contracts with customers
include natural gas and liquids pipelines capacity arrangements and
transportation contracts, power generation contracts, natural gas
storage and other contracts.
Canadian Natural Gas Pipelines
Capacity Arrangements and
Transportation
Revenues from the Company's Canadian natural gas pipelines are
generated from contractual arrangements for committed capacity and
from the transportation of natural gas. Revenues earned from firm
contracted capacity arrangements are recognized ratably over the
term of the contract regardless of the amount of natural gas that
is transported. Transportation revenues for interruptible or
volumetric-based services are recognized when the service is
performed.
Revenues from the Company's Canadian natural gas pipelines are
subject to regulatory decisions by the NEB. The tolls charged on
these pipelines are based on revenue requirements designed to
recover the costs of providing natural gas capacity for
transportation services, which includes a return of and return on
capital, as approved by the NEB. The Company's Canadian natural gas
pipelines are generally not subject to risks related to variances
in revenues and most costs. These variances are generally subject
to deferral treatment and are recovered or refunded in future
tolls. Revenues recognized prior to an NEB decision on rates for
that period reflect the NEB's last approved ROE assumptions.
Adjustments to revenues are recorded when the NEB decision
is received. Canadian natural gas pipelines' revenues are
invoiced and received on a monthly basis. The Company does not take
ownership of the natural gas that it transports for customers.
U.S. Natural Gas Pipelines
Capacity Arrangements and
Transportation
Revenues from the Company's U.S. natural gas pipelines are
generated from contractual arrangements for committed capacity and
from the transportation of natural gas. Revenues earned from firm
contracted capacity arrangements are generally recognized ratably
over the term of the contract regardless of the amount of natural
gas that is transported. Transportation revenues for interruptible
or volumetric-based services are recognized when the service is
performed. The Company has elected to utilize the practical
expedient to recognize revenues from its U.S. natural gas pipelines
as invoiced.
The Company's U.S. natural gas pipelines are subject to
FERC regulations and, as a result, a portion of revenues collected
may be subject to refund if invoiced during an interim period when
a rate proceeding is ongoing. Allowances for these potential
refunds are recognized using management's best estimate based on
the facts and circumstances of the proceeding. Any allowances
that are recognized during the proceeding process are refunded or
retained at the time a regulatory decision becomes final. U.S.
natural gas pipelines' revenues are invoiced and received on a
monthly basis. The Company does not take ownership of the natural
gas that it transports for customers.
Natural Gas Storage and Other
Revenues from the Company's regulated U.S. natural gas storage
services are generated mainly from firm committed capacity storage
contracts. The performance obligation in these contracts is the
reservation of a specified amount of capacity for storage including
specifications with regards to the amount of natural gas that can
be injected or withdrawn on a daily basis. Revenues are recognized
ratably over the contract period for firm committed capacity
regardless of the amount of natural gas that is stored, and when
gas is injected or withdrawn for interruptible or volumetric-based
services. Natural gas storage services revenues are invoiced and
received on a monthly basis. The Company does not take ownership of
the natural gas that it stores for customers.
Revenues from the Company's midstream natural gas services,
including gathering, treating, conditioning, processing,
compression and liquids handling services, are generated from
contractual arrangements and are recognized ratably over the term
of the contract. The Company also owns mineral rights associated
with certain natural gas storage facilities. These mineral rights
can be leased or contributed to producers of natural gas in return
for a royalty interest which is recognized when natural gas and
associated liquids are produced. Midstream natural gas service
revenues are invoiced and received on a monthly basis. The Company
does not take ownership of the natural gas for which it provides
midstream services.
Mexico Natural Gas Pipelines
Capacity Arrangements and
Transportation
Revenues from the Company's Mexico natural gas pipelines are
primarily collected based on CRE-approved negotiated firm capacity
contracts and are generally recognized ratably over the term of the
contract. For certain firm capacity arrangements, the Company has
elected to utilize the practical expedient to recognize revenues as
invoiced. Transportation revenues related to interruptible or
volumetric-based services are recognized when the service is
performed. Other volumes shipped on these pipelines are subject to
CRE-approved tariffs and revenues are recognized when the Company
has performed the transportation services. Mexico natural gas
pipelines' revenues are invoiced and received on a monthly basis.
The Company does not take ownership of the natural gas that it
transports for customers.
Liquids Pipelines
Capacity Arrangements and
Transportation
Revenues from the Company's liquids pipelines are generated mainly
from providing customers with firm capacity arrangements to
transport crude oil. The performance obligation in these contracts
is the reservation of a specified amount of capacity together with
the transportation of crude oil on a monthly basis. Revenues earned
from these arrangements are recognized ratably over the term of the
contract regardless of the amount of crude oil that is transported.
Revenues for interruptible or volumetric-based services are
recognized when the service is performed. Liquids pipelines'
revenues are invoiced and received on a monthly basis. The Company
does not take ownership of the crude oil that it transports for
customers.
Energy
Power Generation
Revenues from the Company's Energy business are primarily derived
from long-term contractual commitments to provide power capacity to
meet the demands of the market, and from the sale of electricity to
both centralized markets and to customers. Power generation
revenues also include revenues from the sale of steam to customers.
Revenues and capacity payments are recognized as the services are
provided and as electricity and steam is delivered. Power
generation revenues are invoiced and received on a monthly
basis.
Natural Gas Storage and Other
Non-regulated natural gas storage contracts include park, loan and
term storage arrangements. Park and loan contracts allow for fixed
injection or withdrawal volumes on specified dates for a specified
price. Term storage contracts allow for a maximum amount of gas to
be stored over a set period of time. Revenues from park and loan
contracts are recognized and invoiced as the injection and
withdrawal services are provided and revenues from term storage
contracts are recognized ratably over the term of the contract.
Term storage revenues are invoiced and received on a monthly basis.
Revenues earned from the sale of proprietary natural gas are
recognized in the month of delivery. Revenues from ancillary
services are recognized as the service is provided. The Company
does not take ownership of the natural gas that it stores for
customers.
FINANCIAL STATEMENT IMPACT OF ADOPTING REVENUE FROM
CONTRACTS WITH CUSTOMERS
The Company adopted the new guidance using the modified
retrospective transition method. As a practical expedient under
this transition method, the Company is not required to analyze
completed contracts at the date of adoption. As a result, the
Company made the following adjustments on January 1, 2018.
Capacity Arrangements and
Transportation
For certain natural gas pipelines capacity contracts, amounts are
invoiced to the customer in accordance with the terms of the
contract, however, the related revenues are recognized when the
Company satisfies its performance obligation to provide committed
capacity ratably over the term of the contract. This difference in
timing between revenue recognition and amounts invoiced creates a
contract asset or contract liability under the new revenue
recognition guidance. Under legacy U.S. GAAP, this difference was
recorded as Accounts receivable. Under the new guidance, contract
assets are included in Other current assets and Intangibles and
other assets and contract liabilities are included in Accounts
payable and other and Other long-term liabilities.
Impact of New Revenue Recognition Guidance on Date of
Adoption
The following table illustrates the impact of the adoption of the
new revenue recognition guidance on the Company's previously
reported consolidated balance sheet line items:
|
As
reported |
Adjustment |
|
(unaudited - millions of Canadian $) |
December 31,
2017 |
January 1,
2018 |
|
|
|
|
Current Assets |
|
|
|
Accounts receivable |
2,522 |
|
(62 |
) |
2,460 |
|
Other1 |
691 |
|
79 |
|
770 |
|
Current Liabilities |
|
|
|
Accounts payable and other2 |
4,057 |
|
17 |
|
4,074 |
|
1 Adjustment relates to contract assets previously
included in Accounts receivable.
2 Adjustment relates to contract liabilities previously
included in Accounts receivable.
Pro-forma Financial Statements under Legacy U.S.
GAAP
As required by the new revenue recognition guidance, the following
tables illustrate the pro-forma impact on the affected line items
on the Condensed consolidated balance sheet, as at
September 30, 2018, using legacy U.S. GAAP:
|
September 30,
2018 |
|
As
reported |
|
Pro-forma
using legacy
U.S. GAAP |
(unaudited - millions of Canadian $) |
|
|
|
|
Current Assets |
|
|
|
Accounts receivable |
2,170 |
|
|
2,460 |
|
Other |
1,003 |
|
|
713 |
|
|
|
|
|
|
|
CONTRACT BALANCES |
|
|
|
|
|
(unaudited - millions of Canadian $) |
September 30,
2018 |
|
|
January
1, 2018 |
|
Receivables from contracts with customers |
1,208 |
|
|
1,736 |
|
Contract assets1 |
290 |
|
|
79 |
|
Long-term contract assets2 |
35 |
|
|
— |
|
Contract liabilities3 |
41 |
|
|
17 |
|
Long-term contract
liabilities4 |
27 |
|
|
— |
|
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 nine months ended September 30, 2018, $17 million
of revenue was recognized that was included in the contract
liability 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 remains 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
As required by the new revenue recognition guidance, the following
provides disclosure on future revenues allocated to remaining
performance obligations representing contracted revenues that have
not yet been recognized. Certain contracts that qualify for the use
of one of the following practical expedients are excluded from the
future revenues disclosures:
1) The original expected duration of the contract is one
year or less.
2) The Company recognizes revenue from the contract that
is equal to the amount invoiced, where the amount invoiced
represents the value to the customer of the service performed to
date. This is referred to as the "right to invoice" practical
expedient.
3) The variable revenue generated from the contract is
allocated entirely to a wholly unsatisfied performance obligation
or to a wholly unsatisfied promise to transfer a distinct good or
service that forms part of a single performance obligation in a
series. A single performance obligation in a series occurs when the
promises under a contract are a series of distinct services that
are substantially the same and have the same pattern of transfer to
the customer over time.
The following provides a discussion of the transaction price
allocated to future performance obligations as well as practical
expedients used by the Company.
Capacity Arrangements and Transportation
As at September 30, 2018, future revenues from long-term
capacity arrangements and transportation contracts extending
through 2043 are approximately $28.0 billion, of which
approximately $1.4 billion is expected to be recognized during the
remainder of 2018.
Future revenues from long-term capacity arrangements and
transportation contracts do not include constrained variable
revenues or arrangements to which the right to invoice practical
expedient has been applied. As a result, these amounts are not
representative of potential total future revenues expected from
these contracts.
Future revenues from the Company's Canadian natural gas
pipelines' regulated firm capacity contracts include fixed revenues
for the time periods that tolls under current rate settlements are
in effect, which is approximately one to three years. Many of these
contracts are long-term in nature and revenues from the remaining
performance obligations that extend beyond the current rate
settlement term are considered to be fully constrained since future
tolls remain unknown. Revenues from these contracts will be
recognized once the performance obligation to provide capacity has
been satisfied and the regulator has approved the applicable tolls.
In addition, the Company considers interruptible transportation
service revenues to be variable revenues since volumes cannot be
estimated. These variable revenues are recognized on a monthly
basis when the Company satisfies the performance obligation and
have been excluded from the future revenues disclosure as the
Company applies the practical expedient related to variable
revenues to these contracts. The future variable revenues earned
under these contracts are allocated entirely to unsatisfied
performance obligations at September 30, 2018.
The Company also applies the right to invoice practical
expedient to all of its U.S. and certain of its Mexico regulated
natural gas pipeline capacity arrangements and flow-through
revenues. Revenues from regulated capacity arrangements are
recognized based on current rates and flow-through revenues are
earned from the recovery of operating expenses. These revenues are
recognized on a monthly basis as the Company performs the services
and are excluded from future revenues disclosures.
Revenues from liquids pipelines capacity arrangements have a
variable component based on volumes transported. As a result, these
variable revenues are excluded from the future revenues disclosures
as the Company applies the practical expedient related to variable
revenues to these contracts. The future variable revenues earned
under these contracts is allocated entirely to unsatisfied
performance obligations at September 30, 2018.
Power Generation
The Company has long-term power generation contracts extending
through 2032. Revenues from power generation 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. The Company applies
the practical expedient related to variable revenues to these
contracts. As a result, future revenues from these contracts are
excluded from the disclosures.
Natural Gas Storage and Other
As at September 30, 2018, future revenues from long-term
natural gas storage and other contracts extending through 2033 are
approximately $1.2 billion, of which approximately $127 million is
expected to be recognized during the remainder of 2018. The Company
applies the practical expedients related to contracts that are for
a duration of one year or less and where it recognizes variable
consideration, and therefore excludes the related revenues from the
future revenues disclosure. As a result, this amount is lower than
the potential total future revenues from these contracts.
5. Assets held for sale
Cartier Wind
On August 1, 2018, TransCanada entered into an agreement to sell
its interests in the Cartier Wind power facilities in Québec to
Innergex Renewable Energy Inc. At September 30, 2018, the related
assets and liabilities were classified as held for sale in the
Energy segment. Subsequently, on October 24, 2018, the Company
closed the sale for gross proceeds of approximately $630 million
before closing adjustments, resulting in an estimated gain of $170
million ($135 million after tax) to be recognized in fourth quarter
2018.
At September 30, 2018, the related assets and liabilities in the
Energy segment were classified as held for sale as follows:
|
|
|
(unaudited - millions of Canadian $) |
|
|
|
|
|
Assets held for sale |
|
|
Plant, property and equipment |
|
458 |
|
Total assets held for
sale |
|
458 |
|
Liabilities related to assets held for sale |
|
|
Other long-term liabilities |
|
14 |
|
Total liabilities related to assets
held for sale1 |
|
14 |
|
1 Included in Accounts payable and other on the
Condensed consolidated balance sheet.
6. Plant, Property and Equipment, Equity Investments and
Goodwill
The Company reviews plant, property and equipment and equity
investments for impairment whenever events or changes in
circumstances indicate the carrying value of the asset may not be
recoverable.
Goodwill is tested for impairment on an annual basis or more
frequently if events or changes in circumstance indicate that it
might be impaired. The Company can initially make this assessment
based on qualitative factors. If the Company concludes that it is
not more likely than not that the fair value of the reporting unit
is less than its carrying value, then an impairment test is not
performed.
In March 2018, FERC proposed changes related to U.S. Tax Reform
and income taxes for rate-making purposes in a master limited
partnership (MLP) that may have an impact on the future earnings
and cash flows of FERC-regulated pipelines. On July 18, 2018, FERC
issued final rulings (Final Rule) with respect to these changes.
The March and July 2018 FERC proposed changes and Final Rule are
collectively referred to herein as the "2018 FERC Actions."
The Company continues to monitor developments following the
Final Rule on the 2018 FERC Actions. TransCanada will incorporate
results to date, future filings for individual pipelines, as well
as FERC responses to others in the industry into its annual
goodwill impairment tests as well as its normal review of plant,
property and equipment and equity investments for
recoverability.
As at September 30, 2018, the goodwill balances related to Great
Lakes and Tuscarora are US$573 million and US$82 million
(December 31, 2017 – US$573 million and US$82 million),
respectively. At December 31, 2017, the estimated fair value of
Great Lakes exceeded its carrying value by less than 10 per cent.
There is a risk that the goodwill balances related to both of these
assets could be negatively impacted by the FERC developments, once
finalized, or by other changes in management's estimates of fair
value resulting in a goodwill impairment charge.
7. Income taxes
U.S. Tax Reform
Pursuant to the enactment of U.S. Tax Reform, the Company recorded
net regulatory liabilities and a corresponding reduction in net
deferred income tax liabilities in the amount of $1,686 million at
December 31, 2017 related to the Company's U.S. natural gas
pipelines subject to RRA. Amounts recorded to adjust income taxes
remain provisional as the Company's interpretation, assessment and
presentation of the impact of U.S. Tax Reform may be further
clarified with additional guidance from tax authorities. Should
additional guidance be provided by tax authorities during the
one-year measurement period permitted by the SEC, the Company will
review the provisional amounts and adjust as appropriate.
Commencing January 1, 2018, the Company has amortized the net
regulatory liabilities using the Reverse South Georgia methodology.
Under this methodology, rate-regulated entities determine and
immediately begin recording amortization based on their composite
depreciation rates. Amortization of the net regulatory liabilities
in the amount of $12 million and $36 million was recorded for the
three and nine months ended September 30, 2018, respectively,
and included in Revenues in the Condensed consolidated statement of
income. Once the final impact of the 2018 FERC Actions is
determined there may be prospective adjustments to the Company's
net regulatory liabilities.
Effective Tax Rates
The effective income tax rates for the nine-month periods ended
September 30, 2018 and 2017 were 12 per cent and 24 per cent,
respectively. The lower effective tax rate in 2018 was primarily
the result of the rate change resulting from U.S. Tax Reform and
lower flow-through income taxes in Canadian rate-regulated
pipelines.
8. Long-term debt
LONG-TERM DEBT ISSUED
The Company issued long-term debt in the nine months ended
September 30, 2018 as follows:
(unaudited - millions of Canadian
$, unless noted otherwise) |
|
|
|
|
|
|
|
|
|
Company |
|
Issue date |
|
Type |
|
Maturity Date |
|
Amount |
|
Interest
rate |
|
|
|
|
|
|
|
|
|
|
|
TRANSCANADA PIPELINES LIMITED |
|
|
|
|
|
|
|
|
|
|
July 2018 |
|
Medium Term Notes |
|
July 2048 |
|
800 |
|
|
4.18 |
% |
|
|
July 2018 |
|
Medium Term Notes |
|
March 2028 |
|
200 |
|
|
3.39 |
% |
|
|
May
2018 |
|
Senior Unsecured Notes |
|
May
2028 |
|
US 1,000 |
|
|
4.25 |
% |
|
|
May
2018 |
|
Senior Unsecured Notes |
|
May
2038 |
|
US 500 |
|
|
4.75 |
% |
|
|
May 2018 |
|
Senior Unsecured Notes |
|
May 2048 |
|
US 1,000 |
|
|
4.875 |
% |
LONG-TERM DEBT RETIRED
The Company retired long-term debt in the nine months ended
September 30, 2018 as follows:
(unaudited -
millions of Canadian $, unless noted otherwise) |
|
|
|
|
|
|
|
|
Company |
|
Retirement date |
|
Type |
|
Amount |
|
Interest rate |
|
|
|
|
|
|
|
|
|
COLUMBIA PIPELINE GROUP, INC. |
|
|
|
|
|
|
|
|
June 2018 |
|
Senior Unsecured
Notes |
|
US 500 |
|
|
2.45 |
% |
PORTLAND NATURAL GAS TRANSMISSION SYSTEM |
|
|
|
|
|
|
|
|
May 2018 |
|
Senior Secured
Notes |
|
US
18 |
|
|
5.90 |
% |
TRANSCANADA PIPELINES LIMITED |
|
|
|
|
|
|
|
|
August 2018 |
|
Senior Unsecured
Notes |
|
US
850 |
|
|
6.50 |
% |
|
|
March 2018 |
|
Debentures |
|
150 |
|
|
9.45 |
% |
|
|
January 2018 |
|
Senior Unsecured
Notes |
|
US
500 |
|
|
1.875 |
% |
|
|
January 2018 |
|
Senior Unsecured
Notes |
|
US
250 |
|
|
Floating |
|
GREAT LAKES GAS TRANSMISSION LIMITED
PARTNERSHIP |
|
|
|
|
|
|
March
2018 |
|
Senior
Unsecured Notes |
|
US 9 |
|
|
6.73 |
% |
CAPITALIZED INTEREST
In the three and nine months ended September 30, 2018,
TransCanada capitalized interest related to capital projects of $33
million and $89 million, respectively (2017 – $49 million and $150
million, respectively).
9. Common shares
TRANSCANADA CORPORATION ATM EQUITY PROGRAM
In the three months ended September 30, 2018, the Company
issued 6.1 million common shares under the TransCanada ATM program
at an average price of $57.75 per common share for proceeds of $351
million, net of related commissions and fees of approximately $3
million. In the nine months ended September 30, 2018, 20.0 million
common shares have been issued at an average price of $56.13 per
common share for proceeds of $1.1 billion, net of approximately $10
million of related commissions and fees.
In June 2018, the Company replenished the capacity available
under its existing Corporate ATM program. This allows for the
issuance of additional common shares from treasury for an aggregate
gross sales price of up to $1.0 billion, for a revised total of
$2.0 billion or its U.S. dollar equivalent. The Corporate ATM
program, as amended, is effective to July 23, 2019.
10. 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 September 30,
2018 |
|
|
|
Income Tax |
|
|
(unaudited - millions of Canadian $) |
|
Before Tax
Amount |
|
Recovery/
(Expense) |
|
Net of Tax
Amount |
|
|
|
|
|
|
|
Foreign currency translation losses on net investment in foreign
operations |
|
(273 |
) |
|
(9 |
) |
|
(282 |
) |
Change in fair value of net investment hedges |
|
12 |
|
|
(3 |
) |
|
9 |
|
Change in fair value of cash flow hedges |
|
5 |
|
|
(1 |
) |
|
4 |
|
Reclassification to net income of gains and losses on cash flow
hedges |
|
8 |
|
|
(2 |
) |
|
6 |
|
Reclassification of actuarial gains and losses on pension and other
post-retirement benefit plans |
|
4 |
|
|
6 |
|
|
10 |
|
Other comprehensive income on equity
investments |
|
7 |
|
|
(1 |
) |
|
6 |
|
Other comprehensive loss |
|
(237 |
) |
|
(10 |
) |
|
(247 |
) |
three months ended September 30,
2017 |
|
|
|
Income Tax |
|
|
(unaudited - millions of Canadian $) |
|
Before Tax
Amount |
|
Recovery/
(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 |
|
(1 |
) |
|
— |
|
|
(1 |
) |
Change in fair value of cash flow hedges |
|
1 |
|
|
— |
|
|
1 |
|
Unrealized actuarial gains and losses on pension and other
post-retirement benefit plans |
|
5 |
|
|
(3 |
) |
|
2 |
|
Reclassification of actuarial gains and losses on pension and other
post-retirement benefit plans |
|
6 |
|
|
(2 |
) |
|
4 |
|
Other comprehensive income on equity
investments |
|
4 |
|
|
(1 |
) |
|
3 |
|
Other comprehensive loss |
|
(349 |
) |
|
(12 |
) |
|
(361 |
) |
nine months ended September 30,
2018 |
|
|
|
Income Tax |
|
|
(unaudited - millions of Canadian $) |
|
Before Tax
Amount |
|
Recovery/
(Expense) |
|
Net of Tax
Amount |
|
|
|
|
|
|
|
Foreign currency translation gains on net investment in foreign
operations |
|
397 |
|
|
12 |
|
|
409 |
|
Change in fair value of net investment hedges |
|
(8 |
) |
|
2 |
|
|
(6 |
) |
Change in fair value of cash flow hedges |
|
8 |
|
|
1 |
|
|
9 |
|
Reclassification to net income of gains and losses on cash flow
hedges |
|
21 |
|
|
(5 |
) |
|
16 |
|
Reclassification of actuarial gains and losses on pension and other
post-retirement benefit plans |
|
12 |
|
|
(2 |
) |
|
10 |
|
Other comprehensive income on equity
investments |
|
20 |
|
|
(2 |
) |
|
18 |
|
Other comprehensive
income |
|
450 |
|
|
6 |
|
|
456 |
|
nine months ended September 30,
2017 |
|
|
|
Income Tax |
|
|
(unaudited - millions of Canadian $) |
|
Before Tax
Amount |
|
Recovery/
(Expense) |
|
Net of Tax
Amount |
|
|
|
|
|
|
|
Foreign currency translation losses on net investment in foreign
operations |
|
(717 |
) |
|
(4 |
) |
|
(721 |
) |
Reclassification of foreign currency translation gains on net
investment on disposal of foreign operations |
|
(77 |
) |
|
— |
|
|
(77 |
) |
Change in fair value of net investment hedges |
|
(4 |
) |
|
1 |
|
|
(3 |
) |
Change in fair value of cash flow hedges |
|
5 |
|
|
(1 |
) |
|
4 |
|
Reclassification to net income of gains and losses on cash flow
hedges |
|
(2 |
) |
|
1 |
|
|
(1 |
) |
Unrealized actuarial gains and losses on pension and other
post-retirement benefit plans |
|
5 |
|
|
(3 |
) |
|
2 |
|
Reclassification of actuarial gains and losses on pension and other
post-retirement benefit plans |
|
16 |
|
|
(5 |
) |
|
11 |
|
Other comprehensive income on equity
investments |
|
8 |
|
|
(2 |
) |
|
6 |
|
Other comprehensive loss |
|
(766 |
) |
|
(13 |
) |
|
(779 |
) |
The changes in AOCI by component are as
follows:
three months ended September 30,
2018 |
|
Currency |
|
|
|
Pension and |
|
|
|
|
(unaudited - millions of Canadian $) |
|
Translation
Adjustments |
|
Cash Flow
Hedges |
|
OPEB Plan
Adjustments |
|
Equity
Investments |
|
Total1 |
|
|
|
|
|
|
|
|
|
|
|
AOCI balance at July 1, 2018 |
|
(462 |
) |
|
(26 |
) |
|
(203 |
) |
|
(443 |
) |
|
(1,134 |
) |
Other comprehensive (loss)/income before
reclassifications2 |
|
(239 |
) |
|
3 |
|
|
— |
|
|
— |
|
|
(236 |
) |
Amounts reclassified from
AOCI3 |
|
— |
|
|
5 |
|
|
10 |
|
|
5 |
|
|
20 |
|
Net current period other comprehensive (loss)/income |
|
(239 |
) |
|
8 |
|
|
10 |
|
|
5 |
|
|
(216 |
) |
AOCI balance at September 30,
2018 |
|
(701 |
) |
|
(18 |
) |
|
(193 |
) |
|
(438 |
) |
|
(1,350 |
) |
1 All amounts are net of tax. Amounts in parentheses
indicate losses recorded to OCI.
2 Other comprehensive (loss)/income before
reclassifications on currency translation adjustments and cash flow
hedges are net of non-controlling interest losses of $34 million
and gains of $1 million, respectively.
3 Amounts reclassified from AOCI on cash flow hedges and
equity investments are net of non-controlling interest gains of $1
million and $1 million, respectively.
nine months ended September 30,
2018 |
|
Currency |
|
|
|
Pension and |
|
|
|
|
(unaudited - millions of Canadian $) |
|
Translation
Adjustments |
|
Cash Flow
Hedges |
|
OPEB Plan
Adjustments |
|
Equity
Investments |
|
Total1 |
|
|
|
|
|
|
|
|
|
|
|
AOCI balance at January 1, 2018 |
|
(1,043 |
) |
|
(31 |
) |
|
(203 |
) |
|
(454 |
) |
|
(1,731 |
) |
Other comprehensive income before
reclassifications2 |
|
342 |
|
|
1 |
|
|
— |
|
|
— |
|
|
343 |
|
Amounts reclassified from
AOCI3,4 |
|
— |
|
|
12 |
|
|
10 |
|
|
16 |
|
|
38 |
|
Net current period other comprehensive
income |
|
342 |
|
|
13 |
|
|
10 |
|
|
16 |
|
|
381 |
|
AOCI balance at September 30,
2018 |
|
(701 |
) |
|
(18 |
) |
|
(193 |
) |
|
(438 |
) |
|
(1,350 |
) |
1 All amounts are net of tax. Amounts in parentheses
indicate losses recorded to OCI.
2 Other comprehensive income before reclassifications on
currency translation adjustments and cash flow hedges are net of
non-controlling interest gains of $61 million and $8 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 ($11 million after tax) at
September 30, 2018. 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 interest gains of $4
million and $2 million, 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
September 30 |
|
nine months ended
September 30 |
|
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
2018 |
2017 |
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges |
|
|
|
|
|
|
|
|
|
Commodities |
|
(3 |
) |
|
4 |
|
|
(4 |
) |
15 |
|
|
Revenues (Energy) |
Interest |
|
(4 |
) |
|
(4 |
) |
|
(13 |
) |
(13 |
) |
|
Interest expense |
|
|
(7 |
) |
|
— |
|
|
(17 |
) |
2 |
|
|
Total before tax |
|
|
2 |
|
|
— |
|
|
5 |
|
(1 |
) |
|
Income tax expense |
|
|
(5 |
) |
|
— |
|
|
(12 |
) |
1 |
|
|
Net of tax1,3 |
Pension and other post-retirement benefit plan adjustments |
|
|
|
|
|
|
|
|
|
Amortization of actuarial gains and losses |
|
(4 |
) |
|
(4 |
) |
|
(12 |
) |
(12 |
) |
|
Plant operating costs and other2 |
Settlement charge |
|
— |
|
|
(2 |
) |
|
— |
|
(2 |
) |
|
Plant operating costs and
other2 |
|
|
(4 |
) |
|
(6 |
) |
|
(12 |
) |
(14 |
) |
|
Total before tax |
|
|
(6 |
) |
|
2 |
|
|
2 |
|
5 |
|
|
Income tax expense |
|
|
(10 |
) |
|
(4 |
) |
|
(10 |
) |
(9 |
) |
|
Net of tax1 |
Equity investments |
|
|
|
|
|
|
|
|
|
Equity income |
|
(6 |
) |
|
(4 |
) |
|
(19 |
) |
(8 |
) |
|
Income from equity investments |
|
|
1 |
|
|
1 |
|
|
3 |
|
2 |
|
|
Income tax expense |
|
|
(5 |
) |
|
(3 |
) |
|
(16 |
) |
(6 |
) |
|
Net of tax1,3 |
Currency translation adjustments |
|
|
|
|
|
|
|
|
|
Realization of foreign currency translation gain on
disposal of foreign operations |
|
— |
|
|
— |
|
|
— |
|
77 |
|
|
Gain on sales of assets |
|
|
— |
|
|
— |
|
|
— |
|
— |
|
|
Income tax expense |
|
|
— |
|
|
— |
|
|
— |
|
77 |
|
|
Net of tax1 |
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 11, Employee post-retirement
benefits, for further information.
3 Amounts reclassified from AOCI on cash flow hedges and
equity investments are net of non-controlling interest gains of $1
million and $1 million, respectively, for the three months ended
September 30, 2018 (2017 - nil and nil) and $4 million and $2
million, respectively, for the nine months ended September 30,
2018 (2017 - nil and nil).
11. 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
September 30 |
|
nine months ended
September 30 |
|
|
Pension benefit
plans |
|
Other post-retirement
benefit plans |
|
Pension benefit
plans |
|
Other post-retirement
benefit plans |
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost1 |
|
30 |
|
|
25 |
|
|
1 |
|
|
1 |
|
|
91 |
|
|
81 |
|
|
3 |
|
|
3 |
|
Other components of net benefit cost1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost |
|
33 |
|
|
30 |
|
|
3 |
|
|
3 |
|
|
100 |
|
|
92 |
|
|
10 |
|
|
10 |
|
Expected return on plan assets |
|
(55 |
) |
|
(45 |
) |
|
(4 |
) |
|
(5 |
) |
|
(165 |
) |
|
(134 |
) |
|
(12 |
) |
|
(16 |
) |
Amortization of actuarial loss |
|
4 |
|
|
3 |
|
|
— |
|
|
1 |
|
|
11 |
|
|
11 |
|
|
1 |
|
|
1 |
|
Amortization of regulatory asset |
|
5 |
|
|
26 |
|
|
— |
|
|
— |
|
|
14 |
|
|
33 |
|
|
— |
|
|
1 |
|
Settlement charge |
|
— |
|
|
2 |
|
|
— |
|
|
— |
|
|
— |
|
|
2 |
|
|
— |
|
|
— |
|
|
|
(13 |
) |
|
16 |
|
|
(1 |
) |
|
(1 |
) |
|
(40 |
) |
|
4 |
|
|
(1 |
) |
|
(4 |
) |
Net Benefit Cost |
|
17 |
|
|
41 |
|
|
— |
|
|
— |
|
|
51 |
|
|
85 |
|
|
2 |
|
|
(1 |
) |
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.
12. Risk management and financial
instruments
RISK MANAGEMENT OVERVIEW
TransCanada 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 and cash flow.
COUNTERPARTY CREDIT RISK
TransCanada’s maximum counterparty credit exposure with respect to
financial instruments at September 30, 2018, without taking
into account security held, consisted of cash and cash equivalents,
accounts receivable, available-for-sale assets, derivative assets
and loans receivable. The Company regularly reviews its accounts
receivable and records an allowance for doubtful accounts as
necessary using the specific identification method. At
September 30, 2018, there were no significant amounts past due
or impaired, no significant credit risk concentration and no
significant credit losses during the period.
LOAN RECEIVABLE FROM AFFILIATE
Related 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. Draws on the credit facility result in a loan
receivable from the joint venture representing the Company's
proportionate share of the debt financing requirements advanced to
the joint venture.
At September 30, 2018, the balance of the Company's loan
receivable from the joint venture totaled MXN$18.0 billion or $1.2
billion (December 31, 2017 – MXN$14.4 billion or $919 million)
and Interest income and other included $32 million and $88 million
of interest income on this loan receivable for the three and nine
months ended September 30, 2018 (2017 – $11 million and $14
million). Amounts recognized in Interest income and other are
offset by a corresponding proportionate share of interest expense
recorded in Income from equity investments.
NET INVESTMENT IN FOREIGN OPERATIONS
The Company hedges its net investment in foreign operations (on an
after-tax basis) with U.S. dollar-denominated debt, cross-currency
interest rate swaps and foreign exchange forward contracts and
options.
The fair values and notional amounts for the derivatives
designated as a net investment hedge were as follows:
|
|
September 30,
2018 |
|
December 31,
2017 |
(unaudited - millions of Canadian $, unless
noted otherwise) |
|
Fair
value1,2 |
|
Notional amount |
|
Fair
value1,2 |
|
Notional amount |
|
|
|
|
|
|
|
|
|
U.S. dollar cross-currency interest rate swaps (maturing 2018 to
2019)3 |
|
(42 |
) |
|
US 300 |
|
(199 |
) |
|
US 1,200 |
U.S. dollar foreign exchange options (maturing 2018 to 2019) |
|
(2 |
) |
|
US 2,000 |
|
5 |
|
|
US 500 |
|
|
(44 |
) |
|
US 2,300 |
|
(194 |
) |
|
US 1,700 |
1 Fair value equals carrying value.
2 No amounts have been excluded from the assessment of
hedge effectiveness.
3 In the three and nine months ended September 30,
2018, Net income includes net realized gains of nil and $1 million,
respectively (2017 – $1 million and $3 million, respectively)
related to the interest component of cross-currency swap
settlements which are reported within Interest expense.
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
noted otherwise) |
|
September 30, 2018 |
|
December 31, 2017 |
|
|
|
|
|
Notional amount |
|
28,300 (US 21,900) |
|
25,400 (US 20,200) |
Fair value |
|
30,200 (US 23,300) |
|
28,900 (US 23,100) |
FINANCIAL INSTRUMENTS
Non-derivative financial instruments
Fair value of non-derivative financial
instruments
Available-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
instruments
The 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:
|
|
September 30,
2018 |
|
December 31,
2017 |
(unaudited - millions of Canadian $) |
|
Carrying
amount |
|
Fair
value |
|
Carrying
amount |
|
Fair
value |
|
|
|
|
|
|
|
|
|
Long-term debt including current portion1,2 |
|
(36,700 |
) |
|
(39,956 |
) |
|
(34,741 |
) |
|
(40,180 |
) |
Junior subordinated notes |
|
(7,186 |
) |
|
(7,014 |
) |
|
(7,007 |
) |
|
(7,233 |
) |
|
|
(43,886 |
) |
|
(46,970 |
) |
|
(41,748 |
) |
|
(47,413 |
) |
1 Long-term debt is recorded at amortized cost except
for US$700 million (December 31, 2017 – US$1.1 billion) that
is attributed to hedged risk and recorded at fair value.
2 Net income for the three and nine months ended
September 30, 2018 includes unrealized losses of $1 million
and unrealized gains of $3 million, respectively, (2017 – gains of
$1 million and $2 million, respectively) for fair value adjustments
attributable to the hedged interest rate risk associated with
interest rate swap fair value hedging relationships on US$700
million of long-term debt at September 30, 2018
(December 31, 2017 – US$1.1 billion). There were no other
unrealized gains or losses from fair value adjustments to the
non-derivative financial instruments.
Available for sale assets summary
The following tables summarize additional information about the
Company's restricted investments that are classified as
available-for-sale assets:
|
September 30,
2018 |
|
December 31,
2017 |
(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 |
— |
|
|
19 |
|
|
— |
|
|
23 |
|
Maturing within 1-5 years |
— |
|
|
113 |
|
|
— |
|
|
107 |
|
Maturing within 5-10 years |
84 |
|
|
— |
|
|
14 |
|
|
— |
|
Maturing after 10 years |
894 |
|
|
— |
|
|
790 |
|
|
— |
|
|
978 |
|
|
132 |
|
|
804 |
|
|
130 |
|
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 Condensed consolidated balance sheet.
|
|
September 30,
2018 |
|
September 30,
2017 |
(unaudited - millions of Canadian $) |
|
LMCI restricted
investments1 |
|
Other restricted
investments2 |
|
LMCI restricted
investments1 |
|
Other restricted
investments2 |
|
|
|
|
|
|
|
|
|
Net unrealized (losses)/gains in the period |
|
|
|
|
|
|
|
|
three months ended |
|
(34 |
) |
|
— |
|
|
(38 |
) |
|
— |
|
nine months ended |
|
(29 |
) |
|
1 |
|
|
(23 |
) |
|
— |
|
Net realized losses in the period |
|
|
|
|
|
|
|
|
three months ended |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
nine months ended |
|
(3 |
) |
|
— |
|
|
(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.
Derivative instruments
Fair value of derivative instruments
The 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.
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
instruments
The balance sheet classification of the fair value of derivative
instruments is as follows:
at September 30, 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 |
|
|
— |
|
|
— |
|
|
332 |
|
|
333 |
|
Foreign exchange |
— |
|
|
— |
|
|
13 |
|
|
20 |
|
|
33 |
|
Interest rate |
6 |
|
|
— |
|
|
— |
|
|
— |
|
|
6 |
|
|
7 |
|
|
— |
|
|
13 |
|
|
352 |
|
|
372 |
|
Intangible and other assets |
|
|
|
|
|
|
|
|
|
Commodities2 |
— |
|
|
— |
|
|
— |
|
|
66 |
|
|
66 |
|
Foreign exchange |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Interest rate |
17 |
|
|
— |
|
|
— |
|
|
— |
|
|
17 |
|
|
17 |
|
|
— |
|
|
— |
|
|
66 |
|
|
83 |
|
Total Derivative Assets |
24 |
|
|
— |
|
|
13 |
|
|
418 |
|
|
455 |
|
Accounts payable and other |
|
|
|
|
|
|
|
|
|
Commodities2 |
(4 |
) |
|
— |
|
|
— |
|
|
(313 |
) |
|
(317 |
) |
Foreign exchange |
— |
|
|
— |
|
|
(57 |
) |
|
(39 |
) |
|
(96 |
) |
Interest rate |
— |
|
|
(5 |
) |
|
— |
|
|
— |
|
|
(5 |
) |
|
(4 |
) |
|
(5 |
) |
|
(57 |
) |
|
(352 |
) |
|
(418 |
) |
Other long-term liabilities |
|
|
|
|
|
|
|
|
|
Commodities2 |
(1 |
) |
|
— |
|
|
— |
|
|
(40 |
) |
|
(41 |
) |
Foreign exchange |
— |
|
|
— |
|
|
— |
|
|
— |
|
|
— |
|
Interest rate |
— |
|
|
(2 |
) |
|
— |
|
|
— |
|
|
(2 |
) |
|
(1 |
) |
|
(2 |
) |
|
— |
|
|
(40 |
) |
|
(43 |
) |
Total Derivative
Liabilities |
(5 |
) |
|
(7 |
) |
|
(57 |
) |
|
(392 |
) |
|
(461 |
) |
Total Derivatives |
19 |
|
|
(7 |
) |
|
(44 |
) |
|
26 |
|
|
(6 |
) |
1 Fair value equals carrying value.
2 Includes purchases and sales of power, natural gas and
liquids.
at December 31, 2017 |
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 |
|
|
— |
|
|
— |
|
|
249 |
|
|
250 |
|
Foreign exchange |
— |
|
|
— |
|
|
8 |
|
|
70 |
|
|
78 |
|
Interest rate |
3 |
|
|
— |
|
|
— |
|
|
1 |
|
|
4 |
|
|
4 |
|
|
— |
|
|
8 |
|
|
320 |
|
|
332 |
|
Intangible and other assets |
|
|
|
|
|
|
|
|
|
Commodities2 |
— |
|
|
— |
|
|
— |
|
|
69 |
|
|
69 |
|
Interest rate |
4 |
|
|
— |
|
|
— |
|
|
— |
|
|
4 |
|
|
4 |
|
|
— |
|
|
— |
|
|
69 |
|
|
73 |
|
Total Derivative Assets |
8 |
|
|
— |
|
|
8 |
|
|
389 |
|
|
405 |
|
Accounts payable and other |
|
|
|
|
|
|
|
|
|
Commodities2 |
(6 |
) |
|
— |
|
|
— |
|
|
(208 |
) |
|
(214 |
) |
Foreign exchange |
— |
|
|
— |
|
|
(159 |
) |
|
(10 |
) |
|
(169 |
) |
Interest rate |
— |
|
|
(4 |
) |
|
— |
|
|
— |
|
|
(4 |
) |
|
(6 |
) |
|
(4 |
) |
|
(159 |
) |
|
(218 |
) |
|
(387 |
) |
Other long-term liabilities |
|
|
|
|
|
|
|
|
|
Commodities2 |
(2 |
) |
|
— |
|
|
— |
|
|
(26 |
) |
|
(28 |
) |
Foreign exchange |
— |
|
|
— |
|
|
(43 |
) |
|
— |
|
|
(43 |
) |
Interest rate |
— |
|
|
(1 |
) |
|
— |
|
|
— |
|
|
(1 |
) |
|
(2 |
) |
|
(1 |
) |
|
(43 |
) |
|
(26 |
) |
|
(72 |
) |
Total Derivative
Liabilities |
(8 |
) |
|
(5 |
) |
|
(202 |
) |
|
(244 |
) |
|
(459 |
) |
Total Derivatives |
— |
|
|
(5 |
) |
|
(194 |
) |
|
145 |
|
|
(54 |
) |
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
relationships
The 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 $) |
September 30,
2018 |
|
December 31,
2017 |
|
September 30,
2018 |
|
December 31,
2017 |
|
|
|
|
|
|
|
|
Current portion of long-term debt |
(387 |
) |
|
(688 |
) |
|
1 |
|
|
1 |
|
Long-term debt |
(511 |
) |
|
(685 |
) |
|
6 |
|
|
4 |
|
|
(898 |
) |
|
(1,373 |
) |
|
7 |
|
|
5 |
|
1 At September 30, 2018 and December 31,
2017, adjustments for discontinued hedging relationships included
in these balances were nil.
Notional and Maturity Summary
The maturity and notional principal or quantity outstanding related
to the Company's derivative instruments excluding hedges of the net
investment in foreign operations is as follows:
at September 30, 2018 |
Power |
|
Natural
Gas |
|
Liquids |
|
Foreign
Exchange |
|
Interest
Rate |
(unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases1 |
30,533 |
|
|
61 |
|
|
55 |
|
|
— |
|
|
— |
|
Sales1 |
22,711 |
|
|
70 |
|
|
74 |
|
|
— |
|
|
— |
|
Millions of U.S. dollars |
— |
|
|
— |
|
|
— |
|
|
3,898 |
|
1,200 |
Maturity dates |
2018-2022 |
|
2018-2021 |
|
2018-2019 |
|
2018-2019 |
|
2018-2028 |
1 Volumes for power, natural gas and liquids
derivatives are in GWh, Bcf and MMBbls, respectively.
at December 31, 2017 |
Power |
|
Natural
Gas |
|
Liquids |
|
Foreign
Exchange |
|
Interest
Rate |
(unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases1 |
66,132 |
|
|
133 |
|
|
6 |
|
|
— |
|
|
— |
|
Sales1 |
42,836 |
|
|
135 |
|
|
7 |
|
|
— |
|
|
— |
|
Millions of U.S. dollars |
— |
|
|
— |
|
|
— |
|
|
2,931 |
|
2,300 |
Millions of Mexican pesos |
— |
|
|
— |
|
|
— |
|
|
100 |
|
— |
|
Maturity dates |
2018-2022 |
|
2018-2021 |
|
2018 |
|
2018 |
|
2018-2022 |
1 Volumes for power, natural gas and liquids
derivatives are in GWh, Bcf and MMBbls, respectively.
Unrealized and realized (losses)/gains on derivative
instruments
The following summary does not include hedges of the net investment
in foreign operations.
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Derivative Instruments Held for
Trading1 |
|
|
|
|
|
|
|
|
Amount of unrealized (losses)/gains in the period |
|
|
|
|
|
|
|
|
Commodities2 |
|
(31 |
) |
|
45 |
|
|
(41 |
) |
|
(102 |
) |
Foreign exchange |
|
60 |
|
|
33 |
|
|
(79 |
) |
|
89 |
|
Interest rate |
|
— |
|
|
(1 |
) |
|
— |
|
|
(1 |
) |
Amount of realized gains/(losses) in the period |
|
|
|
|
|
|
|
|
Commodities |
|
81 |
|
|
(82 |
) |
|
210 |
|
|
(167 |
) |
Foreign exchange |
|
(5 |
) |
|
19 |
|
|
14 |
|
|
10 |
|
Interest rate |
|
— |
|
|
1 |
|
|
— |
|
|
1 |
|
Derivative Instruments in Hedging
Relationships |
|
|
|
|
|
|
|
|
Amount of realized gains/(losses) in the period |
|
|
|
|
|
|
|
|
Commodities |
|
1 |
|
|
4 |
|
|
— |
|
|
17 |
|
Foreign exchange |
|
— |
|
|
— |
|
|
— |
|
|
5 |
|
Interest rate |
|
(2 |
) |
|
— |
|
|
(1 |
) |
|
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 and nine months ended September 30,
2018 and 2017, 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
relationships
The components of OCI related to the change in fair value of
derivatives in cash flow hedging relationships including the
portion attributable to non-controlling interests are as
follows:
|
|
three months ended
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Change in fair value of derivative instruments recognized in OCI
(effective portion)1 |
|
|
|
|
|
|
|
|
Commodities |
|
3 |
|
|
2 |
|
|
(3 |
) |
|
5 |
|
Interest rate |
|
2 |
|
|
(1 |
) |
|
11 |
|
|
— |
|
|
|
5 |
|
|
1 |
|
|
8 |
|
|
5 |
|
1 Amounts presented are pre-tax. 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
relationships
The following tables detail 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
September 30 |
|
|
Revenues
(Energy) |
|
Interest
Expense |
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Total Amount Presented in the Condensed Consolidated
Statement of Income |
|
535 |
|
|
887 |
|
|
(577 |
) |
|
(504 |
) |
Fair Value Hedges |
|
|
|
|
|
|
|
|
Interest rate contracts |
|
|
|
|
|
|
|
|
Hedged items |
|
— |
|
|
— |
|
|
(17 |
) |
|
(18 |
) |
Derivatives designated as hedging instruments |
|
— |
|
|
— |
|
|
(2 |
) |
|
(1 |
) |
Cash Flow Hedges |
|
|
|
|
|
|
|
|
Reclassification of gains/(losses) on derivative instruments from
AOCI to
net income |
|
|
|
|
|
|
|
|
Interest rate contracts1 |
|
— |
|
|
— |
|
|
5 |
|
|
4 |
|
Commodity contracts2 |
|
3 |
|
|
(4 |
) |
|
— |
|
|
— |
|
1 Refer to Note 10, 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.
|
|
nine months ended
September 30 |
|
|
Revenues
(Energy) |
|
Interest
Expense |
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Total Amount Presented in the Condensed Consolidated
Statement of Income |
|
1,724 |
|
|
2,581 |
|
|
(1,662 |
) |
|
(1,528 |
) |
Fair Value Hedges |
|
|
|
|
|
|
|
|
Interest rate contracts |
|
|
|
|
|
|
|
|
Hedged items |
|
— |
|
|
— |
|
|
(59 |
) |
|
(56 |
) |
Derivatives designated as hedging instruments |
|
— |
|
|
— |
|
|
(4 |
) |
|
1 |
|
Cash Flow Hedges |
|
|
|
|
|
|
|
|
Reclassification of gains/(losses) on derivative instruments from
AOCI to
net income |
|
|
|
|
|
|
|
|
Interest rate contracts1 |
|
— |
|
|
— |
|
|
17 |
|
|
13 |
|
Commodity contracts2 |
|
4 |
|
|
(15 |
) |
|
— |
|
|
— |
|
1 Refer to Note 10, 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 instruments
The 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
balance sheet. The following table shows the impact on the
presentation of the fair value of derivative instrument assets and
liabilities on the Condensed consolidated balance sheet had the
Company elected to present these contracts on a net basis:
at September 30, 2018 |
|
Gross
derivative instruments |
|
Amounts
available for offset1 |
|
Net
amounts |
(unaudited - millions of Canadian $) |
|
|
|
|
|
|
|
|
|
|
Derivative instrument assets |
|
|
|
|
|
|
Commodities |
|
399 |
|
|
(309 |
) |
|
90 |
|
Foreign exchange |
|
33 |
|
|
(24 |
) |
|
9 |
|
Interest rate |
|
23 |
|
|
— |
|
|
23 |
|
|
|
455 |
|
|
(333 |
) |
|
122 |
|
Derivative instrument liabilities |
|
|
|
|
|
|
Commodities |
|
(358 |
) |
|
309 |
|
|
(49 |
) |
Foreign exchange |
|
(96 |
) |
|
24 |
|
|
(72 |
) |
Interest rate |
|
(7 |
) |
|
— |
|
|
(7 |
) |
|
|
(461 |
) |
|
333 |
|
|
(128 |
) |
1 Amounts available for offset do not include cash
collateral pledged or received.
at December 31, 2017 |
|
Gross
derivative instruments |
|
Amounts
available for offset1 |
|
Net
amounts |
(unaudited - millions of Canadian $) |
|
|
|
|
|
|
|
|
|
|
Derivative instrument assets |
|
|
|
|
|
|
Commodities |
|
319 |
|
|
(198 |
) |
|
121 |
|
Foreign exchange |
|
78 |
|
|
(56 |
) |
|
22 |
|
Interest rate |
|
8 |
|
|
(1 |
) |
|
7 |
|
|
|
405 |
|
|
(255 |
) |
|
150 |
|
Derivative instrument liabilities |
|
|
|
|
|
|
Commodities |
|
(242 |
) |
|
198 |
|
|
(44 |
) |
Foreign exchange |
|
(212 |
) |
|
56 |
|
|
(156 |
) |
Interest rate |
|
(5 |
) |
|
1 |
|
|
(4 |
) |
|
|
(459 |
) |
|
255 |
|
|
(204 |
) |
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 $87 million and letters of
credit of $17 million as at September 30, 2018
(December 31, 2017 – $165 million and $30 million) to its
counterparties. At September 30, 2018, the Company held nil in
cash collateral and $1 million in letters of credit
(December 31, 2017 – nil and $3 million) from counterparties
on asset exposures.
Credit-risk-related contingent features of derivative
instruments
Derivative 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
September 30, 2018, the aggregate fair value of all derivative
instruments with credit-risk-related contingent features that were
in a net liability position was $2 million (December 31, 2017
– $2 million), for which the Company did not provide collateral in
the normal course of business at September 30, 2018 or
December 31, 2017. If the credit-risk-related contingent
features in these agreements were triggered on September 30,
2018, the Company would have been required to provide collateral of
$2 million (December 31, 2017 – $2 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 HIERARCHY
The 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 |
Valuation based on the extrapolation of
inputs, other than quoted prices included within Level I, for which
all significant inputs are observable directly or indirectly.
Inputs include published exchange rates, interest rates, interest
rate swap curves, yield curves and broker quotes from external data
service providers.
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.
Transfers between Level I and Level II would occur when there is a
change in market circumstances. |
Level III |
Valuation of assets and liabilities are
measured using a market approach based on extrapolation of inputs
that are unobservable or where observable data does not support a
significant portion of the derivative's fair value. 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. Valuation
of options is based on the Black-Scholes pricing model.
Assets and liabilities measured at fair value can fluctuate between
Level II and Level III depending on the proportion of the value of
the contract that extends beyond the time frame for which
significant inputs are considered to be observable. As contracts
near maturity and observable market data become available, they are
transferred out of Level III and into Level II. |
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 September 30, 2018 |
|
Quoted prices in active
markets |
|
Significant other
observable inputs |
|
Significant unobservable
inputs |
|
|
(unaudited - millions of Canadian $) |
|
(Level
I)1 |
|
(Level
II)1 |
|
(Level
III)1 |
|
Total |
|
|
|
|
|
|
|
|
|
Derivative instrument assets |
|
|
|
|
|
|
|
|
Commodities |
|
217 |
|
|
145 |
|
|
37 |
|
|
399 |
|
Foreign exchange |
|
— |
|
|
33 |
|
|
— |
|
|
33 |
|
Interest rate |
|
— |
|
|
23 |
|
|
— |
|
|
23 |
|
Derivative instrument liabilities |
|
|
|
|
|
|
|
|
Commodities |
|
(220 |
) |
|
(87 |
) |
|
(51 |
) |
|
(358 |
) |
Foreign exchange |
|
— |
|
|
(96 |
) |
|
— |
|
|
(96 |
) |
Interest rate |
|
— |
|
|
(7 |
) |
|
— |
|
|
(7 |
) |
|
|
(3 |
) |
|
11 |
|
|
(14 |
) |
|
(6 |
) |
1 There were no transfers from Level I to Level II or
from Level II to Level III for the nine months ended
September 30, 2018.
at December 31, 2017 |
|
Quoted
prices in active markets (Level I)1 |
|
Significant
other observable inputs (Level II)1 |
|
Significant
unobservable inputs
(Level III)1 |
|
|
(unaudited - millions of Canadian $) |
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
Derivative instrument assets |
|
|
|
|
|
|
|
|
Commodities |
|
21 |
|
|
283 |
|
|
15 |
|
|
319 |
|
Foreign exchange |
|
— |
|
|
78 |
|
|
— |
|
|
78 |
|
Interest rate |
|
— |
|
|
8 |
|
|
— |
|
|
8 |
|
Derivative instrument liabilities |
|
|
|
|
|
|
|
|
Commodities |
|
(27 |
) |
|
(193 |
) |
|
(22 |
) |
|
(242 |
) |
Foreign exchange |
|
— |
|
|
(212 |
) |
|
— |
|
|
(212 |
) |
Interest rate |
|
— |
|
|
(5 |
) |
|
— |
|
|
(5 |
) |
|
|
(6 |
) |
|
(41 |
) |
|
(7 |
) |
|
(54 |
) |
1 There were no transfers from Level I to Level II or
from Level II to Level III for the year ended December 31,
2017.
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
September 30 |
|
nine months ended
September 30 |
(unaudited - millions of Canadian $) |
|
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
Balance at beginning of period |
|
|
40 |
|
|
9 |
|
|
(7 |
) |
|
16 |
|
Total losses included in Net income |
|
|
(24 |
) |
|
(10 |
) |
|
(6 |
) |
|
(12 |
) |
Settlements |
|
|
(14 |
) |
|
(1 |
) |
|
9 |
|
|
4 |
|
Sales |
|
|
— |
|
|
— |
|
|
— |
|
|
(5 |
) |
Transfers out of Level III |
|
|
(16 |
) |
|
— |
|
|
(10 |
) |
|
(5 |
) |
Balance at end of
period1 |
|
|
(14 |
) |
|
(2 |
) |
|
(14 |
) |
|
(2 |
) |
1 For the three and nine months ended
September 30, 2018, Revenues include unrealized losses of $16
million and $2 million, respectively, attributed to derivatives in
the Level III category that were still held at September 30,
2018 (2017 – unrealized losses of $10 million and $14
million, respectively).
A 10 per cent increase or decrease in commodity prices, with all
other variables held constant, would result in a $27 million
decrease or increase, respectively, in the fair value of
outstanding derivative instruments included in Level III as at
September 30, 2018.
13. Contingencies and guarantees
CONTINGENCIES
TransCanada 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.
GUARANTEES
TransCanada and its joint venture partner on the Sur de Texas
pipeline, IEnova, have jointly guaranteed the obligations for
construction services during the construction of the pipeline.
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 September 30,
2018 |
|
at December 31,
2017 |
(unaudited - millions of Canadian $) |
|
Term |
|
Potential
exposure1 |
|
Carrying
value |
|
Potential
exposure1 |
|
Carrying
value |
|
|
|
|
|
|
|
|
|
|
|
Sur de Texas |
|
ranging to 2020 |
|
187 |
|
|
1 |
|
|
315 |
|
|
2 |
|
Bruce Power |
|
ranging to 2019 |
|
88 |
|
|
— |
|
|
88 |
|
|
1 |
|
Other jointly-owned entities |
|
ranging to 2059 |
|
104 |
|
|
11 |
|
|
104 |
|
|
13 |
|
|
|
|
|
379 |
|
|
12 |
|
|
507 |
|
|
16 |
|
1 TransCanada’s share of the potential estimated
current or contingent exposure.
14. 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 VIEs
The 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:
|
|
September
30, |
|
December
31, |
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
|
|
|
|
ASSETS |
|
|
|
|
Current Assets |
|
|
|
|
Cash and cash equivalents |
|
62 |
|
|
41 |
|
Accounts receivable |
|
59 |
|
|
63 |
|
Inventories |
|
22 |
|
|
23 |
|
Other |
|
13 |
|
|
11 |
|
|
|
156 |
|
|
138 |
|
Plant, Property and Equipment |
|
3,576 |
|
|
3,535 |
|
Equity Investments |
|
925 |
|
|
917 |
|
Goodwill |
|
505 |
|
|
490 |
|
Intangible and Other
Assets |
|
17 |
|
|
3 |
|
|
|
5,179 |
|
|
5,083 |
|
LIABILITIES |
|
|
|
|
Current Liabilities |
|
|
|
|
Accounts payable and other |
|
79 |
|
|
137 |
|
Dividends payable |
|
— |
|
|
1 |
|
Accrued interest |
|
30 |
|
|
23 |
|
Current portion of long-term debt |
|
74 |
|
|
88 |
|
|
|
183 |
|
|
249 |
|
Regulatory Liabilities |
|
39 |
|
|
34 |
|
Other Long-Term Liabilities |
|
2 |
|
|
3 |
|
Deferred Income Tax Liabilities |
|
13 |
|
|
13 |
|
Long-Term Debt |
|
3,152 |
|
|
3,244 |
|
|
|
3,389 |
|
|
3,543 |
|
Non-Consolidated VIEs
The Company’s non-consolidated VIEs consist of legal entities where
the Company does not have the power to direct the activities that
most significantly impact the economic performance of these
entities 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:
|
|
September
30, |
|
December
31, |
(unaudited - millions of Canadian $) |
|
2018 |
|
2017 |
|
|
|
|
|
Balance sheet |
|
|
|
|
Equity investments |
|
4,430 |
|
|
4,372 |
|
Off-balance sheet |
|
|
|
|
Potential exposure to guarantees |
|
171 |
|
|
171 |
|
Maximum exposure to loss |
|
4,601 |
|
|
4,543 |
|
15. Subsequent Events
Long-term debt issuance
On October 12, 2018, TCPL issued US$1.0 billion of Senior Unsecured
Notes, due in March 2049, bearing interest at a fixed rate of 5.10
per cent and US$400 million of Senior Unsecured Notes, due in May
2028, bearing interest at a fixed rate of 4.25 per cent.
Reimbursement of Coastal GasLink pipeline
pre-development costs
In accordance with provisions in the agreements with the LNG Canada
joint venture participants, to date, four parties have elected to
reimburse TransCanada for their share of pre-development costs on
the Coastal GasLink (CGL) pipeline project, totalling $399 million
of cost reimbursement, with payments due by November 30, 2018. At
September 30, 2018, pre-development costs for the CGL pipeline were
included in Intangible and other assets on the Company's Condensed
consolidated balance sheet.
TC Energy (TSX:TRP)
Historical Stock Chart
From Mar 2024 to Apr 2024
TC Energy (TSX:TRP)
Historical Stock Chart
From Apr 2023 to Apr 2024