CALGARY, Alberta, Aug. 02, 2018 (GLOBE NEWSWIRE) --
TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the
Company) today announced net income attributable to common shares
for second quarter 2018 of $785 million or $0.88 per share compared
to net income of $881 million or $1.01 per share for the same
period in 2017. Comparable earnings for second quarter 2018 were
$768 million or $0.86 per share compared to $659 million or $0.76
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 September 30, 2018, equivalent to
$2.76 per common share on an annualized basis.
"During the second quarter of 2018 our diversified portfolio of
critical energy infrastructure assets continued to perform very
well," said Russ Girling, TransCanada's president and chief
executive officer. "Comparable earnings of 86 cents per share
increased 13 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 six months ended June 30, 2018,
comparable earnings were $1.83 per share, an increase of 17 per
cent over the same period last year despite the sale of our U.S.
Northeast power generation and Ontario solar assets in 2017."
"With our existing asset portfolio benefiting from strong
underlying market fundamentals and $28 billion of near-term growth
projects including maintenance capital expenditures advancing as
planned, earnings and cash flow are forecast to continue to rise.
This is expected to support annual dividend growth at the upper end
of an eight to ten per cent range through 2020 and an additional
eight to ten per cent in 2021,” added Girling. "We have invested
approximately $10 billion in these projects to date and are well
positioned to fund the remainder through our strong and growing
internally generated cash flow along with a broad spectrum of
financing levers including access to capital markets and further
portfolio management activities. In second quarter we placed
approximately $4.3 billion of long-term debt on compelling terms
and year-to-date have raised approximately $1.2 billion of common
equity through our dividend reinvestment plan and at-the-market
program. Earlier today we also announced the sale of our interests
in the Cartier Wind power facilities for approximately
$630 million. Collectively through these initiatives, we have
raised $6.1 billion which represents a sizable component of our
2018 funding requirements."
"In addition, we continue to methodically advance more than $20
billion of medium to longer-term projects including Keystone XL,
Coastal GasLink and the Bruce Power life extension agreement.
Success in advancing these and/or other growth initiatives
associated with our vast North American footprint could extend our
growth outlook beyond 2021," concluded Girling.
Highlights
(All financial figures are unaudited and in Canadian dollars
unless noted otherwise)
- Second quarter 2018 financial results
- Net income attributable to common shares of $785 million or
$0.88 per common share
- Comparable earnings of $768 million or $0.86 per common
share
- Comparable earnings before interest, taxes, depreciation and
amortization of $2.0 billion
- Net cash provided by operations of $1.8 billion
- Comparable funds generated from operations of $1.5 billion
- Comparable distributable cash flow of $1.3 billion or $1.46 per
common share reflecting only non-recoverable maintenance capital
expenditures
- Declared a quarterly dividend of $0.69 per common share for the
quarter ending September 30, 2018
- Received National Energy Board (NEB) approval for the NGTL
System's 2018-2019 Settlement with customers
- Received approval from the Federal government for the $1.6
billion North Montney project
- Raised US$2.5 billion in 10, 20 and 30-year fixed-rate senior
debt in May 2018
- Issued $1 billion of 10 and 30-year fixed-rate medium-term
notes in July 2018
- Replenished the capacity available under the Corporate ATM
program by $1 billion
- Announced the sale of our interests in Cartier Wind for
approximately $630 million in August 2018.
Net income attributable to common shares decreased by $96
million to $785 million or $0.88 per share for the three months
ended June 30, 2018 compared to the same period last year. Net
income per common share in 2018 reflects the dilutive effect of
common shares issued in 2017 and 2018 under our DRP and Corporate
ATM program. Second quarter 2018 results included an $11 million
after-tax loss 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. Second
quarter 2017 results included a $265 million after-tax net gain
related to the monetization of our U.S. Northeast power business,
an after-tax charge of $15 million for integration-related costs
associated with the acquisition of Columbia and an after-tax charge
of $4 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 second quarter 2018 were $768 million or
$0.86 per common share compared to $659 million or $0.76 per common
share for the same period in 2017, an increase of $109 million or
$0.10 per share. Comparable earnings per share for the three months
ended June 30, 2018 include the effect of common shares issued in
2017 and 2018 under our DRP and Corporate ATM program. The increase
in second quarter 2018 comparable earnings over the same period in
2017 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, higher volumes on the Keystone Pipeline System
and increased earnings from liquids marketing activities
- lower income tax expense primarily due to lower income tax
rates as a result of U.S. Tax Reform
- 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 U.S. Power mainly due to the sale of the
U.S. Northeast power generation assets in second quarter 2017
- lower earnings from Bruce Power primarily due to lower volumes
resulting from increased outage days
- lower Eastern Power results mainly due to the sale of our
Ontario solar assets in December 2017.
Notable recent developments include:
Canadian Natural Gas Pipelines:
- NGTL System: On June 19, 2018, the NEB approved the
2018-2019 Settlement, as filed, for final 2018 tolls and revised
interim 2018 tolls. The 2018-2019 Settlement fixes return on equity
(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 are treated as flow-through expenses.
On June 20, 2018, we filed an application with the NEB for approval
to construct and operate the 2021 Expansion Project. The project,
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: On May 23, 2018, the NEB issued a
report recommending the Federal government approve a variance to
the existing North Montney project approvals to remove the
condition requiring a positive Final Investment Decision (FID) for
the Pacific Northwest LNG project prior to commencement of
construction. The Federal government approved the
recommendation on June 22, 2018 and on July 2, 2018 the NEB issued
an amending order for the project.
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 increased by $0.2
billion to $1.6 billion mainly due to construction schedule delays
and an increase in market-dependent construction costs.
The first phase of the project is anticipated to be in service by
fourth quarter 2019 and the second phase is expected to be in
service by second quarter 2020.
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 after. There
were no injuries 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.
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 it 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 of late 2018.
- Tula and Villa de Reyes: We continue to work toward
finalizing amending agreements for both of these pipelines with the
Comisión Federal de Electricidad (CFE) to formalize the schedule
and payments resulting from their respective force majeure events.
The CFE has commenced payments on both pipelines in accordance with
the TSAs.
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 hear the appeal case against the PSC’s
alternative route itself. We expect the Nebraska Supreme Court, as
the final arbiter, could reach a decision by late 2018 or first
quarter 2019.
On May 15, 2018, the U.S. Department of State filed a notice of its
intent to prepare an environmental assessment for the Keystone XL
mainline alternative route in Nebraska. Public comments were due in
June 2018. On July 30, 2018, the U.S. Department of State issued a
draft environmental assessment. Comments on the draft are to be
filed by August 29, 2018. We expect the U.S. Department of State
will have completed the supplemental environmental review by third
or fourth quarter 2018.
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, 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 may be issued by year-end 2018.
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, 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.
Energy:
- Cartier Wind: On August 1, 2018, we entered into an
agreement to sell our interests in the Cartier Wind power
facilities in Québec to Innergex Renewable Energy Inc. for
gross proceeds of $630 million before closing adjustments. The sale
is expected to be completed in fourth quarter 2018 subject to
certain regulatory and other approvals and result in an estimated
gain of $175 million ($130 million after tax) which will be
recorded upon closing of the transaction.
Corporate:
- Common Share Dividend: Our Board of Directors declared
a quarterly dividend of $0.69 per share for the quarter ending
September 30, 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 second quarter
2018, TCPL issued US$1 billion of Senior Unsecured Notes due in May
2028 bearing interest at a fixed rate of 4.25 per cent, US$500
million of Senior Unsecured Notes due in May 2038 bearing interest
at a fixed rate of 4.75 per cent and US$1 billion of Senior
Unsecured Notes due in May 2048 bearing interest at a fixed rate of
4.875 per cent.
In July 2018, TCPL issued $800 million of Medium Term Notes due in
July 2048 bearing interest at a fixed rate of 4.182 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 and to fund our capital program.
- Dividend Reinvestment Plan: In second quarter 2018,
the DRP participation rate amongst common shareholders was
approximately 33 per cent, resulting in $208 million reinvested in
common equity under the program. Year-to-date in 2018, the
participation rate amongst common shareholders has been
approximately 36 per cent, resulting in $442 million of dividends
reinvested.
- ATM Equity Issuance Program: In second quarter 2018,
8.1 million common shares were issued under our Corporate ATM
program at an average price of $54.63 per common share for gross
proceeds of $443 million. In the six months ended June 30, 2018,
13.9 million common shares have been issued under the program at an
average price of $55.42 per common share for gross proceeds of $772
million.
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
(Amended Corporate ATM program), 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 Amended Corporate ATM program,
which is effective to July 23, 2019, will be activated at our
discretion if and as required based on the spend profile of our
capital program and relative cost of other funding options.
- Comparable Distributable Cash Flow: Beginning in
second quarter 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 costs in pipeline tolls. 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.
- 2018 FERC Actions: In December 2016, the Federal
Energy Regulatory Commission (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, H.R. 1, the Tax Cuts and Jobs Act (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, deferred income tax assets and deferred
income tax 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, 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
interstate pipelines 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 pipeline's ROE assuming a
single-issue adjustment to a pipeline’s rates; and (3) a NOI
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 (collectively, the “2018 FERC Actions”). The
Final Rule will become effective September 13, 2018, and is subject
to requests for further rehearing and clarification.
For more information on these developments and their implications
for TransCanada and TC PipeLines, LP, please refer to our
management's discussion and analysis.
Teleconference and Webcast:
We will hold a teleconference and webcast on Thursday, August 2,
2018 to discuss our second 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 9 a.m.
(MT) / 11 a.m. (ET).
Members of the investment community and other interested parties
are invited to participate by calling 800.377.0758 or 416.340.2218
(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/9341.
A replay of the teleconference will be available two hours after
the conclusion of the call until midnight (ET) on August 9, 2018.
Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter
pass code 1845117#.
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 6,100 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 August 1, 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 August 1, 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
Second quarter 2018
Financial highlights
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $, except per share amounts) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Income |
|
|
|
|
|
|
|
|
Revenues |
|
|
3,195 |
|
|
|
3,230 |
|
|
|
6,619 |
|
|
|
6,637 |
|
Net income attributable
to common shares |
|
|
785 |
|
|
|
881 |
|
|
|
1,519 |
|
|
|
1,524 |
|
per
common share – basic |
|
$0.88 |
|
|
$1.01 |
|
|
$1.70 |
|
|
$1.76 |
|
– diluted |
|
$0.88 |
|
|
$1.01 |
|
|
$1.70 |
|
|
$1.75 |
|
Comparable
EBITDA1 |
|
|
1,991 |
|
|
|
1,830 |
|
|
|
4,054 |
|
|
|
3,807 |
|
Comparable
earnings1 |
|
|
768 |
|
|
|
659 |
|
|
|
1,632 |
|
|
|
1,357 |
|
per
common share1 |
|
$0.86 |
|
|
$0.76 |
|
|
$1.83 |
|
|
$1.56 |
|
|
|
|
|
|
|
|
|
|
Cash
flows |
|
|
|
|
|
|
|
|
Net cash provided by
operations |
|
|
1,805 |
|
|
|
1,353 |
|
|
|
3,217 |
|
|
|
2,655 |
|
Comparable funds
generated from operations1 |
|
|
1,459 |
|
|
|
1,367 |
|
|
|
3,070 |
|
|
|
2,875 |
|
Comparable
distributable cash flow1 |
|
|
1,306 |
|
|
|
1,181 |
|
|
|
2,745 |
|
|
|
2,521 |
|
per
common share1 |
|
$1.46 |
|
|
$1.36 |
|
|
$3.08 |
|
|
$2.90 |
|
Capital
spending2 |
|
|
2,597 |
|
|
|
2,321 |
|
|
|
4,693 |
|
|
|
4,115 |
|
|
|
|
|
|
|
|
|
|
Dividends
declared |
|
|
|
|
|
|
|
|
Per common share |
|
$0.69 |
|
|
$0.625 |
|
|
$1.38 |
|
|
$1.25 |
|
Basic common
shares outstanding (millions) |
|
|
|
|
|
|
|
|
–
weighted average for the period |
|
|
896 |
|
|
|
870 |
|
|
|
892 |
|
|
|
868 |
|
– issued and outstanding at end of period |
|
|
904 |
|
|
|
871 |
|
|
|
904 |
|
|
|
871 |
|
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
August 1, 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 six
months ended June 30, 2018, and should be read with the
accompanying unaudited condensed consolidated financial statements
for the three and six months ended June 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, including the economic benefit of
asset drop downs to TC PipeLines, LP
- 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 equivalent 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 measure 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,
beginning in second quarter 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 - second quarter 2018
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $, except per share amounts) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
|
280 |
|
|
|
305 |
|
|
|
533 |
|
|
|
587 |
|
U.S. Natural Gas
Pipelines |
|
|
541 |
|
|
|
401 |
|
|
|
1,189 |
|
|
|
962 |
|
Mexico Natural Gas
Pipelines |
|
|
118 |
|
|
|
120 |
|
|
|
255 |
|
|
|
238 |
|
Liquids Pipelines |
|
|
390 |
|
|
|
251 |
|
|
|
731 |
|
|
|
478 |
|
Energy |
|
|
191 |
|
|
|
645 |
|
|
|
241 |
|
|
|
843 |
|
Corporate |
|
|
72 |
|
|
|
(40 |
) |
|
|
(9 |
) |
|
|
(73 |
) |
Total segmented
earnings |
|
|
1,592 |
|
|
|
1,682 |
|
|
|
2,940 |
|
|
|
3,035 |
|
Interest expense |
|
|
(558 |
) |
|
|
(524 |
) |
|
|
(1,085 |
) |
|
|
(1,024 |
) |
Allowance for funds
used during construction |
|
|
113 |
|
|
|
121 |
|
|
|
218 |
|
|
|
222 |
|
Interest
income and other |
|
|
(92 |
) |
|
|
89 |
|
|
|
(29 |
) |
|
|
109 |
|
Income before
income taxes |
|
|
1,055 |
|
|
|
1,368 |
|
|
|
2,044 |
|
|
|
2,342 |
|
Income
tax expense |
|
|
(153 |
) |
|
|
(393 |
) |
|
|
(274 |
) |
|
|
(593 |
) |
Net
income |
|
|
902 |
|
|
|
975 |
|
|
|
1,770 |
|
|
|
1,749 |
|
Net
income attributable to non-controlling interests |
|
|
(76 |
) |
|
|
(55 |
) |
|
|
(170 |
) |
|
|
(145 |
) |
Net income
attributable to controlling interests |
|
|
826 |
|
|
|
920 |
|
|
|
1,600 |
|
|
|
1,604 |
|
Preferred
share dividends |
|
|
(41 |
) |
|
|
(39 |
) |
|
|
(81 |
) |
|
|
(80 |
) |
Net income attributable to common shares |
|
|
785 |
|
|
|
881 |
|
|
|
1,519 |
|
|
|
1,524 |
|
Net income per
common share — basic |
|
$0.88 |
|
|
$1.01 |
|
|
$1.70 |
|
|
$1.76 |
|
—
diluted |
|
$0.88 |
|
|
$1.01 |
|
|
$1.70 |
|
|
$1.75 |
|
Net income attributable to common shares decreased by $96
million and $5 million, or $0.13 and $0.06 per common share, for
the three and six months ended June 30, 2018 compared to the
same periods in 2017. Net income per common share in 2018 reflects
the effect 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:
- an after-tax loss of $5 million year-to-date related to our
U.S. Northeast power marketing contracts which included an
after-tax loss of $11 million in second quarter and an after-tax
gain of $6 million in first quarter primarily due to income
recognized 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
will continue to run-off through to mid-2020.
2017 results included:
- a $255 million after-tax net gain related to the monetization
of our U.S. Northeast power business, which included a $441 million
after-tax gain on the sale of TC Hydro in second quarter, an
incremental loss of $176 million after tax recorded in second
quarter on the sale of the thermal and wind package and $10 million
year-to-date of after-tax disposition costs
- an after-tax charge of $15 million in second quarter and $39
million year-to-date for integration-related costs associated with
the acquisition of Columbia
- an after-tax charge of $4 million in second quarter and $11
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
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $, except per share amounts) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Net income
attributable to common shares |
|
|
785 |
|
|
|
881 |
|
|
|
1,519 |
|
|
|
1,524 |
|
Specific items
(net of tax): |
|
|
|
|
|
|
|
|
U.S.
Northeast power marketing contracts |
|
|
11 |
|
|
|
— |
|
|
|
5 |
|
|
|
— |
|
Net gain
on sales of U.S. Northeast power generation assets |
|
|
— |
|
|
|
(265 |
) |
|
|
— |
|
|
|
(255 |
) |
Integration and acquisition related costs – Columbia |
|
|
— |
|
|
|
15 |
|
|
|
— |
|
|
|
39 |
|
Keystone
XL asset costs |
|
|
— |
|
|
|
4 |
|
|
|
— |
|
|
|
11 |
|
Keystone
XL income tax recoveries |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(7 |
) |
Risk management activities1 |
|
|
(28 |
) |
|
|
24 |
|
|
|
108 |
|
|
|
45 |
|
Comparable earnings |
|
|
768 |
|
|
|
659 |
|
|
|
1,632 |
|
|
|
1,357 |
|
Net income per
common share — basic |
|
$0.88 |
|
|
$1.01 |
|
|
$1.70 |
|
|
$1.76 |
|
Specific items
(net of tax): |
|
|
|
|
|
|
|
|
U.S.
Northeast power marketing contracts |
|
|
0.01 |
|
|
|
— |
|
|
|
0.01 |
|
|
|
— |
|
Net gain
on sales of U.S. Northeast power generation assets |
|
|
— |
|
|
|
(0.30 |
) |
|
|
— |
|
|
|
(0.29 |
) |
Integration and acquisition related costs – Columbia |
|
|
— |
|
|
|
0.02 |
|
|
|
— |
|
|
|
0.04 |
|
Keystone
XL asset costs |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
0.01 |
|
Keystone
XL income tax recoveries |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(0.01 |
) |
Risk management activities |
|
|
(0.03 |
) |
|
|
0.03 |
|
|
|
0.12 |
|
|
|
0.05 |
|
Comparable earnings per common share |
|
|
$0.86 |
|
|
$0.76 |
|
|
$1.83 |
|
|
$1.56 |
|
1 |
|
Risk management activities |
|
three months ended
June 30 |
|
six months ended
June 30 |
|
|
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Power |
|
1 |
|
|
3 |
|
|
3 |
|
|
4 |
|
|
|
U.S. Power |
|
39 |
|
|
(94 |
) |
|
(62 |
) |
|
(156 |
) |
|
|
Liquids marketing |
|
62 |
|
|
4 |
|
|
55 |
|
|
4 |
|
|
|
Natural Gas
Storage |
|
(3 |
) |
|
(4 |
) |
|
(6 |
) |
|
1 |
|
|
|
Foreign exchange |
|
(60 |
) |
|
41 |
|
|
(139 |
) |
|
56 |
|
|
|
Income tax attributable
to risk management activities |
|
(11 |
) |
|
26 |
|
|
41 |
|
|
46 |
|
|
|
Total unrealized gains/(losses) from risk management
activities |
|
28 |
|
|
(24 |
) |
|
(108 |
) |
|
(45 |
) |
Comparable earnings increased by $109 million or $0.10 per
common share for the three months ended June 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, higher volumes on the Keystone Pipeline System
and increased earnings from liquids marketing activities
- lower income tax expense primarily due to lower income tax
rates as a result of U.S. Tax Reform
- 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 U.S. Power mainly due to the sale of the
U.S. Northeast power generation assets in second quarter 2017
- lower earnings from Bruce Power primarily due to lower volumes
resulting from increased outage days
- lower Eastern Power results mainly due to the sale of our
Ontario solar assets in December 2017.
Comparable earnings increased by $275 million or $0.27 per
common share for the six months ended June 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, higher volumes on the Keystone Pipeline System
and increased earnings from liquids marketing activities
- lower income tax expense primarily due to lower income tax
rates as a result of U.S. Tax Reform
- higher interest income and other primarily resulting from
realized gains in 2018 compared to realized losses in 2017 on
derivatives used to manage our net exposure to foreign exchange
rate fluctuations on U.S. dollar-denominated income
- lower earnings from U.S. Power mainly due to the sale of the
U.S. Northeast power generation assets in second quarter 2017
- 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
- 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 six
months ended June 30, 2018 also reflect the effect 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, H.R. 1, the Tax Cuts and Jobs Act (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, deferred income tax assets and deferred
income tax 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, 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 interstate pipelines 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 pipeline's return on
equity (ROE) assuming a single-issue adjustment to a pipeline’s
rates; and (3) a NOI 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 (collectively, the “2018
FERC Actions”). The Final Rule will become
effective September 13, 2018, and is subject to requests
for further rehearing and clarification. Each is
described below.
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 accumulated deferred income
taxes 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
accumulated deferred income tax 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
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 No.
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. Pipelines filing the
FERC Form No. 501-G will have four options:
- make a limited Natural Gas Act Section 4 filing to reduce its
rates by the reduction in its cost-of-service shown in
its FERC Form No. 501-G. For any pipeline electing this
option, FERC guarantees a three-year moratorium on Natural Gas Act
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 accumulated
deferred income tax balance used for rate-making purposes. In
situations where the accumulated deferred income tax 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.
We are evaluating this Final Rule and our next courses
of action, however, we do not expect an immediate or a retroactive
impact from the Final Rule or the Revised Policy
Statement described above.
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 accumulated deferred income taxes 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 accumulated deferred
income taxes for MLP pipelines, finding that if an MLP pipeline's
income tax allowance is eliminated from its cost-of-service rates,
then its existing accumulated deferred income tax 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 they
are held through wholly-owned taxable corporations and, in
addition, a significant proportion of their 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, some of which may be
accelerated by the Final Rule, 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 wholly-owned U.S.
natural gas pipelines is expected to be limited in comparison
to pre-U.S. Tax Reform.
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
At the time and as a result 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 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 Amended 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
We are analyzing the impact of the 2018 FERC Actions on our TC
PipeLines, LP assets, particularly considering the changes noted
above and alternatives now available under the Final Rule. While a
number of uncertainties exist with respect to the changes, TC
PipeLines, LP’s earnings, cash flows and financial position could
be materially adversely impacted. Should we or TC PipeLines, LP
choose to proactively address the issues contemplated by the 2018
FERC Actions, prospective changes in certain pipeline systems'
rates could occur as early as late 2018. However, the impact in
2018 is expected to be limited, while subsequent periods for TC
PipeLines, LP 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. 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
our consolidated earnings or cash flow.
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 accumulated deferred income tax liability from
rate base, thus increasing rate base in general, may 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.
Until the 2018 FERC Actions are implemented through
individual rate proceedings or settlements and we and TC
PipeLines, LP have fully evaluated our respective alternatives to
minimize any negative impact, we believe that it is not more likely
than not that the fair value of any of the reporting units is less
than its respective carrying value. Therefore, a goodwill
impairment test has not been performed in 2018 to date. We
also determined there is no indication that the carrying values of
plant, property and equipment and equity investments potentially
impacted by the 2018 FERC Actions are not recoverable. We will
continue to monitor developments and assess our goodwill for
impairment as well as review our property, plant and equipment and
equity investments for recoverability as new information becomes
available.
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 2018 FERC Actions, once finalized, could result in a
goodwill impairment charge. The goodwill balance for Great Lakes is
US$573 million at June 30, 2018 (December 31, 2017 - US$573
million). There is also a risk that the goodwill balance of US$82
million at June 30, 2018 (December 31, 2017 - US$82 million)
related to Tuscarora could be negatively impacted by the 2018 FERC
Actions.
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 rate-regulated accounting (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 regulatory, tax and
accounting authorities as well as through our
elections of specific treatments allowed under the Final Rule
described above. Should additional guidance be provided by these
authorities or other sources during the one-year measurement period
permitted by the SEC, we will review the provisional amounts and
adjust as appropriate. Other than the amortizations discussed below
and the foreign exchange impacts, no adjustments were made to these
amounts during second quarter 2018. Once the final
impact of the 2018 FERC Actions is determined there may be
prospective adjustments to our net regulatory liabilities.
Commencing January 1, 2018, we have amortized the net regulatory
liabilities using the Reverse South Georgia methodology. Under this
methodology, rate-regulated entities determine amortization based
on their composite depreciation rate and immediately begin
recording amortization. For the three and six months ended
June 30, 2018, amortization of the net regulatory liabilities
in the amount of $15 million and $24 million, respectively, was
recorded and included in Revenues.
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 flow.
Our capital program consists of approximately $28 billion of
near-term investments and approximately $24 billion of
commercially-supported medium to longer-term projects. Amounts
presented exclude capitalized interest and AFUDC.
Beginning in second quarter 2018, we have included three years
of maintenance capital expenditures for all of our businesses in
the following 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 market
conditions, route refinement, permitting conditions, scheduling and
timing of regulatory permits.
Near-term projects
|
|
Expected in-service |
|
Estimated project |
|
|
Carrying value |
|
(unaudited - billions of $) |
|
date |
|
cost1 |
|
|
at June 30, 2018 |
|
Canadian
Natural Gas Pipelines |
|
|
|
|
|
|
Canadian Mainline |
|
2018-2021 |
|
0.2 |
|
|
— |
|
NGTL System |
|
2018 |
|
0.6 |
|
|
0.4 |
|
|
|
2019 |
|
2.6 |
|
|
0.5 |
|
|
|
2020 |
|
1.7 |
|
|
0.1 |
|
|
|
2021+ |
|
2.5 |
|
|
— |
|
Regulated maintenance
capital expenditures |
|
2018-2020 |
|
2.5 |
|
|
0.2 |
|
U.S. Natural
Gas Pipelines |
|
|
|
|
|
|
Columbia Gas |
|
|
|
|
|
|
Mountaineer XPress |
|
2018 |
|
US
3.0 |
|
|
US
1.4 |
|
WB
XPress |
|
2018 |
|
US
0.9 |
|
|
US
0.6 |
|
Modernization II |
|
2018-2020 |
|
US
1.1 |
|
|
US
0.3 |
|
Buckeye
XPress |
|
2020 |
|
US
0.2 |
|
|
— |
|
Columbia Gulf |
|
|
|
|
|
|
Gulf
XPress |
|
2018 |
|
US
0.6 |
|
|
US
0.4 |
|
Other |
|
2018-2020 |
|
US
0.3 |
|
|
US
0.1 |
|
Regulated maintenance
capital expenditures |
|
2018-2020 |
|
US
1.9 |
|
|
US
0.2 |
|
Mexico Natural
Gas Pipelines |
|
|
|
|
|
|
Sur de Texas |
|
2018 |
|
US
1.3 |
|
|
US
1.2 |
|
Villa de Reyes |
|
2019 |
|
US
0.8 |
|
|
US
0.6 |
|
Tula |
|
2020 |
|
US
0.7 |
|
|
US
0.5 |
|
Liquids
Pipelines |
|
|
|
|
|
|
White Spruce |
|
2019 |
|
0.2 |
|
|
0.1 |
|
Recoverable maintenance
capital expenditures |
|
2018-2020 |
|
0.1 |
|
|
— |
|
Energy |
|
|
|
|
|
|
Napanee2 |
|
2018 |
|
1.5 |
|
|
1.3 |
|
Bruce Power – life
extension3 |
|
up to
2020 |
|
0.9 |
|
|
0.3 |
|
Other |
|
|
|
|
|
|
Non-recoverable maintenance capital expenditures4 |
|
2018-2020 |
|
0.7 |
|
|
0.1 |
|
|
|
|
|
24.3 |
|
|
8.3 |
|
Foreign
exchange impact on near-term projects5 |
|
|
|
3.3 |
|
|
1.6 |
|
Total near-term projects (Cdn$) |
|
|
|
27.6 |
|
|
9.9
|
|
1 Amounts reflect our proportionate share of joint
venture costs where applicable and 100% of costs related to
wholly-owned assets and assets held through TC PipeLines, LP.
2 Reflects increased costs required to bring facility
into service in fourth quarter 2018.
3 Reflects our proportionate share of the remaining
capital costs that Bruce Power expects to incur on its life
extension investment programs in advance of the Unit 6 major
refurbishment outage which is expected to begin in 2020.
4 Includes non-recoverable maintenance capital
expenditures from all segments and is primarily comprised of Bruce
Power cash calls and other Energy amounts.
5 Reflects U.S./Canada foreign exchange rate of 1.31 at
June 30, 2018.
Medium to longer-term projects
The medium to longer-term projects have greater uncertainty with
respect to timing and estimated project costs. The expected
in-service dates of these projects are post-2020, and costs
provided in the schedule below reflect the most recent costs for
each project as filed with the various regulatory authorities or
otherwise determined. These projects are subject to approvals that
include FID and/or complex regulatory processes, however, each
project has commercial support except where noted.
|
|
Estimated project |
|
|
Carrying value |
|
(unaudited - billions of $) |
|
cost1 |
|
|
at June 30, 2018 |
|
|
|
|
|
|
Canadian
Natural Gas Pipelines |
|
|
|
|
Canadian west coast
LNG-related projects |
|
|
|
|
Coastal
GasLink2 |
|
4.8 |
|
|
0.5 |
|
NGTL
System – Merrick |
|
1.9 |
|
|
— |
|
Liquids
Pipelines |
|
|
|
|
Heartland and TC
Terminals2,3 |
|
0.9 |
|
|
0.1 |
|
Grand Rapids Phase
2 |
|
0.7 |
|
|
— |
|
Keystone
XL4 |
|
US
8.0 |
|
|
US
0.3 |
|
Keystone Hardisty
Terminal2,3,4 |
|
0.3 |
|
|
0.1 |
|
Energy |
|
|
|
|
Bruce
Power – life extension |
|
5.3 |
|
|
— |
|
|
|
21.9 |
|
|
1.0 |
|
Foreign exchange impact
on medium to longer-term projects5 |
|
2.5 |
|
|
0.1 |
|
Total medium to longer-term projects (Cdn$) |
|
24.4 |
|
|
1.1 |
|
1 Amounts reflect our proportionate share of joint
venture costs where applicable and 100% of costs related to
wholly-owned assets and assets held through TC PipeLines, LP.
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 U.S./Canada foreign exchange rate of 1.31 at
June 30, 2018.
Outlook
Consolidated comparable earnings
We expect consolidated comparable earnings on a per common share
basis for the second half of 2018 to be similar to the results
achieved in the first half of the year. Our overall comparable
earnings outlook for 2018 has increased compared to what was
included in the 2017 Annual Report primarily due to:
- improved earnings from additional contract sales and lower
expenses 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.
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 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 near-term capital program in 2018,
as well as the capitalization of costs to further advance our
medium to longer-term projects.
Canadian Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
equivalent GAAP measure).
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
NGTL System |
|
311 |
|
|
236 |
|
|
582 |
|
|
466 |
|
Canadian Mainline |
|
204 |
|
|
264 |
|
|
397 |
|
|
511 |
|
Other1 |
|
30 |
|
|
27 |
|
|
60 |
|
|
54 |
|
Comparable
EBITDA |
|
545 |
|
|
527 |
|
|
1,039 |
|
|
1,031 |
|
Depreciation and
amortization |
|
(265 |
) |
|
(222 |
) |
|
(506 |
) |
|
(444 |
) |
Comparable EBIT and segmented earnings |
|
280 |
|
|
305 |
|
|
533 |
|
|
587 |
|
1 Includes results from Foothills, Ventures LP, Great
Lakes Canada, our share of equity income from our investment in
TQM, general and administrative and business development costs
related to our Canadian Natural Gas Pipelines.
Canadian Natural Gas Pipelines segmented earnings decreased by
$25 million and $54 million for the three and six months ended
June 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
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
2017 |
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
Net
Income |
|
|
|
|
|
|
|
|
NGTL
System |
|
96 |
|
87 |
|
188 |
|
169 |
Canadian
Mainline |
|
44 |
|
48 |
|
81 |
|
100 |
Average
investment base |
|
|
|
|
|
|
|
|
NGTL
System |
|
|
|
|
|
9,250 |
|
8,043 |
Canadian Mainline |
|
|
|
|
|
3,829 |
|
4,131 |
Net income for the NGTL System increased by $9 million and $19
million for the three and six months ended June 30, 2018
compared to the same periods in 2017 mainly due to a higher average
investment base as a result of continued system expansions,
partially offset by lower incentive earnings. On June 19, 2018, the
NEB approved NGTL's 2018-2019 Revenue Requirement Settlement
Application (the 2018-2019 Settlement). The 2018-2019 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 $4 million and
$19 million for the three and six months ended June 30, 2018
compared to the same periods in 2017 primarily because no incentive
earnings have been recorded in 2018 pending an NEB decision on the
2018 - 2020 Tolls Review. As a result, 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 $43 million and $62
million for the three and six months ended June 30, 2018
compared to the same periods in 2017 mainly due to facilities that
were placed in service for the NGTL System and an increase in the
approved depreciation rates in the 2018-2019 Settlement.
U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
equivalent GAAP measure).
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of US$, unless noted otherwise) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Columbia Gas |
|
202 |
|
|
136 |
|
|
433 |
|
|
321 |
|
ANR |
|
118 |
|
|
93 |
|
|
259 |
|
|
215 |
|
TC PipeLines,
LP1,2,3 |
|
33 |
|
|
27 |
|
|
72 |
|
|
59 |
|
Great
Lakes4 |
|
21 |
|
|
13 |
|
|
56 |
|
|
40 |
|
Midstream |
|
29 |
|
|
20 |
|
|
59 |
|
|
43 |
|
Columbia Gulf |
|
30 |
|
|
21 |
|
|
56 |
|
|
39 |
|
Other U.S.
pipelines3,5 |
|
16 |
|
|
22 |
|
|
31 |
|
|
50 |
|
Non-controlling
interests6 |
|
97 |
|
|
78 |
|
|
215 |
|
|
186 |
|
Comparable EBITDA |
|
546 |
|
|
410 |
|
|
1,181 |
|
|
953 |
|
Depreciation and amortization |
|
(128 |
) |
|
(112 |
) |
|
(250 |
) |
|
(224 |
) |
Comparable
EBIT |
|
418 |
|
|
298 |
|
|
931 |
|
|
729 |
|
Foreign
exchange impact |
|
123 |
|
|
103 |
|
|
258 |
|
|
243 |
|
Comparable
EBIT (Cdn$) |
|
541 |
|
|
401 |
|
|
1,189 |
|
|
972 |
|
Specific items: |
|
|
|
|
|
|
|
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
— |
|
|
— |
|
|
(10 |
) |
Segmented earnings (Cdn$) |
|
541 |
|
|
401 |
|
|
1,189 |
|
|
962 |
|
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 June 30, 2018, our ownership interest in TC
PipeLines, LP was 25.5 per cent compared to 26.3 per cent for the
same period in 2017. Our ownership interest for the six months
ended June 30, 2018 ranged from 25.7 to 25.5 per cent compared to a
range of 26.5 to 26.3 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 $140
million and $227 million for the three and six months ended
June 30, 2018 compared to the same periods in 2017.
Segmented earnings for the six months ended June 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. As well, 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.
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 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$136 million and US$228 million for the three and six months
ended June 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 in
Midstream
- increased earnings due to the amortization of the net
regulatory liabilities recognized in 2017 as a result of U.S. Tax
Reform.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by US$16 million and US$26
million for the three and six months ended June 30, 2018
compared to the same periods in 2017 mainly due to new projects
placed in service.
Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
equivalent GAAP measure).
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of US$, unless noted otherwise) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Topolobampo |
|
42 |
|
|
40 |
|
|
86 |
|
|
80 |
|
Tamazunchale |
|
32 |
|
|
27 |
|
|
63 |
|
|
56 |
|
Mazatlán |
|
19 |
|
|
17 |
|
|
39 |
|
|
33 |
|
Guadalajara |
|
16 |
|
|
17 |
|
|
35 |
|
|
34 |
|
Sur de
Texas1 |
|
1 |
|
|
7 |
|
|
10 |
|
|
11 |
|
Other |
|
— |
|
|
— |
|
|
4 |
|
|
— |
|
Comparable EBITDA |
|
110 |
|
|
108 |
|
|
237 |
|
|
214 |
|
Depreciation and
amortization |
|
(18 |
) |
|
(19 |
) |
|
(37 |
) |
|
(36 |
) |
Comparable EBIT |
|
92 |
|
|
89 |
|
|
200 |
|
|
178 |
|
Foreign exchange
impact |
|
26 |
|
|
31 |
|
|
55 |
|
|
60 |
|
Comparable EBIT and segmented earnings (Cdn$) |
|
118 |
|
|
120 |
|
|
255 |
|
|
238 |
|
1 Represents equity income from our 60 per cent
interest.
Mexico Natural Gas Pipelines segmented earnings decreased by $2
million and increased by $17 million for the three and six months
ended June 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 2018 had a negative
impact on Canadian dollar equivalent segmented earnings from our
Mexico operations compared to the same period in 2017.
Comparable EBITDA for Mexico Natural Gas Pipelines increased by
US$2 million and US$23 million for the three and six months ended
June 30, 2018 compared to the same periods in 2017 and was
primarily due to higher revenues from operations as a result of
changes in timing of revenue recognition, partially offset by lower
equity earnings from our investment in our Sur de Texas pipeline
due to higher interest expense from an inter-affiliate loan with
TransCanada. The interest expense on the inter-affiliate loan is
fully offset in Interest income and other.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization remained largely consistent for the
three and six months ended June 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
equivalent GAAP measure).
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Keystone Pipeline
System |
|
352 |
|
|
329 |
|
|
692 |
|
|
635 |
|
Intra-Alberta
pipelines |
|
37 |
|
|
— |
|
|
76 |
|
|
— |
|
Other1 |
|
24 |
|
|
3 |
|
|
76 |
|
|
9 |
|
Comparable
EBITDA |
|
413 |
|
|
332 |
|
|
844 |
|
|
644 |
|
Depreciation and amortization |
|
(85 |
) |
|
(80 |
) |
|
(168 |
) |
|
(157 |
) |
Comparable
EBIT |
|
328 |
|
|
252 |
|
|
676 |
|
|
487 |
|
Specific items: |
|
|
|
|
|
|
|
|
Keystone
XL asset costs |
|
— |
|
|
(5 |
) |
|
— |
|
|
(13 |
) |
Risk
management activities |
|
62 |
|
|
4 |
|
|
55 |
|
|
4 |
|
Segmented earnings |
|
390 |
|
|
251 |
|
|
731 |
|
|
478 |
|
|
|
|
|
|
|
|
|
|
Comparable EBIT
denominated as follows: |
|
|
|
|
|
|
|
|
Canadian dollars |
|
89 |
|
|
57 |
|
|
182 |
|
|
112 |
|
U.S. dollars |
|
185 |
|
|
146 |
|
|
387 |
|
|
281 |
|
Foreign
exchange impact |
|
54 |
|
|
49 |
|
|
107 |
|
|
94 |
|
|
|
328 |
|
|
252 |
|
|
676 |
|
|
487 |
|
1 Includes primarily liquids marketing and business
development activities.
Liquids Pipelines segmented earnings increased by $139 million
and $253 million for the three and six months ended June 30,
2018 compared to the same periods in 2017 and included:
- 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 gains in 2018 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.
Comparable EBITDA for Liquids Pipelines increased by $81 million
and $200 million for the three and six months ended June 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
- higher contracted and spot volumes on the Keystone Pipeline
System
- a higher contribution from liquids marketing activities
- lower business development costs as a result of capitalizing
Keystone XL expenditures
- a weaker U.S. dollar which had a negative impact on the
Canadian dollar equivalent earnings from our U.S. operations.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased by $5 million and $11
million for the three and six months ended June 30, 2018
compared to the same periods in 2017 as a result of new facilities
being placed in service, partially offset by the effect of a weaker
U.S. dollar.
Energy
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
equivalent GAAP measure).
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of Canadian $, unless noted otherwise) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Canadian Power |
|
|
|
|
|
|
|
|
Western
Power |
|
34 |
|
|
23 |
|
|
71 |
|
|
53 |
|
Eastern
Power1 |
|
70 |
|
|
83 |
|
|
152 |
|
|
177 |
|
Bruce
Power1 |
|
91 |
|
|
132 |
|
|
145 |
|
|
223 |
|
U.S. Power
(US$)2 |
|
— |
|
|
32 |
|
|
— |
|
|
86 |
|
Foreign
exchange impact on U.S. Power |
|
— |
|
|
9 |
|
|
— |
|
|
27 |
|
Natural Gas Storage and
other |
|
10 |
|
|
11 |
|
|
17 |
|
|
32 |
|
Business
Development |
|
(3 |
) |
|
(3 |
) |
|
(7 |
) |
|
(6 |
) |
Comparable
EBITDA |
|
202 |
|
|
287 |
|
|
378 |
|
|
592 |
|
Depreciation and
amortization |
|
(33 |
) |
|
(39 |
) |
|
(65 |
) |
|
(79 |
) |
Comparable EBIT |
|
169 |
|
|
248 |
|
|
313 |
|
|
513 |
|
Specific items: |
|
|
|
|
|
|
|
|
U.S.
Northeast power marketing contracts |
|
(15 |
) |
|
— |
|
|
(7 |
) |
|
— |
|
Net gain
on sales of U.S. Northeast power generation assets |
|
— |
|
|
492 |
|
|
— |
|
|
481 |
|
Risk
management activities |
|
37 |
|
|
(95 |
) |
|
(65 |
) |
|
(151 |
) |
Segmented earnings |
|
191 |
|
|
645 |
|
|
241 |
|
|
843 |
|
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 $454 million and $602
million for the three and six months ended June 30, 2018
compared to the same periods in 2017 and included the following
specific items:
- a loss of $7 million year-to-date related to our U.S. Northeast
power marketing contracts which included a loss of $15 million in
second quarter and a gain of $8 million in first quarter primarily
due to income recognized 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 will continue to run-off through to
mid-2020
- a net gain of $492 million and $481 million before tax for the
three and six months ended June 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
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $, pre-tax) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Canadian Power |
|
1 |
|
|
3 |
|
|
3 |
|
|
4 |
|
U.S. Power |
|
39 |
|
|
(94 |
) |
|
(62 |
) |
|
(156 |
) |
Natural Gas Storage and
Other |
|
(3 |
) |
|
(4 |
) |
|
(6 |
) |
|
1 |
|
Total unrealized gains/(losses) from risk management
activities |
|
37 |
|
|
(95 |
) |
|
(65 |
) |
|
(151 |
) |
The variances in these unrealized gains and losses reflect the
impact of changes in forward natural gas and power prices and the
volume of our positions for these derivatives over a certain period
of time, however, they do not accurately reflect the gains and
losses that will be realized on settlement, or the offsetting
impacts of other derivative and non-derivative transactions that
make up our business as a whole. As a result, we do not consider
them reflective of our underlying operations.
Comparable EBITDA for Energy decreased by $85 million and $214
million for the three and six months ended June 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 sale of the
U.S. Northeast power generation assets in second quarter 2017
- decreased Bruce Power earnings primarily due to lower volumes
resulting from increased outage days and lower results from
contracting activities. Additional financial and operating
information on Bruce Power is provided below
- lower Eastern Power results mainly due to the sale of our
Ontario solar assets in December 2017
- decreased Natural Gas Storage year-to-date results primarily
due to lower realized natural gas storage price spreads
- increased Western Power results due to higher realized margins
on higher generation volumes.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization decreased by $6 million and $14
million for the three and six months ended June 30, 2018
compared to the same periods in 2017 following the sale of our
Ontario solar assets in December 2017.
BRUCE POWER
The following reflects our proportionate share of the components of
comparable EBITDA and comparable EBIT.
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $, unless noted otherwise) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Equity income included
in comparable EBITDA and EBIT comprised of: |
|
|
|
|
|
|
|
|
Revenues |
|
|
385 |
|
|
|
428 |
|
|
|
756 |
|
|
|
829 |
|
Operating
expenses |
|
|
(209 |
) |
|
|
(209 |
) |
|
|
(436 |
) |
|
|
(433 |
) |
Depreciation and other |
|
|
(85 |
) |
|
|
(87 |
) |
|
|
(175 |
) |
|
|
(173 |
) |
Comparable EBITDA and EBIT1 |
|
|
91 |
|
|
|
132 |
|
|
|
145 |
|
|
|
223 |
|
Bruce
Power – other information |
|
|
|
|
|
|
|
|
Plant
availability2 |
|
|
89 |
% |
|
|
92 |
% |
|
|
87 |
% |
|
|
91 |
% |
Planned outage
days |
|
|
76 |
|
|
|
41 |
|
|
|
150 |
|
|
|
97 |
|
Unplanned outage
days |
|
|
3 |
|
|
|
3 |
|
|
|
34 |
|
|
|
20 |
|
Sales volumes
(GWh)1 |
|
|
6,027 |
|
|
|
6,309 |
|
|
|
11,723 |
|
|
|
12,292 |
|
Realized
sales price per MWh3 |
|
$67 |
|
|
$68 |
|
|
$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 is expected to occur on
Units 3 and 8 in the second half of 2018. 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
equivalent GAAP measure).
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Comparable
EBITDA and EBIT |
|
(15 |
) |
|
(12 |
) |
|
(17 |
) |
|
(16 |
) |
Specific items: |
|
|
|
|
|
|
|
|
Foreign
exchange gain/(loss) – inter-affiliate loan1 |
|
87 |
|
|
(8 |
) |
|
8 |
|
|
(8 |
) |
Integration and acquisition related costs – Columbia |
|
— |
|
|
(20 |
) |
|
— |
|
|
(49 |
) |
Segmented earnings/(losses) |
|
72 |
|
|
(40 |
) |
|
(9 |
) |
|
(73 |
) |
1 Reported in Income from equity investments in our
Corporate segment.
Corporate segmented earnings increased by $112 million for the
three months ended June 30, 2018 compared to the same period
in 2017. For the six months ended June 30, 2018, Corporate
segmented loss decreased by $64 million compared to the same period
in 2017. These results included the following specific items that
have been excluded from comparable EBIT:
- foreign exchange gains and losses 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 losses and gains included in
Interest income and other on the inter-affiliate loan receivable
which fully offset these amounts
- in 2017, pre-tax integration and acquisition costs associated
with the acquisition of Columbia.
OTHER INCOME STATEMENT ITEMS
Interest expense
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Interest on
long-term debt and junior subordinated notes |
|
|
|
|
|
|
|
|
Canadian
dollar-denominated |
|
(131 |
) |
|
(118 |
) |
|
(265 |
) |
|
(226 |
) |
U.S.
dollar-denominated |
|
(332 |
) |
|
(323 |
) |
|
(646 |
) |
|
(640 |
) |
Foreign
exchange impact |
|
(97 |
) |
|
(111 |
) |
|
(180 |
) |
|
(214 |
) |
|
|
(560 |
) |
|
(552 |
) |
|
(1,091 |
) |
|
(1,080 |
) |
Other interest and
amortization expense |
|
(28 |
) |
|
(28 |
) |
|
(50 |
) |
|
(45 |
) |
Capitalized interest |
|
30 |
|
|
56 |
|
|
56 |
|
|
101 |
|
Interest expense |
|
(558 |
) |
|
(524 |
) |
|
(1,085 |
) |
|
(1,024 |
) |
Interest expense increased by $34 million and $61 million for
the three and six months ended June 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
construction of Grand Rapids and Northern Courier in 2017
- final repayment of the Columbia acquisition bridge facilities
in June 2017 resulting in lower interest expense and debt
amortization expense
- the positive impact of a weaker U.S. dollar in translating U.S.
dollar denominated interest.
Allowance for funds used during
construction
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Canadian
dollar-denominated |
|
21 |
|
|
55 |
|
|
41 |
|
|
105 |
|
U.S.
dollar-denominated |
|
72 |
|
|
49 |
|
|
139 |
|
|
87 |
|
Foreign exchange
impact |
|
20 |
|
|
17 |
|
|
38 |
|
|
30 |
|
Allowance for funds used during construction |
|
113 |
|
|
121 |
|
|
218 |
|
|
222 |
|
AFUDC decreased by $8 million and $4 million for the three and
six months ended June 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 the NGTL 2017 Expansion
Program.
The increase in U.S. dollar-denominated AFUDC is primarily due
to additional investment in and higher AFUDC rates on Columbia Gas
growth projects and continued investment in Mexico projects.
Interest income and other
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Interest income
and other included in comparable earnings |
|
55 |
|
|
40 |
|
|
118 |
|
|
45 |
|
Specific items: |
|
|
|
|
|
|
|
|
Foreign
exchange (loss)/gain – inter-affiliate loan |
|
(87 |
) |
|
8 |
|
|
(8 |
) |
|
8 |
|
Risk management activities |
|
(60 |
) |
|
41 |
|
|
(139 |
) |
|
56 |
|
Interest income and other |
|
(92 |
) |
|
89 |
|
|
(29 |
) |
|
109 |
|
Interest income and other decreased by $181
million and $138 million for the three and six months ended
June 30, 2018 compared to the same periods in 2017 and was
primarily the net effect of:
- interest income partially offset by the foreign exchange loss
related to an inter-affiliate loan receivable from the Sur de Texas
joint venture. The corresponding interest expense and foreign
exchange gain are reflected in Income from equity investments in
the Mexico Natural Gas Pipelines and Corporate segments,
respectively. The offsetting currency-related 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
- foreign exchange impact on the translation of foreign currency
denominated working capital balances
- realized gains in 2018 compared to realized losses in 2017 on
derivatives used to manage our net exposure to foreign exchange
rate fluctuations on U.S. dollar-denominated income
- income of $18 million related to reimbursement of Coastal
GasLink project costs recorded in 2017.
Income tax expense
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Income tax
expense included in comparable earnings |
|
(146 |
) |
|
(198 |
) |
|
(317 |
) |
|
(442 |
) |
Specific items: |
|
|
|
|
|
|
|
|
U.S.
Northeast power marketing contracts |
|
4 |
|
|
— |
|
|
2 |
|
|
— |
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
5 |
|
|
— |
|
|
20 |
|
Keystone
XL asset costs |
|
— |
|
|
1 |
|
|
— |
|
|
2 |
|
Net gain
on sales of U.S. Northeast power generation assets |
|
— |
|
|
(227 |
) |
|
— |
|
|
(226 |
) |
Keystone
XL income tax recoveries |
|
— |
|
|
— |
|
|
— |
|
|
7 |
|
Risk
management activities |
|
(11 |
) |
|
26 |
|
|
41 |
|
|
46 |
|
Income tax expense |
|
(153 |
) |
|
(393 |
) |
|
(274 |
) |
|
(593 |
) |
Income tax expense included in comparable earnings decreased by
$52 million and $125 million for the three and six months ended
June 30, 2018 compared to the same periods in 2017 mainly 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
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Net income attributable to non-controlling
interests |
|
(76 |
) |
|
(55 |
) |
|
(170 |
) |
|
(145 |
) |
Net income attributable to non-controlling interests increased
by $21 million and $25 million for the three and six months ended
June 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 six months ended
June 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
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Preferred share dividends |
|
(41 |
) |
|
(39 |
) |
|
(81 |
) |
|
(80 |
) |
Preferred share dividends remained largely consistent for the
three and six months ended June 30, 2018 compared to the same
periods in 2017.
Recent developments
CANADIAN NATURAL GAS PIPELINES
NGTL System
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 still being finalized and are currently
anticipated to increase NGTL’s capital program by approximately
$0.1 billion, to $7.4 billion, excluding maintenance capital
expenditures.
North Montney Project Approval
On May 23, 2018, the NEB issued a report recommending the Federal
government approve the application for a variance 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 Federal government approved the
recommendation on June 22, 2018 and on July 2, 2018 the NEB issued
an amending order for the project.
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 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 is anticipated to be in
service by second quarter 2020.
NGTL 2018-2019 Revenue Requirement Settlement
Approval
On June 19, 2018, the NEB approved the 2018-2019 Settlement, as
filed, for final 2018 tolls and revised interim 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.
2021 NGTL System Expansion Project
Application
On June 20, 2018, we filed an application with the NEB for approval
to construct and operate the 2021 Expansion Project. The project,
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.
Sundre Crossover 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.
Canadian Mainline
Canadian Mainline 2018 - 2020 Toll Review
On March 16, 2018, the NEB provided its Notice of Public Hearing
for our Supplemental Agreement with the Eastern LDCs filed on
December 18, 2017. Our reply evidence is due September 18, 2018.
The NEB will provide further details regarding an oral or written
hearing process to consider the written submissions of the
interested parties.
Maple Compressor Expansion Project
We continue to await an NEB decision on our application seeking
project approval and are reviewing project plans to continue to
meet our in-service timelines.
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 after. 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.
TC PipeLines, LP
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. A number of uncertainties exist with respect to the
changes resulting from the 2018 FERC Actions, which could
materially adversely impact the earnings, cash flows and financial
position of TC PipeLines, LP. Cash retained by TC PipeLines, LP is
being used to fund its ongoing capital expenditures as well as the
repayment of debt to prudently manage its financial metrics in
anticipation of a reduction in revenues should its pipeline
systems’ rates be reset in response to the 2018 FERC Actions. 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.
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.
Mountaineer XPress and WB XPress
In first quarter 2018, estimated project costs were revised upwards
to US$3.0 billion for Mountaineer XPress and US$0.9 billion for WB
XPress, representing increases of US$0.4 billion and US$0.1
billion, respectively. These increases primarily 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 and resources to maintain
our projected in-service dates.
Great Lakes and Northern Border 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.
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 it 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 of late
2018.
Tula and Villa de Reyes
We continue to work toward finalizing amending agreements for both
of these pipelines with the CFE to formalize the schedule and
payments resulting from their respective force majeure events. The
CFE has commenced payments on both pipelines in accordance with the
TSAs.
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
hear the appeal case against the PSC’s alternative route itself. We
expect the Nebraska Supreme Court, as the final arbiter, could
reach a decision by late 2018 or first quarter 2019.
On May 15, 2018, the U.S. Department of State filed a notice of
its intent to prepare an environmental assessment for the Keystone
XL mainline alternative route in Nebraska. Public comments were due
in June 2018. On July 30, 2018, the U.S. Department of State
issued a draft environmental assessment. Comments on the draft are
to be filed by August 29, 2018. We expect the U.S. Department of
State will have completed the supplemental environmental review by
third or fourth quarter 2018.
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, 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 may be issued by year-end 2018.
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 August 1, 2018, we entered
into an agreement to sell our interests in the Cartier Wind power
facilities in Québec to Innergex Renewable Energy
Inc. for gross proceeds of $630 million before closing
adjustments. The sale is expected to be completed in fourth quarter
2018 subject to certain regulatory and other approvals and result
in an estimated gain of $175 million ($130 million after tax) which
will be recorded upon closing of the transaction.
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. 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 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. See the 2018 FERC Actions
section for further information.
At June 30, 2018, our current assets totaled $5.4 billion
and current liabilities amounted to $10.4 billion, leaving us with
a working capital deficit of $5.0 billion compared to a working
capital deficit of $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 $9.3 billion of unutilized, unsecured credit
facilities.
CASH PROVIDED BY OPERATING ACTIVITIES
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $, except per share amounts) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Net cash provided by
operations |
|
|
1,805 |
|
|
|
1,353 |
|
|
|
3,217 |
|
|
|
2,655 |
|
(Decrease)/increase in
operating working capital |
|
|
(361 |
) |
|
|
(17 |
) |
|
|
(154 |
) |
|
|
138 |
|
Funds generated from operations1 |
|
|
1,444 |
|
|
|
1,336 |
|
|
|
3,063 |
|
|
|
2,793 |
|
Specific items: |
|
|
|
|
|
|
|
|
U.S.
Northeast power marketing contracts |
|
|
15 |
|
|
|
— |
|
|
|
7 |
|
|
|
— |
|
Integration and acquisition related costs – Columbia |
|
|
— |
|
|
|
20 |
|
|
|
— |
|
|
|
52 |
|
Keystone
XL asset costs |
|
|
— |
|
|
|
5 |
|
|
|
— |
|
|
|
13 |
|
Net loss
on sales of U.S. Northeast power generation assets |
|
|
— |
|
|
|
6 |
|
|
|
— |
|
|
|
17 |
|
Comparable funds generated from
operations1 |
|
|
1,459 |
|
|
|
1,367 |
|
|
|
3,070 |
|
|
|
2,875 |
|
Dividends on preferred
shares |
|
|
(39 |
) |
|
|
(38 |
) |
|
|
(78 |
) |
|
|
(77 |
) |
Distributions paid to
non-controlling interests |
|
|
(48 |
) |
|
|
(69 |
) |
|
|
(117 |
) |
|
|
(149 |
) |
Non-recoverable
maintenance capital expenditures2 |
|
|
(66 |
) |
|
|
(79 |
) |
|
|
(130 |
) |
|
|
(128 |
) |
Comparable
distributable cash flow1 |
|
|
1,306 |
|
|
|
1,181 |
|
|
|
2,745 |
|
|
|
2,521 |
|
Comparable distributable cash flow per common
share1 |
|
$1.46 |
|
|
$1.36 |
|
|
$3.08 |
|
|
$2.90 |
|
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
maintenance capital expenditures for our equity investments.
Expenditures are primarily related to contributions to Bruce Power
to fund our proportionate share of their maintenance capital
expenditures.
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 $92 million and $195 million for the
three and six months ended June 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 six months ended June 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 six months ended June 30,
2018 also reflects the effect of common shares issued under the
Corporate ATM program and DRP in 2017 and 2018.
Beginning in second quarter 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)/PROVIDED BY INVESTING
ACTIVITIES
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Capital
spending |
|
|
|
|
|
|
|
|
Capital
expenditures |
|
(2,337 |
) |
|
(1,792 |
) |
|
(4,039 |
) |
|
(3,352 |
) |
Capital
projects in development |
|
(76 |
) |
|
(56 |
) |
|
(112 |
) |
|
(98 |
) |
Contributions to equity investments |
|
(184 |
) |
|
(473 |
) |
|
(542 |
) |
|
(665 |
) |
|
|
(2,597 |
) |
|
(2,321 |
) |
|
(4,693 |
) |
|
(4,115 |
) |
Proceeds from sales of
assets, net of transaction costs |
|
— |
|
|
4,147 |
|
|
— |
|
|
4,147 |
|
Other distributions
from equity investments |
|
— |
|
|
1 |
|
|
121 |
|
|
364 |
|
Deferred amounts and
other |
|
(16 |
) |
|
(169 |
) |
|
94 |
|
|
(254 |
) |
Net cash (used in)/provided by investing
activities |
|
(2,613 |
) |
|
1,658 |
|
|
(4,478 |
) |
|
142 |
|
Capital expenditures in 2018 were incurred primarily for the
expansion of the Columbia Gas, Columbia Gulf and NGTL System
natural gas pipelines, the construction of Mexico natural gas
pipelines and the Napanee power generating facility.
Costs incurred on capital projects in development in 2018 were
predominantly related to spending on Keystone XL.
Contributions to equity investments decreased in 2018 compared
to 2017 primarily due to lower contributions to our proportionate
share of Sur de Texas debt financing and Grand Rapids, which went
into service in August 2017. This was partially offset by increased
contributions to our Bruce Power and Millennium investments.
Other distributions from equity investments 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 sale 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
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Notes payable
(repaid)/issued, net |
|
(1,327 |
) |
|
111 |
|
|
485 |
|
|
781 |
|
Long-term debt issued,
net of issue costs1 |
|
3,240 |
|
|
817 |
|
|
3,333 |
|
|
817 |
|
Long-term debt
repaid1 |
|
(808 |
) |
|
(4,418 |
) |
|
(2,034 |
) |
|
(5,469 |
) |
Junior subordinated
notes issued, net of issue costs |
|
— |
|
|
1,489 |
|
|
— |
|
|
3,471 |
|
Dividends and
distributions paid |
|
(467 |
) |
|
(435 |
) |
|
(933 |
) |
|
(854 |
) |
Common shares issued,
net of issue costs |
|
445 |
|
|
18 |
|
|
785 |
|
|
36 |
|
Partnership units of TC
PipeLines, LP issued, net of issue costs |
|
— |
|
|
27 |
|
|
49 |
|
|
119 |
|
Common units of
Columbia Pipeline Partners LP acquired |
|
— |
|
|
— |
|
|
— |
|
|
(1,205 |
) |
Net cash provided by/(used in) financing
activities |
|
1,083 |
|
|
(2,391 |
) |
|
1,685 |
|
|
(2,304 |
) |
1 Includes draws and repayments on unsecured loan
facility by TC PipeLines, LP.
LONG-TERM DEBT ISSUED
In second quarter 2018, TCPL issued US$1 billion of Senior
Unsecured Notes due in May 2028 bearing interest at a fixed rate of
4.25 per cent, US$500 million of Senior Unsecured Notes due in May
2038 bearing interest at a fixed rate of 4.75 per cent as well as
an additional US$1 billion of Senior Unsecured Notes due in May
2048 bearing interest at a fixed rate of 4.875 per cent.
In July 2018, TCPL issued $800 million of Medium Term Notes due
in July 2048 bearing interest at a fixed rate of 4.182 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 and to fund our capital program.
LONG-TERM DEBT REPAID
In second quarter 2018, long-term debt repaid included the
retirement of US$500 million by Columbia Pipeline Group, Inc. of
Senior Unsecured Notes bearing interest at a fixed rate of 2.45 per
cent.
In first quarter 2018, long-term debt repaid included
retirements by TCPL of US$500 million of Senior Unsecured Notes
bearing interest at a fixed rate of 1.875 per cent, US$250 million
of Senior Unsecured Notes bearing interest at a floating rate and
$150 million of Debentures bearing interest at a fixed rate of 9.45
per cent.
DIVIDEND REINVESTMENT PLAN
With respect to dividends declared on April 27, 2018, the DRP
participation rate amongst common shareholders was approximately 33
per cent, resulting in $208 million reinvested in common equity
under the program. Year-to-date in 2018, the participation rate
amongst common shareholders has been approximately 36 per cent,
resulting in $442 million of dividends reinvested.
TRANSCANADA CORPORATION ATM EQUITY ISSUANCE
PROGRAM
In the three months ended June 30, 2018, 8.1 million common
shares were issued under our Corporate ATM program at an average
price of $54.63 per common share for gross proceeds of $443
million. Related commissions and fees totaled approximately $4
million, resulting in net proceeds of $439 million. In the six
months ended June 30, 2018, 13.9 million common shares have
been issued under our Corporate ATM program at an average price of
$55.42 per common share for gross proceeds of $772 million. Related
commissions and fees totaled approximately $7 million, resulting in
net proceeds of $765 million.
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,
(Amended Corporate ATM program), 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 Amended Corporate ATM program,
which is effective to July 23, 2019, will be activated 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 six months ended June 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 June 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.
In light 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 will be reactivated.
DIVIDENDS
On August 1, 2018, we declared quarterly dividends as
follows:
Quarterly dividend on our common shares |
$0.69 per share |
Payable
on October 31, 2018 to shareholders of record at the close of
business on September 28, 2018. |
Quarterly dividends on our preferred shares |
|
Series
1
$0.204125 |
Series 2
$0.20069863 |
Series 3
$0.1345 |
Series 4
$0.16080822 |
Payable on September
28, 2018 to shareholders of record at the close of business on
August 31, 2018. |
Series 5
$0.1414375 |
Series 6
$0.17561918 |
Series 7
$0.25 |
Series 9
$0.265625 |
Payable on October 30,
2018 to shareholders of record at the close of business on October
1, 2018. |
Series 11
$0.2375 |
Series 13
$0.34375 |
Series 15
$0.30625 |
Payable
on August 31, 2018 to shareholders of record at the close of
business on August 15, 2018. |
SHARE INFORMATION
as at July 31, 2018 |
|
|
|
|
|
Common
shares |
Issued and outstanding |
|
|
907 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 July 31, 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$0.7 billion |
|
TCPL USA |
|
Used for TCPL USA
general corporate purposes, guaranteed by TCPL |
|
December 2018 |
US$1.0 billion |
|
US$0.4 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 July 31, 2018, our operated affiliates had an additional $0.7
billion of undrawn capacity on committed credit facilities.
See Financial risks and financial instruments for more
information about liquidity, market and other risks.
CONTRACTUAL OBLIGATIONS
Our capital expenditure commitments have risen by approximately
$0.8 billion since December 31, 2017 as a result of the net effect
of increased commitments for Columbia Gas growth projects, NGTL and
Keystone XL, 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 second 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 June 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 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 June 30, 2018,
the balance of our loan receivable from the joint venture totaled
MXN$17.5 billion or $1.2 billion (December 31, 2017 - MXN$14.4
billion or $919 million) and Interest income and other included $29
million and $56 million of interest income on this loan receivable
for the three and six months ended June 30, 2018 (2017 - $3
million and $3 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 vast
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 June 30, 2018 |
1.29 |
|
three
months ended June 30, 2017 |
1.34 |
|
six months ended June 30, 2018 |
1.28 |
|
six
months ended June 30, 2017 |
1.33 |
|
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 June 30 |
|
six months ended June 30 |
(unaudited - millions of US $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
U.S. Natural Gas
Pipelines comparable EBIT |
|
418 |
|
|
298 |
|
|
931 |
|
|
729 |
|
Mexico Natural Gas
Pipelines comparable EBIT1 |
|
114 |
|
|
89 |
|
|
244 |
|
|
178 |
|
U.S. Liquids Pipelines
comparable EBIT |
|
185 |
|
|
146 |
|
|
387 |
|
|
281 |
|
U.S. Power comparable
EBIT2 |
|
— |
|
|
32 |
|
|
— |
|
|
86 |
|
AFUDC on U.S.
dollar-denominated projects |
|
72 |
|
|
49 |
|
|
139 |
|
|
87 |
|
Interest on U.S.
dollar-denominated long-term debt |
|
(332 |
) |
|
(323 |
) |
|
(646 |
) |
|
(640 |
) |
Capitalized interest on
U.S. dollar-denominated capital expenditures |
|
3 |
|
|
1 |
|
|
6 |
|
|
1 |
|
U.S. dollar
non-controlling interests and other |
|
(65 |
) |
|
(44 |
) |
|
(145 |
) |
|
(114 |
) |
|
|
395 |
|
|
248 |
|
|
916 |
|
|
608 |
|
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:
|
|
June 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 |
|
(80 |
) |
|
US 500 |
|
(199 |
) |
|
US
1,200 |
U.S. dollar foreign
exchange options (maturing 2018 to 2019) |
|
(16 |
) |
|
US 2,000 |
|
5 |
|
|
US
500 |
|
|
(96 |
) |
|
US 2,500 |
|
(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 six months ended June 30, 2018,
Net income includes net realized gains of nil and $1 million,
respectively (2017 - $1 million and $2 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) |
|
June 30, 2018 |
|
December 31, 2017 |
|
|
|
|
|
Notional amount |
|
29,000 (US 22,000) |
|
25,400
(US 20,200) |
Fair value |
|
30,800 (US 23,400) |
|
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 $) |
|
June 30, 2018 |
|
|
December 31, 2017 |
|
|
|
|
|
|
Other
current assets |
|
246 |
|
|
332 |
|
Intangible and other assets |
|
63 |
|
|
73 |
|
Accounts payable and other |
|
(355 |
) |
|
(387 |
) |
Other
long-term liabilities |
|
(52 |
) |
|
(72 |
) |
|
|
(98 |
) |
|
(54 |
) |
Unrealized and realized gains/(losses) of derivative
instruments
The following summary does not include hedges of our net investment
in foreign operations.
|
|
three months ended June 30 |
|
six months ended June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Derivative
instruments held for trading1 |
|
|
|
|
|
|
|
|
Amount of unrealized
gains/(losses) in the period |
|
|
|
|
|
|
|
|
Commodities2 |
|
99 |
|
|
(91 |
) |
|
(10 |
) |
|
(147 |
) |
Foreign
exchange |
|
(60 |
) |
|
41 |
|
|
(139 |
) |
|
56 |
|
Amount of realized
gains/(losses) in the period |
|
|
|
|
|
|
|
|
Commodities |
|
19 |
|
|
(37 |
) |
|
129 |
|
|
(85 |
) |
Foreign
exchange |
|
4 |
|
|
(5 |
) |
|
19 |
|
|
(9 |
) |
Derivative
instruments in hedging relationships |
|
|
|
|
|
|
|
|
Amount of realized
(losses)/gains in the period |
|
|
|
|
|
|
|
|
Commodities |
|
(4 |
) |
|
7 |
|
|
(1 |
) |
|
13 |
|
Foreign
exchange |
|
— |
|
|
— |
|
|
— |
|
|
5 |
|
Interest rate |
|
— |
|
|
— |
|
|
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 six months ended June 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 OCI
related to derivatives in cash flow hedging relationships including
the portion attributable to non-controlling interests is as
follows:
|
|
three months ended June 30 |
|
six months ended June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Change in fair value of
derivative instruments recognized in OCI (effective
portion)1 |
|
|
|
|
|
|
|
|
Commodities |
|
(3 |
) |
|
(2 |
) |
|
(6 |
) |
|
3 |
|
Interest
rate |
|
— |
|
|
— |
|
|
9 |
|
|
1 |
|
|
|
(3 |
) |
|
(2 |
) |
|
3 |
|
|
4 |
|
Reclassification of
gains/(losses) on derivative instruments from AOCI to net
income1 |
|
|
|
|
|
|
|
|
Commodities2 |
|
2 |
|
|
(7 |
) |
|
1 |
|
|
(11 |
) |
Interest
rate3 |
|
7 |
|
|
5 |
|
|
12 |
|
|
9 |
|
|
|
9 |
|
|
(2 |
) |
|
13 |
|
|
(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 June 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 June 30, 2018 and December 31, 2017. If the
credit-risk-related contingent features in these agreements were
triggered on June 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 June 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 second 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
their 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 an intra-entity asset transfer 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
consolidated 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
consolidated 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 continue to monitor and analyze additional guidance
and clarifications provided by the FASB.
The new guidance is effective January 1, 2019, with early
adoption permitted. A modified retrospective transition approach is
required for leases existing at, or entered into after, the
beginning of the earliest comparative period presented in the
financial statements, with certain practical expedients available.
We have developed a preliminary inventory of existing lease
agreements and have substantially completed our analysis on these
leases but continue to evaluate the financial impact on our
consolidated financial statements. We have also selected a system
solution and are in 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.
Amortization on purchased callable debt
securities
In March 2017, the FASB issued new guidance that shortens the
amortization period for the premium on certain purchased callable
debt securities by requiring entities to amortize the premium to
the earliest call date. This new guidance is effective January 1,
2019 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.
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.
Reconciliation of non-GAAP measures
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Comparable
EBITDA |
|
|
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
545 |
|
|
527 |
|
|
1,039 |
|
|
1,031 |
|
U.S. Natural Gas
Pipelines |
|
704 |
|
|
551 |
|
|
1,508 |
|
|
1,271 |
|
Mexico Natural Gas
Pipelines |
|
142 |
|
|
145 |
|
|
302 |
|
|
285 |
|
Liquids Pipelines |
|
413 |
|
|
332 |
|
|
844 |
|
|
644 |
|
Energy |
|
202 |
|
|
287 |
|
|
378 |
|
|
592 |
|
Corporate |
|
(15 |
) |
|
(12 |
) |
|
(17 |
) |
|
(16 |
) |
Comparable
EBITDA |
|
1,991 |
|
|
1,830 |
|
|
4,054 |
|
|
3,807 |
|
Depreciation and amortization |
|
(570 |
) |
|
(516 |
) |
|
(1,105 |
) |
|
(1,026 |
) |
Comparable
EBIT |
|
1,421 |
|
|
1,314 |
|
|
2,949 |
|
|
2,781 |
|
Specific items: |
|
|
|
|
|
|
|
|
Foreign
exchange gain/(loss) – inter-affiliate loan |
|
87 |
|
|
(8 |
) |
|
8 |
|
|
(8 |
) |
U.S.
Northeast power marketing contracts |
|
(15 |
) |
|
— |
|
|
(7 |
) |
|
— |
|
Net gain
on sales of U.S. Northeast power generation assets |
|
— |
|
|
492 |
|
|
— |
|
|
481 |
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
(20 |
) |
|
— |
|
|
(59 |
) |
Keystone
XL asset costs |
|
— |
|
|
(5 |
) |
|
— |
|
|
(13 |
) |
Risk
management activities1 |
|
99 |
|
|
(91 |
) |
|
(10 |
) |
|
(147 |
) |
Segmented earnings |
|
1,592 |
|
|
1,682 |
|
|
2,940 |
|
|
3,035 |
|
1 |
|
Risk management activities |
|
three months ended
June 30 |
|
six months ended
June 30 |
|
|
(unaudited - millions of $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian Power |
|
1 |
|
|
3 |
|
|
3 |
|
|
4 |
|
|
|
U.S. Power |
|
39 |
|
|
(94 |
) |
|
(62 |
) |
|
(156 |
) |
|
|
Liquids marketing |
|
62 |
|
|
4 |
|
|
55 |
|
|
4 |
|
|
|
Natural
Gas Storage |
|
(3 |
) |
|
(4 |
) |
|
(6 |
) |
|
1 |
|
|
|
Total unrealized gains/(losses) from risk management
activities |
|
99 |
|
|
(91 |
) |
|
(10 |
) |
|
(147 |
) |
Quarterly results
SELECTED QUARTERLY CONSOLIDATED FINANCIAL
DATA
|
2018
|
|
2017
|
|
2016
|
(unaudited - millions of $, except
per share amounts) |
|
Second |
|
|
First |
|
|
Fourth |
|
|
Third |
|
|
Second |
|
|
|
First |
|
|
Fourth |
|
|
Third |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
3,195 |
|
|
3,424 |
|
|
3,617 |
|
|
3,195 |
|
|
3,230 |
|
|
|
3,407 |
|
|
3,635 |
|
|
3,642 |
|
Net income/(loss)
attributable to common shares |
|
785 |
|
|
734 |
|
|
861 |
|
|
612 |
|
|
881 |
|
|
|
643 |
|
|
(358 |
) |
|
(135 |
) |
Comparable
earnings |
|
768 |
|
|
864 |
|
|
719 |
|
|
614 |
|
|
659 |
|
|
|
698 |
|
|
626 |
|
|
622 |
|
Per share
statistics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income/(loss) per common share - basic and diluted |
|
$0.88 |
|
|
$0.83 |
|
|
$0.98 |
|
|
$0.70 |
|
|
$1.01 |
|
|
$0.74 |
|
|
($0.43 |
) |
|
($0.17 |
) |
Comparable earnings per
common share |
|
$0.86 |
|
|
$0.98 |
|
|
$0.82 |
|
|
$0.70 |
|
|
$0.76 |
|
|
$0.81 |
|
|
$0.75 |
|
|
$0.78 |
|
Dividends declared per common share |
|
$0.69 |
|
|
$0.69 |
|
|
$0.625 |
|
|
$0.625 |
|
|
$0.625 |
|
|
$0.625 |
|
|
$0.565 |
|
|
$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 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:
- an after-tax gain of $6 million related to our U.S. Northeast
power marketing contracts, primarily due to income recognized on
the sale of our retail contracts. 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 business, 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 business 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 business 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.
In third quarter 2016, comparable earnings also excluded:
- a $656 million after-tax impairment on the Ravenswood goodwill.
As a result of information received during the process to monetize
our U.S. Northeast power business in third quarter 2016, it was
determined that the fair value of Ravenswood no longer exceeded its
carrying value
- costs associated with the acquisition of Columbia including a
charge of $67 million after tax primarily relating to retention,
severance and integration expenses
- $28 million of income tax recoveries related to the realized
loss on a third-party sale of Keystone XL plant and equipment. A
provision for the expected loss on these assets was included in our
fourth quarter 2015 impairment charge but the related tax
recoveries could not be recorded until realized
- a charge of $9 million after tax related to Keystone XL costs
for the maintenance and liquidation of project assets which were
being expensed pending further advancement of the project
- a $3 million after-tax charge related to the monetization of
our U.S. Northeast power business.
Condensed consolidated statement of
income
|
|
three months ended
June 30 |
|
six months ended
June 30 |
(unaudited - millions of Canadian $, except per share amounts) |
|
|
2018 |
|
|
|
2017 |
|
|
|
2018 |
|
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
|
954 |
|
|
|
922 |
|
|
|
1,838 |
|
|
|
1,804 |
|
U.S. Natural Gas
Pipelines |
|
|
930 |
|
|
|
879 |
|
|
|
2,021 |
|
|
|
1,873 |
|
Mexico Natural Gas
Pipelines |
|
|
153 |
|
|
|
150 |
|
|
|
304 |
|
|
|
293 |
|
Liquids Pipelines |
|
|
644 |
|
|
|
501 |
|
|
|
1,267 |
|
|
|
973 |
|
Energy |
|
|
514 |
|
|
|
778 |
|
|
|
1,189 |
|
|
|
1,694 |
|
|
|
|
3,195 |
|
|
|
3,230 |
|
|
|
6,619 |
|
|
|
6,637 |
|
Income from
Equity Investments |
|
|
265 |
|
|
|
197 |
|
|
|
345 |
|
|
|
371 |
|
Operating and
Other Expenses |
|
|
|
|
|
|
|
|
Plant operating costs
and other |
|
|
822 |
|
|
|
1,027 |
|
|
|
1,696 |
|
|
|
2,033 |
|
Commodity purchases
resold |
|
|
324 |
|
|
|
547 |
|
|
|
921 |
|
|
|
1,090 |
|
Property taxes |
|
|
152 |
|
|
|
153 |
|
|
|
302 |
|
|
|
315 |
|
Depreciation and
amortization |
|
|
570 |
|
|
|
516 |
|
|
|
1,105 |
|
|
|
1,033 |
|
|
|
|
1,868 |
|
|
|
2,243 |
|
|
|
4,024 |
|
|
|
4,471 |
|
Gain on Sale of
Assets |
|
|
— |
|
|
|
498 |
|
|
|
— |
|
|
|
498 |
|
Financial
Charges |
|
|
|
|
|
|
|
|
Interest expense |
|
|
558 |
|
|
|
524 |
|
|
|
1,085 |
|
|
|
1,024 |
|
Allowance for funds
used during construction |
|
|
(113 |
) |
|
|
(121 |
) |
|
|
(218 |
) |
|
|
(222 |
) |
Interest
income and other |
|
|
92 |
|
|
|
(89 |
) |
|
|
29 |
|
|
|
(109 |
) |
|
|
|
537 |
|
|
|
314 |
|
|
|
896 |
|
|
|
693 |
|
Income before Income Taxes |
|
|
1,055 |
|
|
|
1,368 |
|
|
|
2,044 |
|
|
|
2,342 |
|
Income Tax
Expense |
|
|
|
|
|
|
|
|
Current |
|
|
89 |
|
|
|
55 |
|
|
|
139 |
|
|
|
122 |
|
Deferred |
|
|
64 |
|
|
|
338 |
|
|
|
135 |
|
|
|
471 |
|
|
|
|
153 |
|
|
|
393 |
|
|
|
274 |
|
|
|
593 |
|
Net
Income |
|
|
902 |
|
|
|
975 |
|
|
|
1,770 |
|
|
|
1,749 |
|
Net
income attributable to non-controlling interests |
|
|
76 |
|
|
|
55 |
|
|
|
170 |
|
|
|
145 |
|
Net Income
Attributable to Controlling Interests |
|
|
826 |
|
|
|
920 |
|
|
|
1,600 |
|
|
|
1,604 |
|
Preferred
share dividends |
|
|
41 |
|
|
|
39 |
|
|
|
81 |
|
|
|
80 |
|
Net Income
Attributable to Common Shares |
|
|
785 |
|
|
|
881 |
|
|
|
1,519 |
|
|
|
1,524 |
|
Net Income per
Common Share |
|
|
|
|
|
|
|
|
Basic |
|
$0.88 |
|
|
$1.01 |
|
|
$1.70 |
|
|
$1.76 |
|
Diluted |
|
$0.88 |
|
|
$1.01 |
|
|
$1.70 |
|
|
$1.75 |
|
Dividends Declared per Common Share |
|
$0.69 |
|
|
$0.625 |
|
|
$1.38 |
|
|
$1.25 |
|
Weighted
Average Number of Common Shares (millions) |
|
|
|
|
|
|
|
|
Basic |
|
|
896 |
|
|
|
870 |
|
|
|
892 |
|
|
|
868 |
|
Diluted |
|
|
896 |
|
|
|
872 |
|
|
|
893 |
|
|
|
870 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated statement of
comprehensive income
|
|
three months ended June 30 |
|
six months ended June 30 |
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Net Income |
|
902 |
|
|
975 |
|
|
1,770 |
|
|
1,749 |
|
Other
Comprehensive Income/(Loss), Net of Income Taxes |
|
|
|
|
|
|
|
|
Foreign currency
translation gains and losses on net investment in foreign
operations |
|
259 |
|
|
(269 |
) |
|
691 |
|
|
(351 |
) |
Reclassification of
foreign currency translation gains on net investment on disposal of
foreign operations |
|
— |
|
|
(77 |
) |
|
— |
|
|
(77 |
) |
Change in fair value of
net investment hedges |
|
(13 |
) |
|
(1 |
) |
|
(15 |
) |
|
(2 |
) |
Change in fair value of
cash flow hedges |
|
(2 |
) |
|
(2 |
) |
|
5 |
|
|
3 |
|
Reclassification to net
income of gains and losses on cash flow hedges |
|
7 |
|
|
(1 |
) |
|
10 |
|
|
(1 |
) |
Reclassification of
actuarial gains and losses on pension and other post-retirement
benefit plans |
|
2 |
|
|
4 |
|
|
— |
|
|
7 |
|
Other
comprehensive income on equity investments |
|
6 |
|
|
— |
|
|
12 |
|
|
3 |
|
Other
comprehensive income/(loss) |
|
259 |
|
|
(346 |
) |
|
703 |
|
|
(418 |
) |
Comprehensive
Income |
|
1,161 |
|
|
629 |
|
|
2,473 |
|
|
1,331 |
|
Comprehensive income attributable to non-controlling interests |
|
116 |
|
|
6 |
|
|
276 |
|
|
56 |
|
Comprehensive
Income Attributable to Controlling Interests |
|
1,045 |
|
|
623 |
|
|
2,197 |
|
|
1,275 |
|
Preferred
share dividends |
|
41 |
|
|
39 |
|
|
81 |
|
|
80 |
|
Comprehensive Income Attributable to Common
Shares |
|
1,004 |
|
|
584 |
|
|
2,116 |
|
|
1,195 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated statement of cash
flows
|
|
three months ended June 30 |
|
six months ended June 30 |
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Cash Generated
from Operations |
|
|
|
|
|
|
|
|
Net income |
|
902 |
|
|
975 |
|
|
1,770 |
|
|
1,749 |
|
Depreciation and
amortization |
|
570 |
|
|
516 |
|
|
1,105 |
|
|
1,033 |
|
Deferred income
taxes |
|
64 |
|
|
338 |
|
|
135 |
|
|
471 |
|
Income from equity
investments |
|
(265 |
) |
|
(197 |
) |
|
(345 |
) |
|
(371 |
) |
Distributions received
from operating activities of equity investments |
|
231 |
|
|
228 |
|
|
465 |
|
|
447 |
|
Employee
post-retirement benefits funding, net of expense |
|
(3 |
) |
|
6 |
|
|
— |
|
|
9 |
|
Gain on sale of
assets |
|
— |
|
|
(498 |
) |
|
— |
|
|
(498 |
) |
Equity allowance for
funds used during construction |
|
(79 |
) |
|
(78 |
) |
|
(157 |
) |
|
(142 |
) |
Unrealized
(gains)/losses on financial instruments |
|
(39 |
) |
|
50 |
|
|
149 |
|
|
91 |
|
Other |
|
63 |
|
|
(4 |
) |
|
(59 |
) |
|
4 |
|
Decrease/(increase) in operating working capital |
|
361 |
|
|
17 |
|
|
154 |
|
|
(138 |
) |
Net cash
provided by operations |
|
1,805 |
|
|
1,353 |
|
|
3,217 |
|
|
2,655 |
|
Investing
Activities |
|
|
|
|
|
|
|
|
Capital
expenditures |
|
(2,337 |
) |
|
(1,792 |
) |
|
(4,039 |
) |
|
(3,352 |
) |
Capital projects in
development |
|
(76 |
) |
|
(56 |
) |
|
(112 |
) |
|
(98 |
) |
Contributions to equity
investments |
|
(184 |
) |
|
(473 |
) |
|
(542 |
) |
|
(665 |
) |
Proceeds from sales of
assets, net of transaction costs |
|
— |
|
|
4,147 |
|
|
— |
|
|
4,147 |
|
Other distributions
from equity investments |
|
— |
|
|
1 |
|
|
121 |
|
|
364 |
|
Deferred
amounts and other |
|
(16 |
) |
|
(169 |
) |
|
94 |
|
|
(254 |
) |
Net cash
(used in)/provided by investing activities |
|
(2,613 |
) |
|
1,658 |
|
|
(4,478 |
) |
|
142 |
|
Financing
Activities |
|
|
|
|
|
|
|
|
Notes payable
(repaid)/issued, net |
|
(1,327 |
) |
|
111 |
|
|
485 |
|
|
781 |
|
Long-term debt issued,
net of issue costs |
|
3,240 |
|
|
817 |
|
|
3,333 |
|
|
817 |
|
Long-term debt
repaid |
|
(808 |
) |
|
(4,418 |
) |
|
(2,034 |
) |
|
(5,469 |
) |
Junior subordinated
notes issued, net of issue costs |
|
— |
|
|
1,489 |
|
|
— |
|
|
3,471 |
|
Dividends on common
shares |
|
(380 |
) |
|
(328 |
) |
|
(738 |
) |
|
(628 |
) |
Dividends on preferred
shares |
|
(39 |
) |
|
(38 |
) |
|
(78 |
) |
|
(77 |
) |
Distributions paid to
non-controlling interests |
|
(48 |
) |
|
(69 |
) |
|
(117 |
) |
|
(149 |
) |
Common shares issued,
net of issue costs |
|
445 |
|
|
18 |
|
|
785 |
|
|
36 |
|
Partnership units of TC
PipeLines, LP issued, net of issue costs |
|
— |
|
|
27 |
|
|
49 |
|
|
119 |
|
Common units of
Columbia Pipeline Partners LP acquired |
|
— |
|
|
— |
|
|
— |
|
|
(1,205 |
) |
Net cash provided by/(used in) financing activities |
|
1,083 |
|
|
(2,391 |
) |
|
1,685 |
|
|
(2,304 |
) |
Effect of Foreign Exchange Rate Changes on Cash and Cash
Equivalents |
|
28 |
|
|
(24 |
) |
|
57 |
|
|
(19 |
) |
Increase in
Cash and Cash Equivalents |
|
303 |
|
|
596 |
|
|
481 |
|
|
474 |
|
Cash and Cash
Equivalents |
|
|
|
|
|
|
|
|
Beginning
of period |
|
1,267 |
|
|
894 |
|
|
1,089 |
|
|
1,016 |
|
Cash and Cash
Equivalents |
|
|
|
|
|
|
|
|
End of
period |
|
1,570 |
|
|
1,490 |
|
|
1,570 |
|
|
1,490 |
|
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated balance
sheet
|
|
June 30, |
|
|
December 31, |
|
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
|
|
|
|
ASSETS |
|
|
|
|
Current Assets |
|
|
|
|
Cash and
cash equivalents |
|
1,570 |
|
|
1,089 |
|
Accounts
receivable |
|
2,111 |
|
|
2,522 |
|
Inventories |
|
403 |
|
|
378 |
|
Assets held
for sale |
|
458 |
|
|
— |
|
Other |
|
888 |
|
|
691 |
|
|
|
5,430 |
|
|
4,680 |
|
Plant, Property
and Equipment |
net of accumulated
depreciation of $24,822 and $23,734, respectively |
|
61,446 |
|
|
57,277 |
|
Equity Investments |
|
6,628 |
|
|
6,366 |
|
Regulatory Assets |
|
1,361 |
|
|
1,376 |
|
Goodwill |
|
13,734 |
|
|
13,084 |
|
Loan Receivable from Affiliate |
|
1,173 |
|
|
919 |
|
Intangible and Other Assets |
|
1,749 |
|
|
1,484 |
|
Restricted Investments |
|
1,062 |
|
|
915 |
|
|
|
92,583 |
|
|
86,101 |
|
LIABILITIES |
|
|
|
|
Current Liabilities |
|
|
|
|
Notes
payable |
|
2,359 |
|
|
1,763 |
|
Accounts
payable and other |
|
3,982 |
|
|
4,057 |
|
Dividends
payable |
|
636 |
|
|
586 |
|
Accrued
interest |
|
642 |
|
|
605 |
|
Current portion of long-term debt |
|
2,812 |
|
|
2,866 |
|
|
|
10,431 |
|
|
9,877 |
|
Regulatory Liabilities |
|
4,603 |
|
|
4,321 |
|
Other Long-Term Liabilities |
|
666 |
|
|
727 |
|
Deferred Income Tax Liabilities |
|
5,700 |
|
|
5,403 |
|
Long-Term Debt |
|
34,583 |
|
|
31,875 |
|
Junior Subordinated Notes |
|
7,284 |
|
|
7,007 |
|
|
|
63,267 |
|
|
59,210 |
|
EQUITY |
|
|
|
|
Common
shares, no par value |
|
22,385 |
|
|
21,167 |
|
Issued
and outstanding: |
June 30, 2018 - 904
million shares |
|
|
|
|
|
December 31, 2017 - 881
million shares |
|
|
|
|
Preferred
shares |
|
3,980 |
|
|
3,980 |
|
Additional
paid-in capital |
|
12 |
|
|
— |
|
Retained
earnings |
|
2,020 |
|
|
1,623 |
|
Accumulated other comprehensive loss |
|
(1,134 |
) |
|
(1,731 |
) |
Controlling Interests |
|
27,263 |
|
|
25,039 |
|
Non-controlling interests |
|
2,053 |
|
|
1,852 |
|
|
|
29,316 |
|
|
26,891 |
|
|
|
92,583 |
|
|
86,101 |
|
Contingencies and Guarantees (Note 13)
Variable Interest Entities (Note 14)
Subsequent Event (Note 15)
See accompanying notes to the Condensed consolidated financial
statements.
Condensed consolidated statement of
equity
|
six months ended June 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 issuance program, net of issue costs |
766 |
|
|
— |
|
Under
dividend reinvestment and share purchase plan |
431 |
|
|
406 |
|
On exercise of stock options |
21 |
|
|
39 |
|
Balance
at end of period |
22,385 |
|
|
20,544 |
|
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 |
5 |
|
|
2 |
|
Dilution from TC
PipeLines, LP units issued |
7 |
|
|
13 |
|
Asset drop downs to TC
PipeLines, LP |
— |
|
|
(202 |
) |
Columbia Pipeline
Partners LP acquisition |
— |
|
|
(171 |
) |
Reclassification of
additional paid-in capital deficit to retained earnings |
— |
|
|
358 |
|
Balance at end of period |
12 |
|
|
— |
|
Retained
Earnings |
|
|
|
Balance at beginning of
period |
1,623 |
|
|
1,138 |
|
Net income attributable
to controlling interests |
1,600 |
|
|
1,604 |
|
Common share
dividends |
(1,238 |
) |
|
(1,087 |
) |
Preferred share
dividends |
(60 |
) |
|
(58 |
) |
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 |
— |
|
|
(358 |
) |
Balance
at end of period |
2,020 |
|
|
1,251 |
|
Accumulated
Other Comprehensive Loss |
|
|
|
Balance at beginning of
period |
(1,731 |
) |
|
(960 |
) |
Other comprehensive
income/(loss) attributable to controlling interests |
597 |
|
|
(329 |
) |
Balance at end of period |
(1,134 |
) |
|
(1,289 |
) |
Equity Attributable to Controlling Interests |
27,263 |
|
|
24,486 |
|
Equity
Attributable to Non-Controlling Interests |
|
|
|
Balance at beginning of
period |
1,852 |
|
|
1,726 |
|
Net income attributable
to non-controlling interests |
170 |
|
|
145 |
|
Other comprehensive
income/(loss) attributable to non-controlling interests |
106 |
|
|
(89 |
) |
Issuance of TC
PipeLines, LP units |
|
|
|
Proceeds,
net of issue costs |
49 |
|
|
119 |
|
Decrease
in TransCanada's ownership of TC PipeLines, LP |
(9 |
) |
|
(21 |
) |
Distributions declared
to non-controlling interests |
(115 |
) |
|
(147 |
) |
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 |
2,053 |
|
|
1,872 |
|
Total Equity |
29,316 |
|
|
26,358 |
|
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 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 an intra-entity asset transfer 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
consolidated 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
consolidated 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 continues to monitor and analyze additional
guidance and clarifications provided by the FASB.
The new guidance is effective January 1, 2019, with early
adoption permitted. A modified retrospective transition approach is
required for leases existing at, or entered into after, the
beginning of the earliest comparative period presented in the
financial statements, with certain practical expedients available.
The Company has developed a preliminary inventory of existing lease
agreements and has substantially completed its analysis on these
leases but continues to evaluate the financial impact on its
consolidated financial statements. The Company has also selected a
system solution and is in 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.
Amortization on purchased callable debt
securities
In March 2017, the FASB issued new guidance that shortens the
amortization period for the premium on certain purchased callable
debt securities by requiring entities to amortize the premium to
the earliest call date. This new guidance is effective January 1,
2019 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.
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.
3. Segmented information
three months ended June 30, 2018 (unaudited -
millions of Canadian $)
|
|
Canadian
Natural
Gas
Pipelines |
|
|
U.S.
Natural
Gas
Pipelines |
|
|
Mexico
Natural
Gas
Pipelines |
|
|
Liquids
Pipelines |
|
|
Energy |
|
|
Corporate
|
1 |
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
954 |
|
|
930 |
|
|
153 |
|
|
644 |
|
|
514 |
|
|
— |
|
3,195 |
|
Intersegment revenues |
|
— |
|
|
56 |
|
|
— |
|
|
— |
|
|
5 |
|
|
(61 |
)2 |
— |
|
|
|
954 |
|
|
986 |
|
|
153 |
|
|
644 |
|
|
519 |
|
|
(61 |
) |
3,195 |
|
Income from equity
investments |
|
3 |
|
|
59 |
|
|
1 |
|
|
13 |
|
|
102 |
|
|
87 |
3 |
265 |
|
Plant operating costs
and other |
|
(341 |
) |
|
(288 |
) |
|
(12 |
) |
|
(155 |
) |
|
(72 |
) |
|
46 |
2 |
(822 |
) |
Commodity purchases
resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(324 |
) |
|
— |
|
(324 |
) |
Property taxes |
|
(71 |
) |
|
(53 |
) |
|
— |
|
|
(27 |
) |
|
(1 |
) |
|
— |
|
(152 |
) |
Depreciation and
amortization |
|
(265 |
) |
|
(163 |
) |
|
(24 |
) |
|
(85 |
) |
|
(33 |
) |
|
— |
|
(570 |
) |
Segmented Earnings |
|
280 |
|
|
541 |
|
|
118 |
|
|
390 |
|
|
191 |
|
|
72 |
|
1,592 |
|
Interest
expense |
(558 |
) |
Allowance
for funds used during construction |
113 |
|
Interest income and other |
(92 |
) |
Income
before income taxes |
1,055 |
|
Income tax expense |
(153 |
) |
Net Income |
902 |
|
Net income attributable to non-controlling
interests |
(76 |
) |
Net Income Attributable to Controlling
Interests |
826 |
|
Preferred share dividends |
(41 |
) |
Net Income Attributable to Common
Shares |
785 |
|
1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted
rates. For segmented reporting, these transactions are included as
Intersegment revenues in the segment providing the service and
Plant operating costs and other in the segment receiving the
service. These transactions are eliminated on consolidation.
Intersegment profit is recognized when the product or service has
been provided to third parties or otherwise realized.
3 Income from equity investments includes foreign
exchange gains on the Company's inter-affiliate loan with Sur de
Texas. The 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 June 30, 2017 (unaudited -
millions of Canadian $) |
|
Canadian
Natural
Gas
Pipelines |
|
|
U.S.
Natural
Gas
Pipelines |
|
|
Mexico
Natural
Gas
Pipelines |
|
|
Liquids
Pipelines |
|
|
Energy |
|
|
Corporate |
1 |
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
922 |
|
|
879 |
|
|
150 |
|
|
501 |
|
|
778 |
|
|
— |
|
3,230 |
|
Intersegment revenues |
|
— |
|
|
10 |
|
|
— |
|
|
— |
|
|
— |
|
|
(10 |
)2 |
— |
|
|
|
922 |
|
|
889 |
|
|
150 |
|
|
501 |
|
|
778 |
|
|
(10 |
) |
3,230 |
|
Income/(loss) from
equity investments |
|
2 |
|
|
57 |
|
|
5 |
|
|
(1 |
) |
|
142 |
|
|
(8 |
)3 |
197 |
|
Plant operating costs
and other |
|
(328 |
) |
|
(347 |
) |
|
(10 |
) |
|
(147 |
) |
|
(173 |
) |
|
(22 |
)2 |
(1,027 |
) |
Commodity purchases
resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(547 |
) |
|
— |
|
(547 |
) |
Property taxes |
|
(69 |
) |
|
(48 |
) |
|
— |
|
|
(22 |
) |
|
(14 |
) |
|
— |
|
(153 |
) |
Depreciation and
amortization |
|
(222 |
) |
|
(150 |
) |
|
(25 |
) |
|
(80 |
) |
|
(39 |
) |
|
— |
|
(516 |
) |
Gain on sale of
assets |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
498 |
|
|
— |
|
498 |
|
Segmented Earnings/(Loss) |
|
305 |
|
|
401 |
|
|
120 |
|
|
251 |
|
|
645 |
|
|
(40 |
) |
1,682 |
|
Interest
expense |
(524 |
) |
Allowance
for funds used during construction |
121 |
|
Interest income and other |
89 |
|
Income
before income taxes |
1,368 |
|
Income tax expense |
(393 |
) |
Net Income |
975 |
|
Net income attributable to non-controlling
interests |
(55 |
) |
Net Income Attributable to Controlling
Interests |
920 |
|
Preferred share dividends |
(39 |
) |
Net Income Attributable to Common
Shares |
881 |
|
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 peso-denominated loan to the Sur de Texas joint venture
represents the Company's proportionate share of debt financing for
this joint venture.
six months ended June 30, 2018 (unaudited -
millions of Canadian $) |
|
Canadian
Natural
Gas
Pipelines |
|
|
U.S.
Natural
Gas
Pipelines |
|
|
Mexico
Natural
Gas
Pipelines |
|
|
Liquids
Pipelines |
|
|
Energy |
|
|
Corporate |
1 |
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
1,838 |
|
|
2,021 |
|
|
304 |
|
|
1,267 |
|
|
1,189 |
|
|
— |
|
6,619 |
|
Intersegment revenues |
|
— |
|
|
81 |
|
|
— |
|
|
— |
|
|
47 |
|
|
(128 |
)2 |
— |
|
|
|
1,838 |
|
|
2,102 |
|
|
304 |
|
|
1,267 |
|
|
1,236 |
|
|
(128 |
) |
6,619 |
|
Income from equity
investments |
|
6 |
|
|
126 |
|
|
12 |
|
|
28 |
|
|
165 |
|
|
8 |
3 |
345 |
|
Plant operating costs
and other |
|
(664 |
) |
|
(612 |
) |
|
(14 |
) |
|
(346 |
) |
|
(171 |
) |
|
111 |
2 |
(1,696 |
) |
Commodity purchases
resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(921 |
) |
|
— |
|
(921 |
) |
Property taxes |
|
(141 |
) |
|
(108 |
) |
|
— |
|
|
(50 |
) |
|
(3 |
) |
|
— |
|
(302 |
) |
Depreciation and
amortization |
|
(506 |
) |
|
(319 |
) |
|
(47 |
) |
|
(168 |
) |
|
(65 |
) |
|
— |
|
(1,105 |
) |
Segmented Earnings/(Loss) |
|
533 |
|
|
1,189 |
|
|
255 |
|
|
731 |
|
|
241 |
|
|
(9 |
) |
2,940 |
|
Interest
expense |
(1,085 |
) |
Allowance
for funds used during construction |
218 |
|
Interest income and other |
(29 |
) |
Income
before income taxes |
2,044 |
|
Income tax expense |
(274 |
) |
Net Income |
1,770 |
|
Net income attributable to non-controlling
interests |
(170 |
) |
Net Income Attributable to Controlling
Interests |
1,600 |
|
Preferred share dividends |
(81 |
) |
Net Income Attributable to Common
Shares |
1,519 |
|
1 Includes intersegment eliminations.
2 The Company records intersegment sales at contracted
rates. For segmented reporting, these transactions are included as
Intersegment revenues in the segment providing the service and
Plant operating costs and other in the segment receiving the
service. These transactions are eliminated on consolidation.
Intersegment profit is recognized when the product or service has
been provided to third parties or otherwise realized.
3 Income from equity investments includes foreign
exchange gains on the Company's inter-affiliate loan with Sur de
Texas. The peso-denominated loan to the Sur de Texas joint venture
represents the Company's proportionate share of debt financing for
this joint venture.
six months ended June 30, 2017 (unaudited -
millions of Canadian $) |
|
Canadian
Natural
Gas
Pipelines |
|
|
U.S.
Natural
Gas
Pipelines |
|
|
Mexico
Natural
Gas
Pipelines |
|
|
Liquids
Pipelines |
|
|
Energy |
|
|
Corporate |
1 |
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
1,804 |
|
|
1,873 |
|
|
293 |
|
|
973 |
|
|
1,694 |
|
|
— |
|
6,637 |
|
Intersegment revenues |
|
— |
|
|
21 |
|
|
— |
|
|
— |
|
|
— |
|
|
(21 |
)2 |
— |
|
|
|
1,804 |
|
|
1,894 |
|
|
293 |
|
|
973 |
|
|
1,694 |
|
|
(21 |
) |
6,637 |
|
Income/(loss) from
equity investments |
|
5 |
|
|
122 |
|
|
11 |
|
|
(1 |
) |
|
242 |
|
|
(8 |
)3 |
371 |
|
Plant operating costs
and other |
|
(640 |
) |
|
(653 |
) |
|
(19 |
) |
|
(292 |
) |
|
(385 |
) |
|
(44 |
)2 |
(2,033 |
) |
Commodity purchases
resold |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
(1,090 |
) |
|
— |
|
(1,090 |
) |
Property taxes |
|
(138 |
) |
|
(95 |
) |
|
— |
|
|
(45 |
) |
|
(37 |
) |
|
— |
|
(315 |
) |
Depreciation and
amortization |
|
(444 |
) |
|
(306 |
) |
|
(47 |
) |
|
(157 |
) |
|
(79 |
) |
|
— |
|
(1,033 |
) |
Gain on sale of
assets |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
498 |
|
|
— |
|
498 |
|
Segmented Earnings/(Loss) |
|
587 |
|
|
962 |
|
|
238 |
|
|
478 |
|
|
843 |
|
|
(73 |
) |
3,035 |
|
Interest
expense |
(1,024 |
) |
Allowance
for funds used during construction |
222 |
|
Interest income and other |
109 |
|
Income
before income taxes |
2,342 |
|
Income tax expense |
(593 |
) |
Net Income |
1,749 |
|
Net income attributable to non-controlling
interests |
(145 |
) |
Net Income Attributable to Controlling
Interests |
1,604 |
|
Preferred share dividends |
(80 |
) |
Net Income Attributable to Common
Shares |
1,524 |
|
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 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 $) |
|
June 30, 2018 |
|
December 31, 2017 |
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
17,447 |
|
16,904 |
|
U.S. Natural Gas
Pipelines |
|
39,786 |
|
35,898 |
|
Mexico Natural Gas
Pipelines |
|
6,268 |
|
5,716 |
|
Liquids Pipelines |
|
16,291 |
|
15,438 |
|
Energy |
|
8,368 |
|
8,503 |
|
Corporate |
|
4,423 |
|
3,642 |
|
|
|
92,583 |
|
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 summarizes total Revenues for the three and
six months ended June 30, 2018:
three months ended June 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 |
954 |
|
785 |
|
152 |
|
513 |
|
— |
|
2,404 |
|
Power
generation |
— |
|
— |
|
— |
|
— |
|
415 |
|
415 |
|
Natural gas storage and other |
— |
|
118 |
|
1 |
|
— |
|
31 |
|
150 |
|
|
954 |
|
903 |
|
153 |
|
513 |
|
446 |
|
2,969 |
|
Other
revenues1,2 |
— |
|
27 |
|
— |
|
131 |
|
68 |
|
226 |
|
|
954 |
|
930 |
|
153 |
|
644 |
|
514 |
|
3,195 |
|
1 Other revenues include income from the Company's
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.
six months ended June 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 |
1,838 |
|
1,669 |
|
302 |
|
1,047 |
|
— |
|
4,856 |
|
Power
generation |
— |
|
— |
|
— |
|
— |
|
1,005 |
|
1,005 |
|
Natural gas storage and other |
— |
|
310 |
|
2 |
|
1 |
|
61 |
|
374 |
|
|
1,838 |
|
1,979 |
|
304 |
|
1,048 |
|
1,066 |
|
6,235 |
|
Other
revenues1,2 |
— |
|
42 |
|
— |
|
219 |
|
123 |
|
384 |
|
|
1,838 |
|
2,021 |
|
304 |
|
1,267 |
|
1,189 |
|
6,619 |
|
1 Other revenues include income from the Company's
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 rate of return on
common equity (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 is
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 contract
liabilities are included in Accounts payable and other.
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 |
|
|
|
|
|
(unaudited - millions of Canadian $) |
December 31, 2017 |
|
Adjustment |
|
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 June 30,
2018, had legacy U.S. GAAP been applied:
|
June 30, 2018 |
(unaudited - millions of Canadian $) |
As reported |
|
Pro-forma
using legacy U.S.
GAAP |
|
|
|
Current
Assets |
|
|
Accounts
receivable |
2,111 |
|
2,353 |
Other |
888 |
|
646 |
CONTRACT BALANCES
(unaudited - millions of Canadian $) |
June 30, 2018 |
|
January 1, 2018 |
|
|
|
|
Receivables from
contracts with customers |
1,225 |
|
1,736 |
Contract
assets1 |
242 |
|
79 |
Contract
liabilities2 |
24 |
|
17 |
Long-term
contract liabilities3 |
17 |
|
— |
1 Recorded as part of Other current assets on the
Condensed consolidated balance sheet.
2 Comprised of deferred revenue recorded in Accounts
payable and other on the Condensed consolidated balance sheet.
During the six months ended June 30, 2018, $17 million of revenue
was recognized that was included in the contract liability at the
beginning of the period.
3 Comprised of deferred revenue recorded in Other
long-term liabilities on the Condensed consolidated balance
sheet.
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.
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:
- The original expected duration of the contract is one year or
less.
- 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.
- 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 June 30, 2018, future revenues from long-term capacity
arrangements and transportation contracts extending through 2043
are approximately $29.4 billion, of which approximately $2.8
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 June 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 June 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 June 30, 2018, future revenues from long-term natural
gas storage and other contracts extending through 2033 are
approximately $1.3 billion, of which approximately $260 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, we entered into an agreement to
sell our interests in the Cartier Wind power facilities in
Québec to Innergex Renewable Energy Inc. for gross
proceeds of $630 million before closing adjustments. The sale is
expected to be completed in fourth quarter 2018, subject to certain
regulatory and other approvals, and result in an estimated gain of
$175 million ($130 million after tax) which will be recorded upon
closing of the transaction.
At June 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 with respect to these changes. Until these
pronouncements are implemented through individual rate proceedings
or settlements, and the Company and TC PipeLines, LP have fully
evaluated their respective alternatives to minimize any negative
impact of the proposed FERC changes, the Company believes that it
is not more likely than not that the fair value of any of its
reporting units is less than its respective carrying value.
Therefore, a goodwill impairment test has not been performed during
the six months ended June 30, 2018. The Company also
determined there is no indication that the carrying values of
plant, property and equipment and equity investments potentially
impacted by FERC's changes are not recoverable. The Company will
continue to monitor developments and assess its goodwill for
impairment as well as review its plant, property and equipment and
equity investments for recoverability as new information becomes
available.
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 FERC developments, once finalized, could result in a
goodwill impairment charge. The goodwill balance related to Great
Lakes is US$573 million at June 30, 2018 (December 31, 2017 –
US$573 million). There is also a risk that the goodwill balance
related to Tuscarora of US$82 million at June 30, 2018
(December 31, 2017 – US$82 million) could be negatively
impacted by the FERC developments.
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 rate-regulated accounting. 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
regulatory, tax and accounting authorities. Should additional
guidance be provided by these authorities or other sources during
the one-year measurement period permitted by the SEC, the Company
will review the provisional amounts and adjust as appropriate.
Other than the amortizations discussed below and the foreign
exchange impacts, no adjustments were made to these amounts during
the six months ended June 30, 2018. There may be prospective
adjustments to the Company's net regulatory liabilities once the
final impact of these changes is determined.
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
amortization based on their composite depreciation rate and
immediately begin recording amortization. Amortization of the net
regulatory liabilities in the amount of $15 million and $24 million
was recorded for the three and six months ended June 30, 2018
respectively and included in Revenues in the Condensed consolidated
statement of income.
Effective Tax Rates
The effective income tax rates for the six-month periods ended
June 30, 2018 and 2017 were 13 per cent and 25 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 six months ended June 30,
2018 as follows:
(unaudited - millions of Canadian $, unless noted otherwise) |
|
|
|
|
|
|
|
|
|
|
Company |
|
Issue date |
|
Type |
|
Maturity Date |
|
Amount |
|
Interest rate |
|
|
|
|
|
|
|
|
|
|
|
TRANSCANADA PIPELINES LIMITED |
|
|
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 six months ended June 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 |
|
5.9% |
TRANSCANADA PIPELINES LIMITED |
|
|
|
|
|
|
|
|
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 six months ended June 30, 2018, TransCanada
capitalized interest related to capital projects of $30 million and
$56 million, respectively (2017 – $56 million and $101 million,
respectively).
9. Common shares
TRANSCANADA CORPORATION ATM EQUITY ISSUANCE
PROGRAM
In the three months ended June 30, 2018, the Company issued
8.1 million common shares under the TransCanada ATM program at an
average price of $54.63 per common share for gross proceeds of $443
million. Related commissions and fees totaled approximately $4
million resulting in net proceeds of $439 million. In the six
months ended June 30, 2018, the Company issued 13.9 million common
shares at an average price of $55.42 per common share for gross
proceeds of $772 million. Related commissions and fees totaled
approximately $7 million resulting in net proceeds of $765
million.
In June 2018, the Company announced that it has 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
(Amended Corporate ATM program). The Amended Corporate ATM program
is effective to July 23, 2019.
10. Other comprehensive income/(loss) and accumulated
other comprehensive loss
Components of other comprehensive income/(loss), including the
portion attributable to non-controlling interests and related tax
effects, are as follows:
three months ended June 30, 2018 |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
Before Tax
Amount |
|
|
Income Tax
Recovery/
(Expense) |
|
|
Net of Tax
Amount |
|
|
|
|
|
|
|
|
Foreign currency
translation gains on net investment in foreign operations |
|
254 |
|
|
5 |
|
|
259 |
|
Change in fair value of
net investment hedges |
|
(17 |
) |
|
4 |
|
|
(13 |
) |
Change in fair value of
cash flow hedges |
|
(3 |
) |
|
1 |
|
|
(2 |
) |
Reclassification to net
income of gains and losses on cash flow hedges |
|
9 |
|
|
(2 |
) |
|
7 |
|
Reclassification of
actuarial gains and losses on pension and other post-retirement
benefit plans |
|
4 |
|
|
(2 |
) |
|
2 |
|
Other
comprehensive income on equity investments |
|
6 |
|
|
— |
|
|
6 |
|
Other comprehensive income |
|
253 |
|
|
6 |
|
|
259 |
|
three months ended June 30, 2017 |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
Before Tax
Amount |
|
|
Income Tax
Recovery/
(Expense) |
|
|
Net of Tax
Amount |
|
|
|
|
|
|
|
|
Foreign currency
translation losses on net investment in foreign operations |
|
(265 |
) |
|
(4 |
) |
|
(269 |
) |
Reclassification of
foreign currency translation gains on net investment on disposal of
foreign operations |
|
(77 |
) |
|
— |
|
|
(77 |
) |
Change in fair value of
net investment hedges |
|
(1 |
) |
|
— |
|
|
(1 |
) |
Change in fair value of
cash flow hedges |
|
(2 |
) |
|
— |
|
|
(2 |
) |
Reclassification to net
income of gains and losses on cash flow hedges |
|
(2 |
) |
|
1 |
|
|
(1 |
) |
Reclassification of actuarial gains and losses on pension and other
post-retirement benefit plans |
|
5 |
|
|
(1 |
) |
|
4 |
|
Other comprehensive loss |
|
(342 |
) |
|
(4 |
) |
|
(346 |
) |
six months ended June 30, 2018 |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
Before Tax
Amount |
|
|
Income Tax
Recovery/
(Expense) |
|
|
Net of Tax
Amount |
|
|
|
|
|
|
|
|
Foreign currency
translation gains on net investment in foreign operations |
|
670 |
|
|
21 |
|
|
691 |
|
Change in fair value of
net investment hedges |
|
(20 |
) |
|
5 |
|
|
(15 |
) |
Change in fair value of
cash flow hedges |
|
3 |
|
|
2 |
|
|
5 |
|
Reclassification to net
income of gains and losses on cash flow hedges |
|
13 |
|
|
(3 |
) |
|
10 |
|
Reclassification of
actuarial gains and losses on pension and other
post-retirement benefit plans |
|
8 |
|
|
(8 |
) |
|
— |
|
Other
comprehensive income on equity investments |
|
13 |
|
|
(1 |
) |
|
12 |
|
Other comprehensive income |
|
687 |
|
|
16 |
|
|
703 |
|
six months ended June 30, 2017 |
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
Before Tax
Amount |
|
|
Income Tax
Recovery/
(Expense) |
|
|
Net of Tax
Amount |
|
|
|
|
|
|
|
|
Foreign currency
translation losses on net investment in foreign operations |
|
(353 |
) |
|
2 |
|
|
(351 |
) |
Reclassification of
foreign currency translation gains on net investment on disposal of
foreign operations |
|
(77 |
) |
|
— |
|
|
(77 |
) |
Change in fair value of
net investment hedges |
|
(3 |
) |
|
1 |
|
|
(2 |
) |
Change in fair value of
cash flow hedges |
|
4 |
|
|
(1 |
) |
|
3 |
|
Reclassification to net
income of gains and losses on cash flow hedges |
|
(2 |
) |
|
1 |
|
|
(1 |
) |
Reclassification of
actuarial gains and losses on pension and other post-retirement
benefit plans |
|
10 |
|
|
(3 |
) |
|
7 |
|
Other
comprehensive income on equity investments |
|
4 |
|
|
(1 |
) |
|
3 |
|
Other comprehensive loss |
|
(417 |
) |
|
(1 |
) |
|
(418 |
) |
The changes in AOCI by component are as
follows:
three months ended June 30, 2018 |
|
|
|
|
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
|
Currency
Translation
Adjustments |
|
|
Cash Flow
Hedges |
|
|
Pension and
OPEB Plan
Adjustments |
|
|
Equity
Investments |
|
|
Total1 |
|
|
|
|
|
|
|
|
|
|
|
|
AOCI balance at April
1, 2018 |
|
(670 |
) |
|
(29 |
) |
|
(205 |
) |
|
(449 |
) |
|
(1,353 |
) |
Other comprehensive
income/(loss) before reclassifications2 |
|
208 |
|
|
(2 |
) |
|
— |
|
|
— |
|
|
206 |
|
Amounts
reclassified from accumulated other comprehensive
loss3 |
|
— |
|
|
5 |
|
|
2 |
|
|
6 |
|
|
13 |
|
Net current period
other comprehensive
income |
|
208 |
|
|
3 |
|
|
2 |
|
|
6 |
|
|
219 |
|
AOCI balance at June 30, 2018 |
|
(462 |
) |
|
(26 |
) |
|
(203 |
) |
|
(443 |
) |
|
(1,134 |
) |
1 All amounts are net of tax. Amounts in parentheses
indicate losses recorded to OCI.
2 Other comprehensive income/(loss) before
reclassifications on currency translation adjustments and cash flow
hedges is net of non-controlling interest gains of $38 million and
nil, respectively.
3 Amounts reclassified from AOCI on cash flow hedges and
equity investments is net of non-controlling interest gains of $2
million and nil, respectively.
six months ended June 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/(loss) before reclassifications2,3 |
|
581 |
|
|
(2 |
) |
|
— |
|
|
— |
|
|
579 |
|
Amounts
reclassified from accumulated other comprehensive loss
4 |
|
— |
|
|
7 |
|
|
— |
|
|
11 |
|
|
18 |
|
Net current period
other comprehensive
income |
|
581 |
|
|
5 |
|
|
— |
|
|
11 |
|
|
597 |
|
AOCI balance at June 30, 2018 |
|
(462 |
) |
|
(26 |
) |
|
(203 |
) |
|
(443 |
) |
|
(1,134 |
) |
1 All amounts are net of tax. Amounts in parentheses
indicate losses recorded to OCI.
2 Other comprehensive income/(loss) before
reclassifications on currency translation adjustments and cash flow
hedges is net of non-controlling interest gains of $95 million and
$7 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 $21 million ($15 million, net of tax) at
June 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 $3
million and $1 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
June 30 |
|
six months ended
June 30 |
|
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedges |
|
|
|
|
|
|
|
|
|
Commodities |
|
(2 |
) |
|
7 |
|
|
(1 |
) |
11 |
|
|
Revenues (Energy) |
Interest |
|
(5 |
) |
|
(5 |
) |
|
(9 |
) |
(9 |
) |
|
Interest
expense |
|
|
(7 |
) |
|
2 |
|
|
(10 |
) |
2 |
|
|
Total before tax |
|
|
2 |
|
|
(1 |
) |
|
3 |
|
(1 |
) |
|
Income
tax expense |
|
|
(5 |
) |
|
1 |
|
|
(7 |
) |
1 |
|
|
Net of
tax1,3 |
Pension and other
post-retirement benefit plan adjustments |
|
|
|
|
|
|
|
|
|
Amortization of actuarial gains and losses |
|
(4 |
) |
|
(4 |
) |
|
(8 |
) |
(8 |
) |
|
Plant operating costs
and other2 |
|
|
2 |
|
|
1 |
|
|
8 |
|
3 |
|
|
Income
tax expense |
|
|
(2 |
) |
|
(3 |
) |
|
— |
|
(5 |
) |
|
Net of
tax1 |
Equity investments |
|
|
|
|
|
|
|
|
|
Equity
income |
|
(6 |
) |
|
— |
|
|
(13 |
) |
(4 |
) |
|
Income from equity
investments |
|
|
— |
|
|
— |
|
|
2 |
|
1 |
|
|
Income tax expense |
|
|
(6 |
) |
|
— |
|
|
(11 |
) |
(3 |
) |
|
Net of tax1,3 |
Currency translation
adjustments |
|
|
|
|
|
|
|
|
|
Realization of foreign currency translation gain on disposal of
foreign operations |
|
— |
|
|
77 |
|
|
— |
|
77 |
|
|
Gain on sale of
assets |
|
|
— |
|
|
— |
|
|
— |
|
— |
|
|
Income tax expense |
|
|
— |
|
|
77 |
|
|
— |
|
77 |
|
|
Net of tax1 |
1 All amounts in parentheses indicate expenses to the
Condensed consolidated statement of income.
2 These accumulated other comprehensive loss 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 is net of non-controlling interest gains of $2
million and nil, respectively for the three months ended June 30,
2018 (2017 - nil and nil) and $3 million and $1 million,
respectively for the six months ended June 30, 2018 (2017 - nil and
nil).
11. Employee post-retirement benefits
The net benefit cost recognized for the Company’s benefit
pension plans and other post-retirement benefit plans is as
follows:
|
|
three months ended June 30 |
|
six months ended June 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 |
|
31 |
|
|
27 |
|
|
1 |
|
|
1 |
|
|
61 |
|
|
56 |
|
|
2 |
|
|
2 |
|
Other components of net
benefit cost1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
cost |
|
34 |
|
|
28 |
|
|
4 |
|
|
3 |
|
|
67 |
|
|
62 |
|
|
7 |
|
|
7 |
|
Expected
return on plan assets |
|
(55 |
) |
|
(39 |
) |
|
(4 |
) |
|
(6 |
) |
|
(110 |
) |
|
(89 |
) |
|
(8 |
) |
|
(11 |
) |
Amortization of actuarial loss |
|
3 |
|
|
4 |
|
|
1 |
|
|
— |
|
|
7 |
|
|
8 |
|
|
1 |
|
|
— |
|
Amortization of regulatory asset |
|
4 |
|
|
1 |
|
|
— |
|
|
1 |
|
|
9 |
|
|
7 |
|
|
— |
|
|
1 |
|
|
|
(14 |
) |
|
(6 |
) |
|
1 |
|
|
(2 |
) |
|
(27 |
) |
|
(12 |
) |
|
— |
|
|
(3 |
) |
Net Benefit Cost |
|
17 |
|
|
21 |
|
|
2 |
|
|
(1 |
) |
|
34 |
|
|
44 |
|
|
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 June 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
June 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 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
June 30, 2018, the balance of the Company's loan receivable
from the joint venture totaled MXN$17.5 billion or $1.2 billion
(December 31, 2017 – MXN$14.4 billion or $919 million) and
Interest income and other included $29 million and $56 million of
interest income on this loan receivable for the three and six
months ended June 30, 2018 (2017 – $3 million and $3 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:
|
|
June 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 |
|
(80 |
) |
|
US 500 |
|
(199 |
) |
|
US
1,200 |
U.S. dollar foreign
exchange options (maturing 2018 to 2019) |
|
(16 |
) |
|
US 2,000 |
|
5 |
|
|
US
500 |
|
|
(96 |
) |
|
US 2,500 |
|
(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 six months ended June 30, 2018,
Net income includes net realized gains of nil and $1 million,
respectively (2017 – $1 million and $2 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) |
|
June 30, 2018 |
|
December 31, 2017 |
|
|
|
|
|
Notional amount |
|
29,000 (US 22,000) |
|
25,400
(US 20,200) |
Fair value |
|
30,800 (US 23,400) |
|
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:
|
|
June 30, 2018 |
|
December 31, 2017 |
(unaudited - millions of Canadian $) |
|
Carrying
amount |
|
|
Fair
value |
|
|
Carrying
amount |
|
|
Fair
value |
|
|
|
|
|
|
|
|
|
|
Long-term debt
including current portion1,2 |
|
(37,395 |
) |
|
(40,762 |
) |
|
(34,741 |
) |
|
(40,180 |
) |
Junior subordinated
notes |
|
(7,284 |
) |
|
(7,101 |
) |
|
(7,007 |
) |
|
(7,233 |
) |
|
|
(44,679 |
) |
|
(47,863 |
) |
|
(41,748 |
) |
|
(47,413 |
) |
1 Long-term debt is recorded at amortized cost except
for US$1.3 billion (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 six months ended
June 30, 2018 includes unrealized losses of $1 million and
unrealized gains of $4 million, respectively, (2017 – losses of $1
million and gains of $1 million, respectively) for fair value
adjustments attributable to the hedged interest rate risk
associated with interest rate swap fair value hedging relationships
on US$1.3 billion of long-term debt at June 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:
|
June 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 |
— |
|
|
24 |
|
|
— |
|
|
23 |
|
Maturing
within 1-5 years |
— |
|
|
105 |
|
|
— |
|
|
107 |
|
Maturing
within 5-10 years |
85 |
|
|
— |
|
|
14 |
|
|
— |
|
Maturing
after 10 years |
857 |
|
|
— |
|
|
790 |
|
|
— |
|
|
942 |
|
|
129 |
|
|
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.
|
|
June 30, 2018 |
|
June 30, 2017 |
(unaudited - millions of Canadian $) |
|
LMCI restricted
investments1 |
|
|
Other restricted
investments2 |
|
|
LMCI restricted
investments1 |
|
|
Other restricted
investments2 |
|
|
|
|
|
|
|
|
|
|
Net unrealized gains in
the period |
|
|
|
|
|
|
|
|
three months ended |
|
3 |
|
|
— |
|
|
13 |
|
|
— |
|
six months ended |
|
5 |
|
|
1 |
|
|
15 |
|
|
— |
|
Net realized losses in
the period |
|
|
|
|
|
|
|
|
three months ended |
|
(3 |
) |
|
— |
|
|
(1 |
) |
|
— |
|
six 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 June 30, 2018 (unaudited - millions of
Canadian $) |
Cash Flow
Hedges |
|
|
Fair Value
Hedges |
|
|
Net
Investment
Hedges |
|
|
Held for
Trading |
|
|
Total Fair
Value of
Derivative
Instruments1 |
|
|
|
|
|
|
|
|
|
|
|
Other current
assets |
|
|
|
|
|
|
|
|
|
Commodities2 |
— |
|
|
— |
|
|
— |
|
|
221 |
|
|
221 |
|
Foreign
exchange |
— |
|
|
— |
|
|
10 |
|
|
11 |
|
|
21 |
|
Interest rate |
4 |
|
|
— |
|
|
— |
|
|
— |
|
|
4 |
|
|
4 |
|
|
— |
|
|
10 |
|
|
232 |
|
|
246 |
|
Intangible and other
assets |
|
|
|
|
|
|
|
|
|
Commodities2 |
— |
|
|
— |
|
|
— |
|
|
46 |
|
|
46 |
|
Foreign
exchange |
— |
|
|
— |
|
|
2 |
|
|
— |
|
|
2 |
|
Interest rate |
15 |
|
|
— |
|
|
— |
|
|
— |
|
|
15 |
|
|
15 |
|
|
— |
|
|
2 |
|
|
46 |
|
|
63 |
|
Total Derivative Assets |
19 |
|
|
— |
|
|
12 |
|
|
278 |
|
|
309 |
|
Accounts payable and
other |
|
|
|
|
|
|
|
|
|
Commodities2 |
(8 |
) |
|
— |
|
|
— |
|
|
(158 |
) |
|
(166 |
) |
Foreign
exchange |
— |
|
|
— |
|
|
(93 |
) |
|
(90 |
) |
|
(183 |
) |
Interest rate |
— |
|
|
(6 |
) |
|
— |
|
|
— |
|
|
(6 |
) |
|
(8 |
) |
|
(6 |
) |
|
(93 |
) |
|
(248 |
) |
|
(355 |
) |
Other long-term
liabilities |
|
|
|
|
|
|
|
|
|
Commodities2 |
(2 |
) |
|
— |
|
|
— |
|
|
(32 |
) |
|
(34 |
) |
Foreign
exchange |
— |
|
|
— |
|
|
(15 |
) |
|
— |
|
|
(15 |
) |
Interest rate |
— |
|
|
(3 |
) |
|
— |
|
|
— |
|
|
(3 |
) |
|
(2 |
) |
|
(3 |
) |
|
(15 |
) |
|
(32 |
) |
|
(52 |
) |
Total Derivative Liabilities |
(10 |
) |
|
(9 |
) |
|
(108 |
) |
|
(280 |
) |
|
(407 |
) |
Total Derivatives |
9 |
|
|
(9 |
) |
|
(96 |
) |
|
(2 |
) |
|
(98 |
) |
1 Fair value equals carrying value.
2 Includes purchases and sales of power, natural gas and
liquids.
at December 31, 2017 (unaudited - millions of
Canadian $) |
Cash Flow
Hedges |
|
|
Fair Value
Hedges |
|
|
Net
Investment
Hedges |
|
|
Held for
Trading |
|
|
Total Fair
Value of
Derivative
Instruments1 |
|
|
|
|
|
|
|
|
|
|
|
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 $) |
|
June 30, 2018 |
|
|
December 31, 2017 |
|
|
June 30, 2018 |
|
|
December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
Current portion of
long-term debt |
|
(1,114 |
) |
|
(688 |
) |
|
4 |
|
|
1 |
|
Long-term
debt |
|
(520 |
) |
|
(685 |
) |
|
5 |
|
|
4 |
|
|
|
(1,634 |
) |
|
(1,373 |
) |
|
9 |
|
|
5 |
|
1 At June 30, 2018 and December 31, 2017,
adjustments for discontinued hedging relationships included in the
balance 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 June 30, 2018 (unaudited) |
Power |
|
|
Natural
Gas |
|
|
Liquids |
|
|
Foreign
Exchange |
|
|
Interest |
|
|
|
|
|
|
|
|
|
|
|
Purchases1 |
38,381 |
|
|
87 |
|
|
40 |
|
|
— |
|
|
— |
|
Sales1 |
27,191 |
|
|
92 |
|
|
52 |
|
|
— |
|
|
— |
|
Millions
of U.S. dollars |
— |
|
|
— |
|
|
— |
|
|
3,504 |
|
|
2,450 |
|
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 (unaudited) |
Power |
|
|
Natural
Gas |
|
|
Liquids |
|
|
Foreign
Exchange |
|
|
Interest |
|
|
|
|
|
|
|
|
|
|
|
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 gains/(losses) on derivative
instruments
The following summary does not include hedges of the net investment
in foreign operations.
|
|
three months ended June 30 |
|
six months ended June 30 |
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Derivative
Instruments Held for Trading1 |
|
|
|
|
|
|
|
|
Amount of unrealized
gains/(losses) in the period |
|
|
|
|
|
|
|
|
Commodities2 |
|
99 |
|
|
(91 |
) |
|
(10 |
) |
|
(147 |
) |
Foreign
exchange |
|
(60 |
) |
|
41 |
|
|
(139 |
) |
|
56 |
|
Amount of realized
gains/(losses) in the period |
|
|
|
|
|
|
|
|
Commodities |
|
19 |
|
|
(37 |
) |
|
129 |
|
|
(85 |
) |
Foreign
exchange |
|
4 |
|
|
(5 |
) |
|
19 |
|
|
(9 |
) |
Derivative
Instruments in Hedging Relationships |
|
|
|
|
|
|
|
|
Amount of realized
(losses)/gains in the period |
|
|
|
|
|
|
|
|
Commodities |
|
(4 |
) |
|
7 |
|
|
(1 |
) |
|
13 |
|
Foreign
exchange |
|
— |
|
|
— |
|
|
— |
|
|
5 |
|
Interest rate |
|
— |
|
|
— |
|
|
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 six months ended June 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 June 30 |
|
six months ended June 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 |
) |
|
(6 |
) |
|
3 |
|
Interest rate |
|
— |
|
|
— |
|
|
9 |
|
|
1 |
|
|
|
(3 |
) |
|
(2 |
) |
|
3 |
|
|
4 |
|
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 June 30 |
|
|
Revenues (Energy) |
|
Interest Expense |
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Total Amount
Presented in the Condensed Consolidated Statement of
Income |
|
514 |
|
|
778 |
|
|
(558 |
) |
|
(524 |
) |
Fair Value
Hedges |
|
|
|
|
|
|
|
|
Interest rate
contracts |
|
|
|
|
|
|
|
|
Hedged
items |
|
— |
|
|
— |
|
|
(22 |
) |
|
(19 |
) |
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 |
|
— |
|
|
— |
|
|
3 |
|
|
1 |
|
Commodity
contracts2 |
|
2 |
|
|
(7 |
) |
|
— |
|
|
— |
|
Reclassification of
gains on derivative instruments from AOCI to net income as a result
of forecasted transactions that are no longer probable of
occurring |
|
|
|
|
|
|
|
|
Interest rate contracts1 |
|
— |
|
|
— |
|
|
4 |
|
|
4 |
|
1 Refer to Note 10, Other comprehensive income/(loss)
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.
|
|
six months ended June 30 |
|
|
Revenues (Energy) |
|
Interest Expense |
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
Total Amount
Presented in the Condensed Consolidated Statement of
Income |
|
1,189 |
|
|
1,694 |
|
|
(1,085 |
) |
|
(1,024 |
) |
Fair Value
Hedges |
|
|
|
|
|
|
|
|
Interest rate
contracts |
|
|
|
|
|
|
|
|
Hedged
items |
|
— |
|
|
— |
|
|
(42 |
) |
|
(38 |
) |
Derivatives designated as hedging instruments |
|
— |
|
|
— |
|
|
(2 |
) |
|
2 |
|
Cash Flow
Hedges |
|
|
|
|
|
|
|
|
Reclassification of
gains/(losses) on derivative instruments from AOCI to
net income |
|
|
|
|
|
|
|
|
Interest
rate contracts1 |
|
— |
|
|
— |
|
|
4 |
|
|
1 |
|
Commodity
contracts2 |
|
1 |
|
|
(11 |
) |
|
— |
|
|
— |
|
Reclassification of
gains on derivative instruments from AOCI to net income as a result
of forecasted transactions that are no longer probable of
occurring |
|
|
|
|
|
|
|
|
Interest rate contracts1 |
|
— |
|
|
— |
|
|
8 |
|
|
8 |
|
1 Refer to Note 10, Other comprehensive income/(loss)
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 June 30, 2018 (unaudited - millions of
Canadian $) |
|
Gross derivative instruments |
|
|
Amounts available
for offset1 |
|
|
Net amounts |
|
|
|
|
|
|
|
|
Derivative instrument
assets |
|
|
|
|
|
|
Commodities |
|
267 |
|
|
(139 |
) |
|
128 |
|
Foreign
exchange |
|
23 |
|
|
(23 |
) |
|
— |
|
Interest rate |
|
19 |
|
|
(1 |
) |
|
18 |
|
|
|
309 |
|
|
(163 |
) |
|
146 |
|
Derivative instrument
liabilities |
|
|
|
|
|
|
Commodities |
|
(200 |
) |
|
139 |
|
|
(61 |
) |
Foreign
exchange |
|
(198 |
) |
|
23 |
|
|
(175 |
) |
Interest rate |
|
(9 |
) |
|
1 |
|
|
(8 |
) |
|
|
(407 |
) |
|
163 |
|
|
(244 |
) |
1 Amounts available for offset do not include cash
collateral pledged or received.
at December 31, 2017 (unaudited - millions of
Canadian $) |
|
Gross derivative instruments |
|
|
Amounts available
for offset1 |
|
|
Net amounts |
|
|
|
|
|
|
|
|
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 $125 million and letters of
credit of $12 million as at June 30, 2018 (December 31,
2017 – $165 million and $30 million) to its counterparties. At
June 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.
Based on contracts in place and market prices at June 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 June 30, 2018 or
December 31, 2017. If the credit-risk-related contingent
features in these agreements were triggered on June 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 June 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 |
|
75 |
|
|
103 |
|
|
89 |
|
|
267 |
|
Foreign
exchange |
|
— |
|
|
23 |
|
|
— |
|
|
23 |
|
Interest
rate |
|
— |
|
|
19 |
|
|
— |
|
|
19 |
|
Derivative instrument
liabilities |
|
|
|
|
|
|
|
|
Commodities |
|
(72 |
) |
|
(79 |
) |
|
(49 |
) |
|
(200 |
) |
Foreign
exchange |
|
— |
|
|
(198 |
) |
|
— |
|
|
(198 |
) |
Interest
rate |
|
— |
|
|
(9 |
) |
|
— |
|
|
(9 |
) |
|
|
3 |
|
|
(141 |
) |
|
40 |
|
|
(98 |
) |
1 There were no transfers from Level I to Level II or
from Level II to Level III for the six months ended June 30,
2018.
at December 31, 2017 (unaudited - millions of
Canadian $) |
|
Quoted prices in
active markets
(Level I)1 |
|
|
Significant other
observable inputs
(Level II)1 |
|
|
Significant
unobservable
inputs
(Level III)1 |
|
|
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 June 30 |
|
six months ended June 30 |
(unaudited - millions of Canadian $) |
|
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
Balance at beginning of
period |
|
|
(18 |
) |
|
10 |
|
|
(7 |
) |
|
16 |
|
Total gains/(losses)
included in Net income |
|
|
20 |
|
|
(2 |
) |
|
18 |
|
|
(2 |
) |
Settlements |
|
|
32 |
|
|
5 |
|
|
23 |
|
|
5 |
|
Sales |
|
|
— |
|
|
(3 |
) |
|
— |
|
|
(5 |
) |
Transfers out of Level
III |
|
|
6 |
|
|
(1 |
) |
|
6 |
|
|
(5 |
) |
Balance at end of period1 |
|
|
40 |
|
|
9 |
|
|
40 |
|
|
9 |
|
1 For the three and six months ended June 30,
2018, Revenues include unrealized gains of $50 million and $44
million, respectively, attributed to derivatives in the Level III
category that were still held at June 30, 2018 (2017 –
unrealized losses of $1 million and unrealized gains of $1 million,
respectively).
A 10 per cent increase or decrease in commodity prices, with all
other variables held constant, would result in a $16 million
increase or decrease, respectively, in the fair value of
outstanding derivative instruments included in Level III as at
June 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 June 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 |
|
203 |
|
|
1 |
|
|
315 |
|
|
2 |
|
Bruce Power |
|
ranging
to 2019 |
|
88 |
|
|
— |
|
|
88 |
|
|
1 |
|
Other
jointly-owned entities |
|
ranging to 2059 |
|
104 |
|
|
11 |
|
|
104 |
|
|
13 |
|
|
|
|
|
395 |
|
|
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:
|
|
June 30, |
|
|
December 31, |
|
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
|
|
|
|
ASSETS |
|
|
|
|
Current
Assets |
|
|
|
|
Cash and cash
equivalents |
|
67 |
|
|
41 |
|
Accounts
receivable |
|
43 |
|
|
63 |
|
Inventories |
|
24 |
|
|
23 |
|
Other |
|
14 |
|
|
11 |
|
|
|
148 |
|
|
138 |
|
Plant, Property
and Equipment |
|
3,654 |
|
|
3,535 |
|
Equity
Investments |
|
954 |
|
|
917 |
|
Goodwill |
|
514 |
|
|
490 |
|
Intangible and Other Assets |
|
15 |
|
|
3 |
|
|
|
5,285 |
|
|
5,083 |
|
LIABILITIES |
|
|
|
|
Current
Liabilities |
|
|
|
|
Accounts payable and
other |
|
66 |
|
|
137 |
|
Dividends payable |
|
— |
|
|
1 |
|
Accrued interest |
|
24 |
|
|
23 |
|
Current
portion of long-term debt |
|
75 |
|
|
88 |
|
|
|
165 |
|
|
249 |
|
Regulatory
Liabilities |
|
38 |
|
|
34 |
|
Other Long-Term
Liabilities |
|
2 |
|
|
3 |
|
Deferred Income
Tax Liabilities |
|
13 |
|
|
13 |
|
Long-Term Debt |
|
3,287 |
|
|
3,244 |
|
|
|
3,505 |
|
|
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:
|
|
June 30, |
|
|
December 31, |
|
(unaudited - millions of Canadian $) |
|
2018 |
|
|
2017 |
|
|
|
|
|
|
Balance
sheet |
|
|
|
|
Equity
investments |
|
4,382 |
|
|
4,372 |
|
Off-balance
sheet |
|
|
|
|
Potential exposure to guarantees |
|
171 |
|
|
171 |
|
Maximum exposure to loss |
|
4,553 |
|
|
4,543 |
|
15. Subsequent Event
On July 3, 2018, TCPL issued $800 million of Medium Term Notes,
due in July 2048, bearing interest at a fixed rate of 4.182 per
cent and $200 million of Medium Term Notes, due in March 2028,
bearing interest at a fixed rate of 3.39 per cent.
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