TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the
Company) today announced net income attributable to common shares
for fourth quarter 2017 of $861 million or $0.98 per share compared
to a net loss of $358 million or $0.43 per share for the same
period in 2016. For the year ended December 31, 2017, net income
attributable to common shares was $3.0 billion or $3.44 per share
compared to net income of $124 million or $0.16 per share in 2016.
Comparable earnings for fourth quarter 2017 were $719 million or
$0.82 per common share compared to $626 million or $0.75 per share
for the same period last year. For the year ended December 31,
2017, comparable earnings were $2.7 billion or $3.09 per common
share compared to $2.1 billion or $2.78 per share in 2016.
TransCanada's Board of Directors also declared a quarterly dividend
of $0.69 per common share for the quarter ending March 31,
2018, equivalent to $2.76 per common share on an annualized basis,
an increase of 10.4 per cent. This is the eighteenth consecutive
year the Board of Directors has raised the dividend.
"We are pleased that our vision of becoming one of North
America’s leading energy infrastructure companies is becoming a
reality. In 2017, we advanced a number of strategic initiatives and
delivered record financial performance following the successful
integration of Columbia into our operations," said Russ Girling,
TransCanada’s president and chief executive officer. "Comparable
earnings per share increased eleven per cent compared to 2016 while
comparable funds generated from operations of $5.6 billion were
nine per cent higher than last year. The increases reflect the
strong performance of our existing assets and approximately $5
billion of growth projects that were completed and placed into
service during 2017. They included expansions of our NGTL and
Canadian Mainline systems in our Canadian natural gas pipelines
business, the Gibraltar and Rayne XPress projects in U.S. natural
gas pipelines and the Grand Rapids and Northern Courier liquids
pipelines in Alberta."
"Looking forward, we will continue to advance a $23 billion
near-term capital program, including an additional $2.4 billion on
NGTL. This program is expected to generate significant additional
growth in earnings and cash flow and support continued 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 $8 billion into
these projects to date and are well positioned to fund the
remainder of this capital program through our strong and growing
internally generated cash flow and access to capital markets on
compelling terms."
"In addition, we continue to advance more than $20 billion of
medium to longer-term projects including Keystone XL, Coastal
GasLink and the Bruce Power life extension program. Progress on
Keystone XL continues following the Nebraska Public Service
Commission approval of a viable route through the state, which we
support, and the receipt of commercial commitments for the project.
At the same time we expect to secure additional organic growth
associated with our extensive North American footprint in natural
gas pipelines, liquids pipelines and power generation as evidenced
by ongoing expansions of the NGTL System. These initiatives
highlight the strong competitive position of our asset base and our
proven ability to continuously replenish our growth portfolio with
attractive, strategic, low-risk investment opportunities. Success
in advancing these and other projects into construction and
operation could extend our dividend growth outlook beyond 2021,"
concluded Girling.
Highlights
(All financial figures are unaudited and in Canadian dollars
unless noted otherwise)
• Fourth quarter 2017 financial results:
- Net income attributable to common shares of $861 million or
$0.98 per share
- Comparable earnings of $719 million or $0.82 per common
share
- Comparable earnings before interest, taxes, depreciation and
amortization of $1.9 billion
- Net cash provided by operations of $1.4 billion
- Comparable funds generated from operations of $1.5 billion
- Comparable distributable cash flow of $1.3 billion or $1.45 per
common share reflecting only non-recoverable maintenance capital
expenditures
• For the year ended December 31, 2017:
- Net income attributable to common shares of $3.0 billion or
$3.44 per share
- Comparable earnings of $2.7 billion or $3.09 per common
share
- Comparable earnings before interest, taxes, depreciation and
amortization of $7.4 billion
- Net cash provided by operations of $5.2 billion
- Comparable funds generated from operations of $5.6 billion
- Comparable distributable cash flow of $5.0 billion or $5.69 per
common share reflecting only non-recoverable maintenance capital
expenditures
• Fourth quarter highlights:
- Announced a 10.4 per cent increase in the quarterly common
share dividend to $0.69 per common share for the quarter
ending March 31, 2018
- NGTL placed approximately $0.6 billion of facilities in service
during the fourth quarter bringing the total to $1.7 billion in
2017
- Placed Rayne XPress and Gibraltar into service in November,
followed by Leach XPress on January 1, 2018
- Received FERC certificates for the WB XPress, Mountaineer
XPress and Gulf XPress projects
- Completed the sale of our Ontario solar assets for $541
million
- Announced that we would no longer be pursuing Energy East and
related projects
- Raised US$1.25 billion in 2-year floating and fixed rate senior
debt on November 15, 2017
- Concluded open seasons for the Keystone and Marketlink pipeline
systems and secured incremental long-term contractual
commitments
- Received approval for a route through Nebraska for Keystone XL
from the Nebraska Public Service Commission
- In January 2018, announced that we received commercial support
for the Keystone XL project
- In February 2018, announced a new NGTL System expansion for
2021 of $2.4 billion
Net income attributable to common shares increased by $1.2
billion or $1.41 per share to $861 million or $0.98 per share for
the three months ended December 31, 2017 compared to the same
period last year. Fourth quarter 2017 results included an $804
million recovery of deferred income taxes as a result of U.S. Tax
Reform, a $136 million after- tax gain related to the sale of our
Ontario solar assets and a $64 million after-tax net gain related
to the monetization of our U.S. Northeast power business. These
gains were partially offset by 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
and 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. All of these specific items, as
well as unrealized gains and losses from changes in risk management
activities, are excluded from comparable earnings.
Net income attributable to common shares for the year ended
December 31, 2017 was $3.0 billion or $3.44 per share compared to
$124 million or $0.16 per share in 2016. Net income per common
share includes the dilutive effect of issuing 161 million common
shares in 2016 and common shares issued under our DRP and corporate
ATM program in 2017. Results in 2017 included an $804 million
recovery of deferred income taxes as a result of U.S. Tax Reform, a
$307 million after-tax net gain related to the monetization of our
U.S. Northeast power business and a $136 million after-tax gain
related to the sale of our Ontario solar assets. These items were
partially offset by 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 $69
million after-tax charge for integration-related costs associated
with the acquisition of Columbia, a $28 million after-tax charge
related to the maintenance and liquidation of Keystone XL assets
which were expensed pending further advancement of the project and
a $7 million income tax recovery in first quarter related to the
realized loss on a third party sale of Keystone XL project 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 fourth quarter 2017 were $719 million or
$0.82 per share compared to $626 million or $0.75 per share for the
same period in 2016, an increase of $93 million or $0.07 per share.
The increase in fourth quarter comparable earnings was primarily
due to the net effect of a higher contribution from U.S. Natural
Gas Pipelines due to lower operating costs including synergies
achieved from the Columbia acquisition, a higher contribution from
Liquids Pipelines primarily due to higher volumes on Keystone, the
commencement of operations on Northern Courier and Grand Rapids and
liquids marketing activities, higher earnings from Bruce Power
mainly due to higher volumes resulting from fewer outage days, and
higher AFUDC on our rate-regulated U.S. natural gas pipelines,
partially offset by our decision not to proceed with the Energy
East pipeline, a lower contribution from U.S. Power due to the
monetization of our U.S. Northeast power generation assets in
second quarter 2017 and the continued wind-down of our U.S. power
marketing operations and an after-tax impairment charge in 2017
related to obsolete Energy equipment.
Comparable earnings for the year ended December 31, 2017 of $2.7
billion or $3.09 per share were $582 million or $0.31 per common
share higher than in 2016 and includes the dilutive effect of
issuing 161 million common shares in 2016 and common shares issued
under our DRP and corporate ATM program in 2017. The 2017 increase
in comparable earnings was primarily the net result of a higher
contribution from U.S. Natural Gas Pipelines due to incremental
earnings from Columbia following the July 2016 acquisition and
higher ANR transportation revenue resulting from a FERC-approved
rate settlement, increased earnings from Liquids Pipelines
primarily due to higher volumes on the Keystone Pipeline System,
liquids marketing activities and the commencement of operations on
Grand Rapids and Northern Courier, higher earnings from Bruce Power
mainly due to higher volumes resulting from fewer outage days, a
higher contribution from Mexico Natural Gas Pipelines due to
earnings from Topolobampo beginning in July 2016 and Mazatlán
beginning in December 2016, higher AFUDC on our rate-regulated U.S.
natural gas pipelines, the NGTL System, Tula and Villa de Reyes,
partially offset by the commercial in-service of Topolobampo and
completion of Mazatlán construction, and higher interest income and
other due to income related to Coastal GasLink project costs and
the termination of the PRGT project. These items were partially
offset by lower contributions from U.S. Power due to the sales of
our U.S. Northeast power generation assets in second quarter 2017
and the wind-down of our U.S. power marketing operations, as well
as higher interest expense as a result of debt assumed in the
acquisition of Columbia on July 1, 2016 and long-term debt and
junior subordinated note issuances in 2017, net of maturities.
Notable recent developments include:
Canadian Natural Gas Pipelines:
- NGTL System: In February 2018, we announced a $2.4 billion NGTL
System expansion with expected in- service dates between 2019 and
2021 that includes approximately 375 km (233 miles) of 16-inch to
48-inch pipeline, four compression units and associated facilities.
We anticipate incremental firm receipt contracts of 664
TJ/d (620 MMcf/d) and firm delivery contracts to our major border
export and intra-basin delivery locations of 1.1 PJ/d (1.0 Bcf/d).
With this expansion, NGTL now has a $7.2 billion growth capital
program, excluding the $1.9 billion Merrick pipeline project. In
2017, we placed approximately $1.7 billion of facilities in
service.On December 28, 2017, the NEB approved the Sundre Crossover
Project on the NGTL System. The approximate $100 million project
will increase delivery of 245 TJ/d (229 MMcf/d) to the Alberta /
British Columbia border to connect with TransCanada downstream
pipelines. In-service is planned for April 1, 2018.
- North Montney: In 2017, we filed an application with the NEB
for a variance to the existing approvals for the North Montney
Project on the NGTL System to remove the condition that the project
could only proceed once a positive final investment decision was
made for the Pacific Northwest LNG project. The North Montney
project is now underpinned by restructured 20-year commercial
contracts and is not dependent on the LNG project proceeding. A
hearing on the matter began the week of January 22, 2018 and a
decision from the NEB is anticipated in second quarter 2018.
- NGTL 2018 Revenue Requirement: NGTL's 2016-2017 Settlement,
which established revenue requirements for the system, expired on
December 31, 2017. We continue to work with interested parties
towards a new revenue requirement arrangement for 2018 and longer.
While these discussions are underway, NGTL is operating under
interim tolls for 2018 that were approved by the NEB on November
24, 2017.
- Canadian Mainline Long-Term Fixed-Price Service: On November 1,
2017, we began offering the new Long-Term Fixed-Price service
on the Canadian Mainline. This NEB-approved service enables WCSB
producers to transport up to 1.5 PJ/d (1.4 Bcf/d) of natural gas at
a simplified toll of $0.77/GJ from the Empress receipt point in
Alberta to the Dawn hub in Southern Ontario. The service is
underpinned by ten-year contracts that have early termination
rights after five years. Any early termination will result in an
increased toll for the last two years of the contract.
- Canadian Mainline 2018-2020 Toll Review: Tolls for the Canadian
Mainline were previously established for 2015 to 2017 in accordance
with the terms of the 2015-2030 LDC Settlement. While the
settlement specified tolls for 2015 to 2020, the NEB ordered a toll
review halfway through the six-year period which must include
costs, forecast volumes, contract levels, deferral balances and any
other material changes. A Supplemental Agreement for the 2018 to
2020 period was executed on December 8, 2017 and filed for approval
with the NEB on December 18, 2017. The Agreement proposes lower
tolls, maintains an incentive arrangement that provides the
opportunity for a 10.1 per cent or greater return on 40 per cent
deemed equity and describes the revenue requirements and billing
determinants for the 2018-2020 period. We anticipate the NEB will
provide direction and process to adjudicate the application in
first quarter 2018. Interim tolls for 2018 were filed at the level
established by the agreement and subsequently approved by the NEB
on December 19, 2017.
U.S. Natural Gas Pipelines:
- Gibraltar: Gibraltar, a Midstream project consisting of a 1,000
TJ/d (934 MMcf/d) dry gas header pipeline in southwest
Pennsylvania, was placed in service November 1, 2017.
- Rayne XPress: Rayne Xpress was placed in service November 2,
2017. This Columbia Gulf project transports approximately 1.1 PJ/d
(1.0 Bcf/d) of supply from an interconnect with the Leach XPress
pipeline project, and another interconnect, to markets along the
system and to the Gulf Coast.
- Leach XPress: Leach XPress was placed in service January 1,
2018. This Columbia Gas project transports approximately 1.6 PJ/d
(1.5 Bcf/d) of Marcellus and Utica gas supply to delivery points
along the system.
- WB, Mountaineer and Gulf XPress: The FERC certificate for WB
XPress was received in November 2017 and the FERC certificates for
Mountaineer XPress and Gulf XPress projects were received on
December 29, 2017.
Mexico Natural Gas Pipelines:
- Tula: Construction of the Tula pipeline continues with
completion revised to late 2019 due to delays experienced by the
Secretary of Energy, the governmental department which conducts
indigenous consultations in Mexico. Construction of the Tula
pipeline was substantially completed in 2017 with the exception of
approximately 90 km (56 miles) of the pipeline. The delay has been
recognized by the CFE as a force majeure event and we are
finalizing amending agreements to formalize the schedule and
payment impacts. As a result of the delay and increased costs of
land and permitting, estimated project costs have increased by
US$0.1 billion from the original estimate.
- Villa de Reyes: Construction has commenced, however, delays due
to archeological investigations by federal authorities have caused
the in-service date of the project to be revised to late 2018. The
delay has been recognized as a force majeure event by the CFE and
we are finalizing amending agreements to formalize the schedule and
payment impacts. As a result of the delay and increased costs of
land and permitting, estimated project costs have increased by
US$0.2 billion from the original estimate.
- Sur de Texas: Construction on the pipeline is progressing
toward an anticipated in-service date of late 2018, with
approximately 60 per cent of the off-shore construction completed
as of the end of 2017.
Liquids Pipelines:
- Keystone XL: In February 2017, we filed an application with the
Nebraska Public Service Commission (PSC) seeking approval for the
Keystone XL pipeline route through that state and received approval
for an alternate route on November 20, 2017. On December 27, 2017,
opponents of the Keystone XL project, and intervenors in the
Keystone XL Nebraska regulatory proceeding, filed an appeal of the
November 20, 2017 PSC decision seeking to have that decision
overturned. TransCanada supports the decision of the Nebraska PSC
and will actively participate in the appeal process to defend that
decision. In January 2018, TransCanada announced that we
secured approximately 500,000 barrels per day of firm, 20- year
commitments, following an open season in 2017, positioning the
proposed project to proceed. The Company will look to continue to
secure additional long-term contracted volumes. We are also
continuing an outreach program in the communities where the
pipeline will be constructed and are working collaboratively with
landowners in an open and transparent way to obtain the necessary
easements for the approved route. Construction preparation has
commenced and will increase as the permitting process advances
throughout 2018. Primary construction is expected to begin in 2019
and will take approximately two years to complete.
- Keystone Pipeline System: In fourth quarter 2017, we concluded
open seasons for the Keystone and Marketlink pipeline systems and
secured incremental long-term contractual support.On November 16,
2017, the Keystone pipeline was temporarily shut down after a leak
was detected in Marshall County, South Dakota. On November 29,
2017, the pipeline was repaired and returned to service at a
reduced pressure in the affected section of the pipeline. Further
investigative activities and corrective measures required by the
Pipeline and Hazardous Materials Safety Administration (PHMSA) are
planned for 2018. This shutdown did not have a significant impact
on our 2017 earnings.
- Northern Courier: The $1 billion Northern Courier project
achieved commercial in-service in November 2017.
- White Spruce: In first quarter 2018, we anticipate
receiving a decision from the Alberta Energy Regulator on the
regulatory permit to construct the $200 million White Spruce
pipeline, which will transport crude oil from Canadian Natural
Resources Limited's Horizon facility in northeast Alberta into the
Grand Rapids pipeline. Due to the delay in the regulatory
process, we expect the White Spruce pipeline to be in-service in
2019.
- Energy East and Related Projects: In September 2017, we
requested the NEB suspend the review of the Energy East and Eastern
Mainline project applications for 30 days to provide time for us to
conduct a careful review of the NEB's changes, announced on August
23, 2017, regarding the list of issues and environmental assessment
factors related to the projects and how these changes impact the
projects' costs, schedules and viability. In October 2017, we
announced that we would no longer be pursuing these projects. We
reviewed the $1.3 billion carrying value of the projects, including
AFUDC capitalized since inception, and recorded a $954 million
after-tax non-cash charge in fourth quarter 2017. With Energy
East’s inability to reach a regulatory decision, no recoveries of
costs from third parties are forthcoming.
Energy:
- Napanee: Construction continues on our 900 MW natural gas-fired
power plant. We expect to invest approximately $1.3 billion in the
Napanee facility and commercial operations are expected to begin in
fourth quarter 2018. Costs have increased due to delays in the
construction schedule. Once in service, production from the
facility is fully contracted with Ontario's Independent Electricity
System Operator for a 20-year period.
- Ontario Solar: On October 24, 2017, we entered into an
agreement to sell our Ontario solar assets comprised of eight
facilities with a total generating capacity of 76 MWs. On December
19, 2017, we closed the sale for $541 million resulting in a
pre-tax gain of $127 million ($136 million after-tax).
- Monetization of U.S. Northeast power business: On December 22,
2017, we entered into an agreement to sell our U.S. power retail
contracts as part of the continued wind down of our U.S. power
marketing operations. The transaction is expected to close in the
first quarter of 2018 subject to regulatory and other
approvals.
Corporate:
- Common Share Dividend: Our Board of Directors declared a
quarterly dividend of $0.69 per share for the quarter ending
March 31, 2018 on TransCanada's outstanding common shares. This
represents an increase in the dividend of 10.4 per cent from the
previous dividend and is equivalent to $2.76 per common share
on an annualized basis.
- Issuance of Senior Notes: On November 15, 2017, we raised
US$700 million in Senior Unsecured Notes at a fixed interest rate
of 2.125 per cent and US$550 million in Senior Unsecured Notes at a
floating rate, both due in November 2019.
- Dividend Reinvestment Plan (DRP): In 2017, the participation
rate in our DRP was approximately 36 per cent of common share
dividends, resulting in $790 million of common equity issued under
the program.
- ATM Equity Issuance Program: In fourth quarter 2017, 3.5
million common shares were issued through the corporate ATM program
at an average price of $63.03 per share for gross proceeds of $218
million.
- U.S. Tax Reform: As a result of changes to U.S. tax legislation
resulting from the enactment of H.R. 1, the Tax Cuts and Jobs Act,
in the fourth quarter we recorded an $804 million recovery of
deferred income taxes, a $1,686 million increase in net regulatory
liabilities and a $2,490 million decrease in net deferred income
tax liabilities.
Teleconference and Webcast:
We will hold a teleconference and webcast on Thursday, February
15, 2018 to discuss our fourth quarter 2017 and year-end financial
results. Russ Girling, TransCanada President and Chief Executive
Officer, and Don Marchand, Executive Vice-President and Chief
Financial Officer, along with other members of the TransCanada
executive leadership team, will discuss the financial results and
Company developments at 2 p.m. (MST) / 4 p.m. (EST).
Members of the investment community and other
interested parties are invited to participate by calling
800.273.9672 or 416.340.2216 (Toronto area). No pass code is
required. Please dial in 10 minutes prior to the start of the call.
A live webcast of the teleconference will be available at
www.transcanada.com.
A replay of the teleconference will be available two hours after
the conclusion of the call until midnight (EST) on February 22,
2018. Please call 800.408.3053 or 905.694.9451 (Toronto area) and
enter pass code 2578190#.
The audited annual Consolidated Financial Statements and
Management’s Discussion and Analysis (MD&A) are available under
TransCanada's profile on SEDAR at www.sedar.com, with the U.S.
Securities and Exchange Commission on EDGAR at
www.sec.gov/info/edgar.shtml and on the TransCanada website at
www.transcanada.com.
With more than 65 years' experience, TransCanada is a leader in
the responsible development and reliable operation of North
American energy infrastructure including natural gas and liquids
pipelines, power generation and gas storage facilities. TransCanada
operates one of the largest natural gas transmission networks that
extends more than 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 currently 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 TransCanada.com to learn
more, or connect with us on social media and 3BL Media.
Media Enquiries:Mark Cooper / Grady Semmens
403.920.7859 or 800.608.7859
Investor & Analyst Enquiries: David Moneta
/ Stuart Kampel 403.920.7911 or 800.361.6522
Fourth quarter 2017 financial highlights
|
|
|
|
|
|
|
three months endedDecember
31 |
|
year endedDecember
31 |
(unaudited - millions of $, except per share amounts) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
Income |
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
3,617 |
|
|
3,635 |
|
|
13,449 |
|
|
12,547 |
Net income/(loss)
attributable to common shares |
|
861 |
|
|
(358 |
) |
|
2,997 |
|
|
124 |
per
common share |
|
|
|
|
|
|
|
|
|
|
|
-
basic |
|
$0.98 |
|
|
($0.43 |
) |
|
$3.44 |
|
|
$0.16 |
-
diluted |
|
$0.98 |
|
|
($0.43 |
) |
|
$3.43 |
|
|
$0.16 |
Comparable EBITDA1 |
|
1,903 |
|
|
1,890 |
|
|
7,377 |
|
|
6,647 |
Comparable
earnings1 |
|
719 |
|
|
626 |
|
|
2,690 |
|
|
2,108 |
per
common share1 |
|
$0.82 |
|
|
$0.75 |
|
|
$3.09 |
|
|
$2.78 |
Operating cash
flow |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
operations |
|
1,390 |
|
|
1,575 |
|
|
5,230 |
|
|
5,069 |
Comparable funds
generated from operations1 |
|
1,450 |
|
|
1,425 |
|
|
5,641 |
|
|
5,171 |
Comparable
distributable cash flow1 |
|
|
|
|
|
|
|
|
|
|
|
-
reflecting all maintenance capital expenditures |
|
727 |
|
|
928 |
|
|
3,599 |
|
|
3,541 |
-
reflecting only non-recoverable maintenance capital
expenditures |
|
1,268 |
|
|
1,251 |
|
|
4,963 |
|
|
4,482 |
Comparable
distributable cash flow per common share1 |
|
|
|
|
|
|
|
|
|
|
|
-
reflecting all maintenance capital expenditures |
|
$0.83 |
|
|
$1.12 |
|
|
$4.13 |
|
|
$4.67 |
-
reflecting only non-recoverable maintenance capital
expenditures |
|
$1.45 |
|
|
$1.50 |
|
|
$5.69 |
|
|
$5.91 |
|
|
|
|
|
|
|
|
|
|
|
|
Investing
activities |
|
|
|
|
|
|
|
|
|
|
|
Capital spending2 |
|
2,552 |
|
|
2,016 |
|
|
9,210 |
|
|
6,067 |
Acquisitions, net of
cash acquired |
|
— |
|
|
— |
|
|
— |
|
|
13,608 |
Proceeds from sales of
assets, net of transaction costs |
|
1,170 |
|
|
— |
|
|
5,317 |
|
|
6 |
Dividends
declared |
|
|
|
|
|
|
|
|
|
|
|
per
common share |
|
$0.625 |
|
|
$0.565 |
|
|
$2.50 |
|
|
$2.26 |
Basic common
shares outstanding (millions) |
|
|
|
|
|
|
|
|
|
|
|
-
weighted average |
|
877 |
|
|
832 |
|
|
872 |
|
|
759 |
- issued
and outstanding |
|
881 |
|
|
864 |
|
|
881 |
|
|
864 |
|
|
|
|
|
|
|
|
|
|
|
|
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. |
|
FORWARD-LOOKING INFORMATIONWe disclose
forward-looking information to help current and potential investors
understand management’s assessment of our future plans and
financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain
assumptions and on what we know and expect today. These statements
generally include words like anticipate, expect, believe, may,
will, should, estimate or other similar words.
Forward-looking statements in this news release include
information about the following, among other things:
- 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
- expected outcomes with respect to legal proceedings, including
arbitration and insurance claims
- expected capital expenditures and contractual obligations
- expected operating and financial results
- the expected impact of future accounting changes, commitments
and contingent liabilities
- the 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 news release.
Our forward-looking information is based on the following key
assumptions, and is subject to the following risks and
uncertainties:
Assumptions
- planned wind-down of our U.S. Northeast power marketing
business
- inflation rates and commodity prices
- nature and scope of hedging
- regulatory decisions and outcomes
- 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
- outcomes of legal proceedings, including arbitration and
insurance claims
- performance and credit risk of our counterparties
- changes in market commodity prices
- changes in the political environment
- changes in environmental and other laws and regulations
- competitive factors in the pipeline and energy sectors
- construction and completion of capital projects
- costs for labour, equipment and materials
- access to capital markets
- interest, tax and foreign exchange rates, including the impact
of U.S. Tax Reform
- weather
- cyber security
- technological developments
- economic conditions in North America as well as globally.
You can read more about these factors and others in reports we
have filed with Canadian securities regulators and the SEC,
including the MD&A in our 2016 Annual Report.
As actual results could vary significantly from the
forward-looking information, you should not put undue reliance on
forward-looking information and should not use future-oriented
information or financial outlooks for anything other than their
intended purpose. We do not update our forward-looking statements
due to new information or future events, unless we are required to
by law.
FOR MORE INFORMATIONYou can find more
information about TransCanada in our Annual Information Form and
other disclosure documents, which are available on SEDAR
(www.sedar.com).
NON-GAAP MEASURESThis news release 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 measuresWe 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 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 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/(loss)
attributable to common shares |
comparable earnings per
common share |
|
net income/(loss) per
common share |
comparable EBITDA |
|
segmented
earnings/(losses) |
comparable EBIT |
|
segmented
earnings/(losses) |
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
shareComparable earnings represents earnings or loss
attributable to common shareholders on a consolidated basis
adjusted for specific items. Comparable earnings is comprised of
segmented earnings, interest expense, AFUDC, interest income and
other, income taxes and non-controlling interests adjusted for the
specific items. See the reconciliation of net income to comparable
earnings.
Comparable EBIT and comparable EBITDAComparable
EBIT represents segmented earnings adjusted for the specific items
described above. 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 for a
reconciliation to segmented earnings.
Funds generated from operations and comparable funds
generated from operationsFunds generated from operations
reflects net cash provided by operations before changes in
operating working capital. We believe it is a useful measure of our
consolidated operating cash flow because it does not include
fluctuations from working capital balances, which do not
necessarily reflect underlying operations in the same period, and
is used to provide a consistent measure of the cash generating
performance of our assets. Comparable funds generated from
operations is adjusted for the cash impact of specific items noted
above. See the comparable distributable cash flow section for the
reconciliation to net cash provided by operations.
Comparable distributable cash flow and comparable
distributable cash flow per shareWe believe comparable
distributable cash flow is a useful supplemental measure of
performance that defines cash available to common shareholders
before capital allocation. Comparable distributable cash flow is
defined as comparable funds generated from operations less
preferred share dividends, distributions to non-controlling
interests and 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. See the comparable
distributable cash flow section for the reconciliation to net cash
provided by operations.
Although we deduct maintenance capital expenditures in
determining comparable distributable cash flow, we have the ability
to recover the majority of these costs in Canadian Natural Gas
Pipelines, U.S. Natural Gas Pipelines and Liquids Pipelines.
Canadian natural gas pipelines maintenance capital expenditures are
reflected in rate bases, on which we earn a regulated return and
subsequently recover in tolls. The majority of our U.S. natural gas
pipelines can seek to recover maintenance capital expenditures
through rates established in future rate cases or rate settlements.
As such, these maintenance capital expenditures are effectively
recovered in the same manner as expansion capital
expenditures. Tolling arrangements in Liquids Pipelines
provide for recovery of maintenance capital.
Effective December 31, 2017, we amended our presentation of
comparable distributable cash flow and comparable distributable
cash flow per share to illustrate the impact of excluding
recoverable maintenance capital expenditures from their respective
calculations. We have included comparable distributable cash flow
and comparative distributable cash flow per share for 2016 to
reflect the amended presentation format which we believe provides
better information for readers.
Consolidated results - fourth quarter 2017
We operate in three core businesses - Natural Gas Pipelines,
Liquids Pipelines and Energy. In order to provide information that
is aligned with how management decisions about our business are
made and how performance of our business is assessed, our results
are reflected in five operating segments: Canadian Natural Gas
Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas
Pipelines, Liquids Pipelines and Energy. We also have a
non-operational Corporate segment consisting of corporate and
administrative functions that provide governance and other support
to our operational business segments.
Certain costs previously reported in our Corporate segment are
now being reported within the business segments to better align
with how we measure our financial performance. 2016 results have
been adjusted to reflect this change.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
three months endedDecember
31 |
year endedDecember
31 |
(unaudited - millions of $, except per share amounts) |
|
2017 |
|
|
2016 |
|
2017 |
|
|
2016 |
|
Canadian Natural Gas
Pipelines |
|
333 |
|
|
364 |
|
1,236 |
|
|
1,307 |
|
U.S. Natural Gas
Pipelines |
|
461 |
|
|
403 |
|
1,760 |
|
|
1,190 |
|
Mexico Natural Gas
Pipelines |
|
93 |
|
|
103 |
|
426 |
|
|
287 |
|
Liquids Pipelines |
|
(932 |
) |
|
213 |
|
(251 |
) |
|
806 |
|
Energy |
|
472 |
|
|
(574 |
) |
1,552 |
|
|
(1,157 |
) |
Corporate |
|
63 |
|
|
(33 |
) |
(39 |
) |
|
(120 |
) |
Total
segmented earnings |
|
490 |
|
|
476 |
|
4,684 |
|
|
2,313 |
|
Interest expense |
|
(541 |
) |
|
(542 |
) |
(2,069 |
) |
|
(1,998 |
) |
Allowance for funds
used during construction |
|
140 |
|
|
97 |
|
507 |
|
|
419 |
|
Interest
income and other |
|
(9 |
) |
|
(15 |
) |
184 |
|
|
103 |
|
Income before
income taxes |
|
80 |
|
|
16 |
|
3,306 |
|
|
837 |
|
Income
tax recovery/(expense) |
|
870 |
|
|
(274 |
) |
89 |
|
|
(352 |
) |
Net
income/(loss) |
|
950 |
|
|
(258 |
) |
3,395 |
|
|
485 |
|
Net
income attributable to non-controlling interests |
|
(49 |
) |
|
(68 |
) |
(238 |
) |
|
(252 |
) |
Net
income/(loss) attributable to controlling interests |
|
901 |
|
|
(326 |
) |
3,157 |
|
|
233 |
|
Preferred
share dividends |
|
(40 |
) |
|
(32 |
) |
(160 |
) |
|
(109 |
) |
Net income/(loss) attributable to common
shares |
|
861 |
|
|
(358 |
) |
2,997 |
|
|
124 |
|
Net income/(loss) per common share |
|
|
|
|
- basic |
$0.98 |
|
($0.43 |
) |
$3.44 |
|
$0.16 |
|
- diluted |
$0.98 |
|
($0.43 |
) |
$3.43 |
|
$0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) attributable to common shares increased by
$1,219 million or $1.41 per share for the three months ended
December 31, 2017 compared to the same period in 2016 due to the
changes in net income described below, as well as the dilutive
effect of issuing 60 million common shares in the fourth quarter of
2016 and common shares issued under our DRP and corporate ATM
program in 2017.
Fourth quarter 2017 results included:
- an $804 million recovery of deferred income taxes as a result
of U.S. Tax Reform
- a $136 million after-tax gain related to the sale of our
Ontario solar assets
- a $64 million net after-tax gain related to the monetization of
our U.S. Northeast power 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.
Fourth quarter 2016 results included:
- 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 closing of the acquisition and $23 million of
retention, severance and integration cost.
- an $18 million after-tax charge related to the maintenance and
liquidation of Keystone XL assets which were 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 form
part of a restructuring initiative, which commenced in 2015, to
maximize the effectiveness and efficiency of our existing
operations and reduce overall costs.
Net income in all periods included unrealized gains and losses
from changes in risk management activities which we exclude, along
with the above-noted items, to arrive at comparable earnings. A
reconciliation of net income/(loss) attributable to common shares
to comparable earnings is shown in the following table.
RECONCILIATION OF NET INCOME/(LOSS) TO COMPARABLE
EARNINGS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
three months ended December 31 |
year endedDecember 31 |
(unaudited - millions of $, except per share amounts) |
|
2017 |
|
|
2016 |
|
2017 |
|
|
2016 |
|
Net
income/(loss) attributable to common shares |
|
861 |
|
|
(358 |
) |
2,997 |
|
|
124 |
|
Specific items (net of tax): |
|
|
|
|
U.S. Tax
Reform adjustment |
|
(804 |
) |
|
— |
|
(804 |
) |
|
— |
|
Gain on
sale of Ontario solar assets |
|
(136 |
) |
|
— |
|
(136 |
) |
|
— |
|
Net
(gain)/loss on sales of U.S. Northeast power assets |
|
(64 |
) |
|
870 |
|
(307 |
) |
|
873 |
|
Energy
East impairment charge |
|
954 |
|
|
— |
|
954 |
|
|
— |
|
Keystone
XL asset costs |
|
9 |
|
|
18 |
|
28 |
|
|
42 |
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
67 |
|
69 |
|
|
273 |
|
Keystone
XL income tax recoveries |
|
— |
|
|
— |
|
(7 |
) |
|
(28 |
) |
Ravenswood goodwill impairment |
|
— |
|
|
— |
|
— |
|
|
656 |
|
Alberta
PPA terminations and settlement |
|
— |
|
|
68 |
|
— |
|
|
244 |
|
Restructuring costs |
|
— |
|
|
6 |
|
— |
|
|
16 |
|
TC
Offshore loss on sale |
|
— |
|
|
— |
|
— |
|
|
3 |
|
Risk management activities1 |
|
(101 |
) |
|
(45 |
) |
(104 |
) |
|
(95 |
) |
Comparable earnings |
|
719 |
|
|
626 |
|
2,690 |
|
|
2,108 |
|
Net
income/(loss) per common share |
$0.98 |
|
($0.43 |
) |
$3.44 |
|
$0.16 |
|
Specific items (net of tax): |
|
|
|
|
U.S. Tax
Reform adjustment |
|
(0.92 |
) |
|
— |
|
(0.92 |
) |
|
— |
|
Gain on
sale of Ontario solar assets |
|
(0.16 |
) |
|
— |
|
(0.16 |
) |
|
— |
|
Net
loss/(gain) on sales of U.S. Northeast power assets |
|
(0.08 |
) |
|
1.05 |
|
(0.34 |
) |
|
1.15 |
|
Energy
East impairment charge |
|
1.09 |
|
|
— |
|
1.09 |
|
|
— |
|
Keystone
XL asset costs |
|
0.01 |
|
|
0.02 |
|
0.03 |
|
|
0.06 |
|
Integration and acquisition related costs – Columbia |
|
— |
|
|
0.08 |
|
0.08 |
|
|
0.37 |
|
Keystone
XL income tax recoveries |
|
— |
|
|
— |
|
(0.01 |
) |
|
(0.04 |
) |
Ravenswood goodwill impairment |
|
— |
|
|
— |
|
— |
|
|
0.86 |
|
Alberta
PPA terminations and settlement |
|
— |
|
|
0.08 |
|
— |
|
|
0.32 |
|
Restructuring costs |
|
— |
|
|
0.01 |
|
— |
|
|
0.02 |
|
Risk management activities |
|
(0.10 |
) |
|
(0.06 |
) |
(0.12 |
) |
|
(0.12 |
) |
Comparable earnings per common share |
$0.82 |
|
$0.75 |
|
$3.09 |
|
$2.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
Risk management
activities |
three months endedDecember 31 |
year ended December 31 |
|
(unaudited - millions of $) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
Canadian Power |
6 |
|
1 |
|
11 |
|
4 |
|
|
U.S. Power |
136 |
|
97 |
|
39 |
|
113 |
|
|
Liquids marketing |
15 |
|
4 |
|
— |
|
(2 |
) |
|
Natural Gas
Storage |
7 |
|
(1 |
) |
12 |
|
8 |
|
|
Interest rate |
— |
|
— |
|
(1 |
) |
— |
|
|
Foreign exchange |
(1 |
) |
(23 |
) |
88 |
|
26 |
|
|
Income
tax attributable to risk management activities |
(62 |
) |
(33 |
) |
(45 |
) |
(54 |
) |
|
Total unrealized gains from risk
management activities |
101 |
|
45 |
|
104 |
|
95 |
|
|
|
|
|
|
|
|
|
|
|
Comparable earnings increased by $93 million or $0.07 per share
for the three months ended December 31, 2017 compared to the same
period in 2016 and was primarily the net effect of:
- increased earnings from Liquids Pipelines primarily due to
higher uncontracted volumes on the Keystone Pipeline System,
liquids marketing activities, and the commencement of operations on
Grand Rapids and Northern Courier
- higher contribution from U.S. Natural Gas Pipelines due to
lower operating costs including synergies achieved from the
Columbia acquisition
- higher AFUDC on our rate-regulated U.S. natural gas pipelines,
partially offset by our decision not to proceed with the Energy
East Pipeline
- higher earnings from Bruce Power mainly due to higher volumes
resulting from fewer outage days
- lower contribution from U.S. Power due to the monetization of
our U.S. Northeast power generation assets in second quarter 2017
and the continued wind-down of our U.S. power marketing
operations
- an after-tax impairment charge in 2017 of $16 million related
to obsolete Energy equipment.
U.S. TAX REFORM
On December 22, 2017, H.R. 1, the Tax Cuts and Jobs Act (U.S.
Tax Reform or the Act) 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, we have remeasured existing
deferred income tax assets and deferred income tax liabilities
related to our U.S. businesses to reflect the new lower income tax
rate as at December 31, 2017.
For our businesses in the U.S. not subject to rate-regulated
accounting (RRA), the reduction in enacted tax rates has been
recorded as a decrease in net deferred income tax liabilities and
income tax expense, resulting in an increase in net income
attributable to common shares in the fourth quarter and for the
year ended December 31, 2017 in the amount of $816 million.
For our businesses in the U.S. subject to RRA, we expect the
lower income tax rates to impact future rate setting processes and
have therefore recognized a net regulatory liability with a
corresponding reduction in net deferred income tax liabilities in
the amount of $1,686 million. These regulatory liabilities will be
amortized to earnings over time.
Net deferred income tax liabilities related to the cumulative
remeasurements of employee post-retirement benefits included in
accumulated other comprehensive income have also been adjusted with
a corresponding increase in deferred income tax expense of $12
million.
Given the significance of the legislation, the Securities and
Exchange Commission (SEC) issued guidance which allows registrants
to record provisional amounts which may be adjusted as information
becomes available, prepared or analyzed during a measurement period
not to exceed one year.
The SEC guidance summarizes a three-step process to be applied
at each reporting period to identify: (1) where the accounting is
complete; (2) provisional amounts where the accounting is not yet
complete, but a reasonable estimate has been determined; and (3)
where a reasonable estimate cannot yet be determined and therefore
income taxes are reflected in accordance with law prior to the
enactment of the Act.
At December 31, 2017, we consider all amounts recorded related
to U.S. Tax Reform to be reasonable estimates that are provisional,
as our interpretation, assessment and presentation of the impact of
the tax law change, particularly as it has been applied to our
businesses subject to RRA, 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, we will review the
provisional amounts and adjust as appropriate.
As a result of the lower U.S. income tax rates included as part
of the Act, we expect a modest increase to 2018 earnings. In
addition to the reduction in statutory rates, longer-term there are
several other provisions in the new legislation which may impact us
prospectively, including changes to the expensing of depreciable
property, limitations to interest deductions, the creation of Base
Erosion Anti-Abuse Tax along with certain exemptions for
rate-regulated businesses. We continue to evaluate the impact of
these and other provisions of the Act.
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 $23 billion of
near-term projects and approximately $24 billion of commercially
supported medium to longer-term projects. Amounts presented exclude
maintenance capital expenditures, capitalized interest and
AFUDC.
All projects are subject to cost adjustments due to market
conditions, route refinement, permitting conditions, scheduling and
timing of regulatory permits.
Near-term projects
|
|
|
|
(unaudited - billions of $) |
Expected in-service date |
Estimated project cost |
Carrying value at December 31, 2017 |
Canadian
Natural Gas Pipelines |
|
|
|
Canadian Mainline |
2018-2021 |
0.2 |
— |
NGTL System |
2018 |
0.6 |
0.2 |
|
2019 |
2.3 |
0.3 |
|
2020 |
1.6 |
0.1 |
|
2021 |
2.7 |
— |
U.S Natural Gas
Pipelines |
|
|
|
Columbia Gas |
|
|
|
Leach
XPress1 |
2018 |
US
1.6 |
US
1.5 |
WB
XPress |
2018 |
US
0.8 |
US
0.4 |
Mountaineer XPress |
2018 |
US
2.6 |
US
0.5 |
Modernization II |
2018-2020 |
US
1.1 |
US
0.1 |
Buckeye
XPress |
2020 |
US
0.2 |
— |
Columbia Gulf |
|
|
|
Cameron
Access |
2018 |
US
0.3 |
US
0.3 |
Gulf
XPress |
2018 |
US
0.6 |
US
0.2 |
Other2 |
2018-2020 |
US
0.3 |
— |
Mexico Natural
Gas Pipelines |
|
|
|
Sur de Texas3 |
2018 |
US
1.3 |
US
1.0 |
Villa de Reyes |
2018 |
US
0.8 |
US
0.5 |
Tula |
2019 |
US
0.7 |
US
0.5 |
Liquids
Pipelines |
|
|
|
White Spruce |
2019 |
0.2 |
— |
Energy |
|
|
|
Napanee |
2018 |
1.3 |
0.9 |
Bruce
Power – life extension4 |
up to 2020 |
0.9 |
0.3 |
|
|
20.1 |
6.8 |
Foreign
exchange impact on near-term projects5 |
|
2.6 |
1.3 |
Total near-term projects (billions of
Cdn$) |
|
22.7 |
8.1 |
1 Leach XPress was placed in service in January 2018.2 Reflects
our proportionate share of costs related to Portland Xpress and
various expansion projects.3 Our proportionate share.4 Amount
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 2020.5 Reflects U.S./Canada foreign
exchange rate of 1.25 at December 31, 2017.
Medium to longer-term projectsThe 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 applicable 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.
|
|
|
|
(unaudited – billions of $) |
Segment |
Estimated project cost |
Carrying value at December 31, 2017 |
|
|
|
|
Heartland and TC
Terminals1 |
Liquids
Pipelines |
0.9 |
0.1 |
Grand Rapids Phase
22 |
Liquids
Pipelines |
0.7 |
— |
Bruce Power–life
extension2 |
Energy |
5.3 |
— |
Keystone
projects |
|
|
|
Keystone
XL3 |
Liquids
Pipelines |
US
8.0 |
US
0.3 |
Keystone
Hardisty Terminal1,3 |
Liquids
Pipelines |
0.3 |
0.1 |
BC west coast
LNG-related
projects |
|
|
|
Coastal
GasLink |
Canadian
Natural Gas Pipelines |
4.8 |
0.4 |
NGTL System – Merrick |
Canadian Natural Gas Pipelines |
1.9 |
— |
|
|
21.9 |
0.9 |
Foreign
exchange impact on medium to longer-term projects4 |
|
2.0 |
0.1 |
Total medium to longer-term projects
(billions of Cdn$) |
|
23.9 |
1.0 |
1 Regulatory approvals have been obtained, additional commercial
support is being pursued.2 Our proportionate share.3 Carrying value
reflects amount remaining after impairment charge recorded in
2015.4 Reflects U.S./Canada foreign exchange rate of 1.25 at
December 31, 2017.
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). Certain costs previously reported in our
Corporate segment are now being reported within the business
segments to better align with how we measure our financial
performance. 2016 results have been adjusted to reflect this
change.
|
|
|
|
three months ended |
year ended |
|
December 31 |
December 31 |
(unaudited – millions of $) |
2017 |
2016 |
2017 |
2016 |
NGTL System |
274 |
|
255 |
|
996 |
|
968 |
|
Canadian Mainline |
269 |
|
305 |
|
1,043 |
|
1,105 |
|
Other Canadian
pipelines1 |
29 |
|
27 |
|
110 |
|
116 |
|
Business
development |
(3 |
) |
(3 |
) |
(5 |
) |
(7 |
) |
Comparable
EBITDA |
569 |
|
584 |
|
2,144 |
|
2,182 |
|
Depreciation and amortization |
(236 |
) |
(220 |
) |
(908 |
) |
(875 |
) |
Comparable EBIT and segmented earnings |
333 |
|
364 |
|
1,236 |
|
1,307 |
|
1 Includes results from Foothills, Ventures LP, Great Lakes
Canada, our share of equity income from our investment in TQM, and
general and administration costs related to our Canadian
Pipelines.
Canadian Natural Gas Pipelines segmented earnings decreased by
$31 million for the three months ended December 31, 2017 compared
to the same period in 2016 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. Changes in depreciation, financial charges and
income taxes also impact comparable EBITDA but do not have a
significant impact on net income as they are almost entirely
recovered in revenue on a flow-through basis.
NET INCOME - NGTL SYSTEM AND CANADIAN
MAINLINE
|
|
|
|
three months ended December 31 |
year ended December 31 |
(unaudited – millions of $) |
2017 |
2016 |
2017 |
2016 |
NGTL System |
91 |
85 |
352 |
318 |
Canadian
Mainline |
50 |
54 |
199 |
208 |
|
|
|
|
|
Net income for the NGTL System increased by $6 million for the
three months ended December 31, 2017 compared to the same period in
2016 mainly due to a higher average investment base, partially
offset by lower OM&A incentive earnings. The NGTL System
operated under the two-year 2016-2017 Revenue Requirement
Settlement which included an ROE of 10.1 per cent on 40 per cent
deemed equity and a mechanism for sharing variances between actual
and a fixed OM&A amount.
Canadian Mainline's net income decreased by $4 million for the
three months ended December 31, 2017 compared to the same period in
2016 primarily due to a lower average investment base and lower
incentive earnings. The Canadian Mainline is operating under the
NEB 2014 Decision which includes an approved ROE of 10.1 per cent
on a 40 per cent deemed equity with a possible range of achieved
outcomes between 8.7 per cent and 11.5 per cent. The decision also
includes an incentive mechanism that has both upside and downside
risk and a $20 million annual after-tax contribution from
TransCanada.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization increased by $16 million for the three months ended
December 31, 2017 compared to the same period in 2016 mainly due to
facilities that were placed in service for the NGTL System and
Canadian Mainline.
OPERATING STATISTICS - NGTL SYSTEM AND CANADIAN
MAINLINE
|
|
|
year ended December
31 |
NGTL System1 |
Canadian Mainline2 |
(unaudited) |
2017 |
2016 |
2017 |
2016 |
Average investment base
(millions of $) |
8,385 |
7,451 |
4,184 |
4,441 |
Delivery volumes
(Bcf): |
|
|
|
|
Total |
4,153 |
4,055 |
1,620 |
1,634 |
Average per day |
11.4 |
11.1 |
4.4 |
4.5 |
|
|
|
|
|
1 Field receipt volumes for the NGTL System for the year ended
December 31, 2017 were 4,224 Bcf (2016 – 4,117 Bcf). Average per
day was 11.6 Bcf (2016 – 11.3 Bcf).2 Canadian Mainline’s throughput
volumes represent physical deliveries to domestic and export
markets. Physical receipts originating at the Alberta border
and in Saskatchewan for the year ended December 31, 2017 were 1,019
Bcf (2016 – 1,055 Bcf). Average per day was 2.8 Bcf (2016 – 2.9
Bcf).
U.S. Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
equivalent GAAP measure). Certain costs previously reported in our
Corporate segment are now being reported within the business
segments to better align with how we measure our financial
performance. 2016 results have been adjusted to reflect this
change.
|
|
|
|
|
|
three months ended December 31 |
year ended December 31 |
(unaudited - millions of US$, unless otherwise noted) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Columbia Gas1 |
177 |
|
146 |
|
623 |
|
269 |
|
ANR |
99 |
|
88 |
|
400 |
|
321 |
|
TC PipeLines,
LP2,3 |
27 |
|
28 |
|
110 |
|
118 |
|
Midstream1 |
23 |
|
14 |
|
93 |
|
40 |
|
Columbia Gulf1 |
21 |
|
14 |
|
76 |
|
25 |
|
Great Lakes3,4 |
15 |
|
12 |
|
64 |
|
60 |
|
Other U.S.
pipelines1,2,3,5 |
30 |
|
28 |
|
108 |
|
74 |
|
Non-controlling
interests6 |
84 |
|
101 |
|
341 |
|
365 |
|
Business
development |
(1 |
) |
(1 |
) |
(2 |
) |
(3 |
) |
Comparable
EBITDA |
475 |
|
430 |
|
1,813 |
|
1,269 |
|
Depreciation and amortization |
(113 |
) |
(118 |
) |
(453 |
) |
(322 |
) |
Comparable
EBIT |
362 |
|
312 |
|
1,360 |
|
947 |
|
Foreign
exchange impact |
99 |
|
102 |
|
410 |
|
310 |
|
Comparable
EBIT (Cdn$) |
461 |
|
414 |
|
1,770 |
|
1,257 |
|
Specific items: |
|
|
|
|
Integration and acquisition related costs – Columbia |
— |
|
(11 |
) |
(10 |
) |
(63 |
) |
TC Offshore loss on sale |
— |
|
— |
|
— |
|
(4 |
) |
Segmented earnings (Cdn$) |
461 |
|
403 |
|
1,760 |
|
1,190 |
|
1 We completed the acquisition of Columbia on July 1, 2016.
Results reflect our effective ownership in these assets from that
date.2 Results from Northern Border and Iroquois reflect our share
of equity income from these investments. We acquired additional
interests in Iroquois of 4.87 per cent on March 31, 2016 and 0.65
per cent on May 1, 2016. TC PipeLines, LP acquired 49.34 per cent
of our 50 per cent interest in Iroquois on June 1, 2017. On January
1, 2016, we sold a 49.9 per cent direct interest in PNGTS to TC
PipeLines, LP and its remaining 11.81 per cent interest to TC
PipeLines, LP on June 1, 2017.3 TC PipeLines, LP periodically
conducts at-the-market equity issuances which decrease our
ownership in TC PipeLines, LP. The following shows our ownership
interest in TC PipeLines, LP and our effective ownership interest
of Great Lakes and PNGTS through our ownership interest in TC
PipeLines, LP at the date presented.
|
|
|
Effective ownership percentage as
of |
|
December 31, 2017 |
December 31, 2016 |
TC PipeLines, LP |
25.7 |
26.8 |
Effective ownership
through TC PipeLines, LP: |
|
|
Great
Lakes |
11.9 |
12.5 |
PNGTS |
15.9 |
13.4 |
4 Represents our 53.6 per cent direct interest in Great Lakes.
The remaining 46.4 per cent is held by TC PipeLines, LP.5 Includes
our direct ownership in Iroquois and PNGTS (until June 1, 2017),
our effective ownership in Millennium and Hardy Storage, and
general and administrative costs related to U.S. natural gas
assets. 6 Comparable EBITDA for the portions of TC PipeLines,
LP, PNGTS (until June 1, 2017) and CPPL that we do not own.
Effective February 17, 2017, we acquired the remaining
publicly held units of CPPL.
U.S. Natural Gas Pipelines segmented earnings increased by $58
million for the three months ended December 31, 2017 compared to
the same period in 2016. Segmented earnings for the three months
ended December 31, 2016 included pre-tax costs of $11 million
mainly related to retention and severance expenses resulting from
the Columbia acquisition. These amounts have been excluded from our
calculation of comparable EBIT.
Earnings from our U.S. Natural Gas Pipelines operations, which
include Columbia effective July 1, 2016, 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. Transmission and storage
revenues are generally higher in winter months due to increased
seasonal demand for our services.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by
US$45 million for the three months ended December 31, 2017 compared
to the same period in 2016. This was primarily due to lower
operating costs including synergies achieved from the Columbia
acquisition.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization decreased by US$5 million for the three months ended
December 31, 2017 compared to the same period in 2016 primarily due
to fair value adjustments related to our Midstream assets recorded
in fourth quarter 2016.
Mexico Natural Gas Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
equivalent GAAP measure). Certain costs previously reported in our
Corporate segment are now being reported within the business
segments to better align with how we measure our financial
performance. 2016 results have been adjusted to reflect this
change.
|
|
|
|
|
|
three months ended December
31 |
year ended December 31 |
(unaudited – millions of US$, unless otherwise noted) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Topolobampo |
38 |
|
41 |
|
157 |
|
81 |
|
Tamazunchale |
27 |
|
26 |
|
112 |
|
105 |
|
Guadalajara |
17 |
|
18 |
|
68 |
|
67 |
|
Mazatlán |
16 |
|
5 |
|
65 |
|
5 |
|
Sur de Texas1 |
(6 |
) |
— |
|
8 |
|
— |
|
Other |
(1 |
) |
(3 |
) |
(11 |
) |
(3 |
) |
Business
development |
— |
|
(1 |
) |
— |
|
(5 |
) |
Comparable
EBITDA |
91 |
|
86 |
|
399 |
|
250 |
|
Depreciation and amortization |
(18 |
) |
(12 |
) |
(72 |
) |
(35 |
) |
Comparable
EBIT |
73 |
|
74 |
|
327 |
|
215 |
|
Foreign
exchange impact |
20 |
|
29 |
|
99 |
|
72 |
|
Comparable EBIT and segmented earnings (Cdn$) |
93 |
|
103 |
|
426 |
|
287 |
|
1 Represents our 60 per cent equity interest in a joint venture
with IEnova to build, own and operate the Sur de Texas
pipeline.
Mexico Natural Gas Pipelines segmented earnings decreased by $10
million for the three months ended December 31, 2017 compared to
the same period in 2016 and are equivalent to comparable EBIT.
Aside from the commercial factors outlined below, a weaker U.S.
dollar had a negative impact on the Canadian dollar equivalent
segmented earnings from our Mexico operations.
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.
Comparable EBITDA for Mexico Natural Gas Pipelines increased by
US$5 million for the three months December 31, 2017 compared to the
same period in 2016 and was the net effect of:
- incremental earnings from Mazatlán beginning December 2016
- equity earnings from our investment in the Sur de Texas
pipeline which records AFUDC during construction, net of interest
expense on an inter-affiliate loan from TransCanada. The
inter-affiliate loan interest is fully offset in interest income
and other in the Corporate segment.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization increased by US$6 million for the three months ended
December 31, 2017 compared to the same period in 2016 primarily due
to the commencement of depreciation on Mazatlán.
Liquids Pipelines
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented earnings (the
equivalent GAAP measure). Certain costs previously reported in our
Corporate segment are now being reported within the business
segments to better align with how we measure our financial
performance. 2016 results have been adjusted to reflect this
change.
|
|
|
|
|
|
three months ended December 31 |
year ended December 31 |
(unaudited – millions of $) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Keystone Pipeline
System |
346 |
|
296 |
|
1,283 |
|
1,155 |
|
Intra-Alberta
pipelines |
29 |
|
— |
|
33 |
|
— |
|
Other
services1 |
26 |
|
6 |
|
32 |
|
(3 |
) |
Comparable
EBITDA |
401 |
|
302 |
|
1,348 |
|
1,152 |
|
Depreciation and amortization |
(81 |
) |
(78 |
) |
(309 |
) |
(292 |
) |
Comparable
EBIT |
320 |
|
224 |
|
1,039 |
|
860 |
|
Specific items: |
|
|
|
|
|
|
|
|
Energy
East impairment charge |
(1,256 |
) |
— |
|
(1,256 |
) |
— |
|
Keystone
XL asset costs |
(11 |
) |
(15 |
) |
(34 |
) |
(52 |
) |
Risk management activities |
15 |
|
4 |
|
— |
|
(2 |
) |
Segmented
(losses)/earnings |
(932 |
) |
213 |
|
(251 |
) |
806 |
|
|
|
|
|
|
|
|
|
|
Comparable EBIT
denominated as follows: |
|
|
|
|
|
|
|
|
Canadian dollars |
80 |
|
63 |
|
255 |
|
223 |
|
U.S. dollars |
188 |
|
122 |
|
604 |
|
482 |
|
Foreign
exchange impact |
52 |
|
39 |
|
180 |
|
155 |
|
|
320 |
|
224 |
|
1,039 |
|
860 |
|
1 Includes primarily liquids marketing and business development
activities.
Liquids Pipelines segmented earnings decreased by $1,145 million
for the three months ended December 31, 2017 compared to the same
period in 2016. This was primarily the net effect of a $1,256
million pre-tax impairment charge for the Energy East pipeline and
related projects, $11 million (2016 - $15 million) of pre-tax costs
related to Keystone XL for the maintenance and liquidation of
project assets which were expensed pending further advancement of
the project, and unrealized gains from changes in the fair value of
derivatives related to our liquids marketing business. These
amounts have been excluded from our calculation of comparable
EBIT.
Keystone Pipeline System earnings are generated primarily by
providing pipeline capacity to shippers for fixed monthly payments
that are not linked to actual throughput volumes. Uncontracted
capacity is offered to the market on a spot basis and provides
opportunities to generate incremental earnings.
Comparable EBITDA for Liquids Pipelines increased by $99 million
for the three months ended December 31, 2017 compared to the same
period in 2016 and was the net effect of:
- higher uncontracted volumes on the Keystone Pipeline
System
- new intra-Alberta pipelines, Grand Rapids and Northern Courier,
which began operations in the second half of 2017
- a higher contribution from the liquids marketing business
- higher business development activities, including advancement
of Keystone XL
- a weaker U.S. dollar which had a negative impact on the
Canadian dollar equivalent comparable earnings from our U.S.
operations.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization increased by $3 million for the three months ended
December 31, 2017 compared to the same period in 2016 as a result
of the 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). Certain costs previously reported in our
Corporate segment are now being reported within the business
segments to better align with how we measure our financial
performance. 2016 results have been adjusted to reflect this
change.
|
|
|
|
|
|
three months ended December 31 |
year ended December 31 |
(unaudited – millions of $) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Canadian
Power |
|
|
|
|
Western Power1 |
23 |
|
26 |
|
100 |
|
74 |
|
Eastern Power |
92 |
|
82 |
|
344 |
|
349 |
|
Bruce
Power |
120 |
|
83 |
|
434 |
|
293 |
|
Canadian Power
- comparable EBITDA1,2 |
235 |
|
191 |
|
878 |
|
716 |
|
Depreciation and amortization |
(30 |
) |
(26 |
) |
(138 |
) |
(145 |
) |
Canadian Power - comparable EBIT1,2 |
205 |
|
165 |
|
740 |
|
571 |
|
U.S. Power -
comparable EBITDA3 (US$) |
(8 |
) |
73 |
|
100 |
|
394 |
|
Depreciation and amortization4 |
— |
|
(11 |
) |
— |
|
(109 |
) |
U.S. Power -
comparable EBIT |
(8 |
) |
62 |
|
100 |
|
285 |
|
Foreign
exchange impact |
(4 |
) |
20 |
|
30 |
|
92 |
|
U.S. Power - comparable EBIT (Cdn$) |
(12 |
) |
82 |
|
130 |
|
377 |
|
Natural Gas
Storage and other operations - comparable EBITDA |
15 |
|
20 |
|
55 |
|
58 |
|
Depreciation and amortization |
(3 |
) |
(3 |
) |
(13 |
) |
(12 |
) |
Natural Gas
Storage and other operations - comparable EBIT |
12 |
|
17 |
|
42 |
|
46 |
|
Business Development and other costs - comparable EBITDA
and EBIT5 |
(24 |
) |
(4 |
) |
(33 |
) |
(15 |
) |
Energy -
comparable EBIT |
181 |
|
260 |
|
879 |
|
979 |
|
Specific items: |
|
|
|
|
Gain on
sale of Ontario solar assets |
127 |
|
— |
|
127 |
|
— |
|
Gain/(loss) on sales of U.S. Northeast power assets |
15 |
|
(839 |
) |
484 |
|
(844 |
) |
Ravenswood goodwill impairment |
— |
|
— |
|
— |
|
(1,085 |
) |
Alberta
PPA terminations and settlement |
— |
|
(92 |
) |
— |
|
(332 |
) |
Risk management activities |
149 |
|
97 |
|
62 |
|
125 |
|
Segmented earnings/(losses) |
472 |
|
(574 |
) |
1,552 |
|
(1,157 |
) |
|
|
|
|
|
|
|
|
|
1 Included losses from the Alberta PPAs up to March 2016 when
the PPAs were terminated.2 Includes our share of equity income from
our investments in Portlands Energy and Bruce Power.3 TC Hydro
earnings included up to April 19, 2017 sale date; Ravenswood,
Ironwood, Ocean State Power and Kibby Wind earnings included up to
June 2, 2017 sale date.4 Depreciation of U.S. Northeast power
assets ceased effective November 2016 when classified as assets
held for sale.5 Includes a $21 million impairment charge in fourth
quarter 2017 of obsolete equipment.
Energy segmented earnings increased by $1,046 million for the
three months ended December 31, 2017 compared to the same period in
2016 and included the following specific items:
- a gain in 2017 of $127 million before tax related to the sale
of our Ontario solar assets
- a net gain in 2017 of $15 million before tax related to the
monetization of our U.S. Northeast power assets which consisted
primarily of insurance recoveries for a portion of repair costs
incurred during an unplanned outage at Ravenswood prior to its
sale
- in 2016, a loss of $839 million before tax related to the sale
of the U.S. Northeast power assets which included an $829 million
pre-tax loss on the thermal and wind package and $10 million of
pre-tax disposition costs
- in 2016, a $92 million before tax loss on the transfer of
environmental credits to the Balancing Pool upon final settlement
of the Alberta PPA terminations
- unrealized gains and losses in both years from changes in the
fair value of derivatives used to reduce our exposure to certain
commodity price risks
The remainder of the Energy segmented earnings are equivalent to
comparable EBIT along with comparable EBITDA.
CANADIAN POWER
Western PowerWestern Power
comparable EBITDA was consistent for the three months ended
December 31, 2017 compared to the same period in 2016.
Eastern PowerEastern Power comparable EBITDA
increased by $10 million for the three months ended December 31,
2017 compared to the same period in 2016 mainly due to higher
earnings from our wind facilities.
DEPRECIATION AND AMORTIZATIONDepreciation and
amortization increased by $4 million primarily due to a 2016
adjustment related to the expected useful life of our cogeneration
assets, partially offset by the cessation of depreciation on our
Ontario solar assets upon classification as held for sale in
October 2017.
Bruce PowerBruce Power results reflect our
proportionate share. The following is our proportionate share of
the components of comparable EBITDA and comparable EBIT.
|
|
|
|
three months ended December 31 |
year ended December 31 |
(unaudited – millions of $, unless otherwise noted) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
Equity income included
in comparable EBITDA and EBIT comprised of: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
414 |
|
|
382 |
|
|
1,626 |
|
|
1,491 |
|
Operating
expenses |
|
(208 |
) |
|
(212 |
) |
|
(846 |
) |
|
(870 |
) |
Depreciation and other |
|
(86 |
) |
|
(87 |
) |
|
(346 |
) |
|
(328 |
) |
Comparable EBITDA and comparable EBIT1 |
|
120 |
|
|
83 |
|
|
434 |
|
|
293 |
|
Bruce
Power – other information |
|
|
|
|
Plant
availability2 |
|
92 |
% |
|
85 |
% |
|
90 |
% |
|
83 |
% |
Planned outage
days |
|
43 |
|
|
80 |
|
|
221 |
|
|
415 |
|
Unplanned outage
days |
|
10 |
|
|
27 |
|
|
49 |
|
|
76 |
|
Sales volumes
(GWh)1 |
|
6,275 |
|
|
5,758 |
|
|
24,368 |
|
|
22,178 |
|
Realized
sales price per MWh3 |
$67 |
|
$69 |
|
$67 |
|
$68 |
|
|
|
|
|
|
1 Represents our 48.4 per cent (2016 - 48.5 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.
Bruce Power comparable EBITDA increased by $37 million for the
three months ended December 31, 2017 compared to the same period in
2016 mainly due to higher volumes resulting from fewer outage
days.
U.S. POWERIn second quarter 2017, we completed
the sales of our U.S. Power generation assets and initiated the
wind down of our U.S. power marketing operations.
NATURAL GAS STORAGE AND OTHER OPERATINGNatural
Gas Storage comparable EBITDA decreased by $5 million for the three
months ended December 31, 2017 compared to the same period in 2016
mainly due to lower realized natural gas storage price spreads.
Corporate
The following is a reconciliation of comparable EBITDA and
comparable EBIT (our non-GAAP measures) to segmented
earnings/(losses) (the equivalent GAAP measure). Certain costs
previously reported in our Corporate segment are now being reported
within the business segments to better align with how we measure
our financial performance. 2016 results have been adjusted to
reflect this change.
|
|
|
|
three months endedDecember 31 |
year endedDecember 31 |
(unaudited - millions of $) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Comparable
EBITDA and EBIT |
(1 |
) |
11 |
|
(21 |
) |
18 |
|
Specific items: |
|
|
|
|
Integration and acquisition related costs – Columbia |
— |
|
(36 |
) |
(81 |
) |
(116 |
) |
Foreign
exchange gain – inter-affiliate loan1 |
64 |
|
— |
|
63 |
|
— |
|
Restructuring costs |
— |
|
(8 |
) |
— |
|
(22 |
) |
Segmented earnings/(losses) |
63 |
|
(33 |
) |
(39 |
) |
(120 |
) |
|
|
|
|
|
1 Reported in Income from equity investments on the Condensed
consolidated statement of income.
Corporate segmented earnings were $63 million for the three
months ended December 31, 2017 compared to a loss of $33 million
for the same period in 2016 and included the following specific
items that have been excluded from comparable EBIT:
- in 2017, a foreign exchange gain on a peso-denominated
inter-affiliate loan to the Sur de Texas project for our
proportionate share of the project's financing. There is a
corresponding foreign exchange loss included in interest income and
other on the inter-affiliate loan receivable which fully offsets
this gain
- in 2016, pre-tax integration and acquisition costs associated
with the acquisition of Columbia and restructuring costs.
Comparable EBITDA decreased by $12 million for the three months
ended December 31, 2017 compared to the same period in 2016
primarily due to increased general and administrative costs.
OTHER INCOME STATEMENT ITEMS
Interest expense
|
|
|
|
|
|
three months ended December 31 |
year ended December 31 |
(unaudited - millions of $) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Interest on long-term debt and junior
subordinated notes |
|
|
|
|
Canadian
dollar-denominated |
(138 |
) |
(109 |
) |
(494 |
) |
(452 |
) |
U.S.
dollar-denominated |
(315 |
) |
(316 |
) |
(1,269 |
) |
(1,127 |
) |
Foreign
exchange impact |
(86 |
) |
(106 |
) |
(379 |
) |
(366 |
) |
|
(539 |
) |
(531 |
) |
(2,142 |
) |
(1,945 |
) |
Other interest and
amortization expense |
(25 |
) |
(54 |
) |
(99 |
) |
(114 |
) |
Capitalized interest |
23 |
|
43 |
|
173 |
|
176 |
|
Interest expense included in comparable
earnings |
(541 |
) |
(542 |
) |
(2,068 |
) |
(1,883 |
) |
Specific items: |
|
|
|
|
|
|
|
|
Integration and acquisition related costs – Columbia |
— |
|
— |
|
— |
|
(115 |
) |
Risk management activities |
— |
|
— |
|
(1 |
) |
— |
|
Interest expense |
(541 |
) |
(542 |
) |
(2,069 |
) |
(1,998 |
) |
|
|
|
|
|
|
|
|
|
Interest expense was consistent for the three months ended
December 31, 2017 compared to the same period in 2016 and reflects
the net effect of:
- Canadian and U.S. dollar-denominated long-term debt and junior
subordinated note issuances in 2017, net of maturities
- retirement of the Columbia acquisition bridge facilities in
June 2017
- the impact of a weaker U.S. dollar in translating U.S.
dollar-denominated interest
- lower capitalized interest on Liquids Pipelines projects placed
in-service in 2017.
Allowance for funds used during
construction
|
|
|
|
three months ended December 31 |
year ended December 31 |
(unaudited – millions of $) |
2017 |
2016 |
2017 |
2016 |
Canadian
dollar-denominated |
25 |
48 |
174 |
181 |
U.S.
dollar-denominated |
91 |
32 |
259 |
181 |
Foreign
exchange impact |
24 |
17 |
74 |
57 |
Allowance for funds used during construction |
140 |
97 |
507 |
419 |
|
|
|
|
|
AFUDC increased by $43 million for the three months ended
December 31, 2017 compared to the same period in 2016 primarily due
to to continued investment in and higher rates on projects acquired
as part of the 2016 Columbia acquisition, as well as continued
investment in Mexico projects, partially offset by the commercial
in-service of Topolobampo, the completion of Mazatlán construction
and our decision not to proceed with the Energy East Pipeline.
Interest income and other
|
|
|
(unaudited - millions of $) |
three months ended December
31 |
year ended December 31 |
2017 |
|
2016 |
2017 |
|
2016 |
Interest income and other included in
comparable earnings |
56 |
|
8 |
159 |
|
71 |
Specific items: |
|
|
|
|
|
|
Integration and acquisition related costs – Columbia |
— |
|
— |
— |
|
6 |
Foreign
exchange loss – inter-affiliate loan |
(64) |
|
— |
(63) |
|
— |
Risk management activities |
(1) |
|
(23) |
88 |
|
26 |
Interest income and other |
(9) |
|
(15) |
184 |
|
103 |
|
|
|
|
|
|
|
Interest income and other increased by $6 million for the three
months ended December 31, 2017 compared to the same period in 2016
due to the net effect of:
- higher interest income along with a $64 million 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. Both currency-related amounts are excluded
from comparable earnings
- lower unrealized losses on risk management activities in 2017
compared to 2016. These amounts have been excluded from comparable
earnings
- foreign exchange impact on the translation of foreign currency
denominated working capital balances.
Income tax expense
|
|
|
|
three months ended December
31 |
year ended December 31 |
(unaudited - millions of $) |
2017 |
|
2016 |
|
|
2017 |
|
|
2016 |
|
Income tax
expense included in comparable earnings |
(234 |
) |
(211 |
) |
(839 |
) |
(841 |
) |
Specific items: |
|
|
|
|
U.S. Tax
Reform adjustment |
804 |
|
— |
|
804 |
|
— |
|
Energy
East impairment charge |
302 |
|
— |
|
302 |
|
— |
|
Net
loss/(gain) on sales of U.S. Northeast power assets |
49 |
|
(31 |
) |
(177 |
) |
(29 |
) |
Gain on
sale of Ontario solar assets |
9 |
|
— |
|
9 |
|
— |
|
Keystone
XL asset costs |
2 |
|
(3 |
) |
6 |
|
10 |
|
Integration and acquisition related costs – Columbia |
— |
|
(22 |
) |
22 |
|
10 |
|
Keystone
XL income tax recoveries |
— |
|
— |
|
7 |
|
28 |
|
Ravenswood goodwill impairment |
— |
|
— |
|
— |
|
429 |
|
Alberta
PPA terminations |
— |
|
24 |
|
— |
|
88 |
|
Restructuring costs |
— |
|
2 |
|
— |
|
6 |
|
TC
Offshore loss on sale |
— |
|
— |
|
— |
|
1 |
|
Risk management activities |
(62 |
) |
(33 |
) |
(45 |
) |
(54 |
) |
Income tax recovery/(expense) |
870 |
|
(274 |
) |
89 |
|
(352 |
) |
|
|
|
|
|
|
|
|
|
Income tax expense included in comparable earnings increased by
$23 million for the three months ended December 31, 2017 compared
to the same period in 2016 primarily due to an increase in
comparable earnings, changes in the proportion of income earned
between Canadian and foreign jurisdictions and changes in
flow-through taxes in regulatory operations.
Net income attributable to non-controlling
interests
|
|
|
|
|
|
three months ended |
year ended |
|
December 31 |
December 31 |
(unaudited - millions of $) |
2017 |
|
2016 |
|
2017 |
2016 |
|
Net income
attributable to non-controlling interests |
|
|
|
|
included in
comparable earnings |
(49 |
) |
(70 |
) |
(238 |
) |
(257 |
) |
Specific items: |
|
|
|
|
Acquisition related costs - Columbia |
— |
|
2 |
|
— |
|
5 |
|
Net income attributable to non-controlling
interests |
(49 |
) |
(68 |
) |
(238 |
) |
(252 |
) |
|
|
|
|
|
|
|
|
|
Net income attributable to non-controlling interests decreased
by $19 million, and $21 million as included in comparable earnings,
for the three months ended December 31, 2017 compared to the same
period in 2016 primarily due to the acquisition of the remaining
outstanding publicly held common units of CPPL in February
2017.
Preferred share dividends
|
|
|
|
|
|
three months ended |
year ended |
|
December 31 |
December 31 |
(unaudited - millions of $) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Preferred share dividends |
(40 |
) |
(32 |
) |
(160 |
) |
(109 |
) |
Preferred share dividends increased by $8 million for the three
months ended December 31, 2017 compared to the same period in 2016
primarily due to the issuance of Series 15 preferred shares in
November 2016.
|
|
|
|
|
|
COMPARABLE
DISTRIBUTABLE CASH FLOW |
|
|
|
|
|
|
|
|
|
|
|
|
|
three months ended |
year ended |
|
December 31 |
December 31 |
(unaudited - millions of $, except per share amounts) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
Net cash provided by
operations |
|
1,390 |
|
|
1,575 |
|
|
5,230 |
|
|
5,069 |
|
Increase/(decrease) in operating working capital |
|
49 |
|
|
(220 |
) |
|
273 |
|
|
(248 |
) |
Funds generated from
operations1 |
|
1,439 |
|
|
1,355 |
|
|
5,503 |
|
|
4,821 |
|
Specific items: |
|
|
|
|
|
Integration and acquisition related costs - Columbia |
|
— |
|
|
45 |
|
|
84 |
|
|
283 |
|
Keystone
XL asset costs |
|
11 |
|
|
15 |
|
|
34 |
|
|
52 |
|
U.S. Northeast power disposition costs |
|
— |
|
|
10 |
|
|
20 |
|
|
15 |
|
Comparable
funds generated from operations1 |
|
1,450 |
|
|
1,425 |
|
|
5,641 |
|
|
5,171 |
|
Dividends on preferred
shares |
|
(39 |
) |
|
(26 |
) |
|
(155 |
) |
|
(100 |
) |
Distributions paid to
non-controlling interests |
|
(68 |
) |
|
(78 |
) |
|
(283 |
) |
|
(279 |
) |
Maintenance capital
expenditures including equity |
|
|
|
|
|
investments |
|
|
|
|
|
-
Recoverable in future tolls |
|
(541 |
) |
|
(323 |
) |
|
(1,364 |
) |
|
(941 |
) |
- Other |
|
(75 |
) |
|
(70 |
) |
|
(240 |
) |
|
(310 |
) |
Comparable
distributable cash flow1 |
|
|
|
|
|
-
Reflecting all maintenance capital expenditures |
|
727 |
|
|
928 |
|
|
3,599 |
|
|
3,541 |
|
-
Reflecting only non-recoverable maintenance capital |
|
|
|
|
|
expenditures |
|
1,268 |
|
|
1,251 |
|
|
4,963 |
|
|
4,482 |
|
Comparable
distributable cash flow per common share1 |
|
|
|
|
|
-
Reflecting all maintenance capital expenditures |
$0.83 |
|
$1.12 |
|
$4.13 |
|
$4.67 |
|
-
Reflecting only non-recoverable maintenance capital |
|
|
|
|
|
expenditures |
$1.45 |
|
$1.50 |
|
$5.69 |
|
$5.91 |
|
1 See the non-GAAP measures section in 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.
Comparable funds generated from
operationsComparable funds generated from
operations, a non-GAAP measure, increased $25 million for the three
months ended December 31, 2017 compared to the same period in 2016
primarily due to higher comparable earnings.
Comparable distributable cash
flowComparable distributable cash flow, a
non-GAAP measure, helps us assess the cash available to common
shareholders before capital allocation.
The decrease in comparable distributable cash flow reflecting
all maintenance capital expenditures for the three months ended
December 31, 2017 compared to the same period in 2016 was primarily
driven by the increase in recoverable maintenance capital
expenditures in Canadian and U.S. natural gas pipelines. Comparable
distributable cash flow reflecting only non-recoverable maintenance
capital expenditures is consistent with fourth quarter 2016.
Comparable distributable cash flow per common share for the three
months ended December 31, 2017 also includes the dilutive effect of
common shares issued in fourth quarter 2016 and 2017.
Although we deduct maintenance capital expenditures in
determining comparable distributable cash flow, we have the ability
to recover the majority of these costs in Canadian Natural Gas
Pipelines, U.S. Natural Gas Pipelines and Liquids Pipelines.
Canadian natural gas pipelines maintenance capital expenditures are
reflected in rate bases, on which we earn a regulated return and
subsequently recover in tolls. The majority of our U.S. natural gas
pipelines can recover maintenance capital through tolls under
current rate settlements, or have the ability to recover
maintenance capital through tolls established in future rate cases
or settlements. Tolling arrangements in Liquids Pipelines provide
for recovery of maintenance capital.
The following provides a breakdown of maintenance capital
expenditures:
|
|
|
|
three months ended |
year ended |
|
December 31 |
December 31 |
(unaudited - millions of $) |
2017 |
2016 |
2017 |
2016 |
Canadian
Natural Gas Pipelines |
301 |
133 |
601 |
323 |
U.S.
Natural Gas Pipelines |
237 |
182 |
749 |
586 |
Liquids
Pipelines |
8 |
8 |
19 |
32 |
Other |
70 |
70 |
235 |
310 |
Maintenance capital expenditures including
equity |
|
|
|
|
investments |
616 |
393 |
1,604 |
1,251 |
|
|
|
|
|
Reconciliation of non-GAAP measures
|
|
|
|
three months ended December
31 |
year ended December 31 |
(unaudited - millions of $) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Comparable
EBITDA |
|
|
|
|
Canadian Natural Gas
Pipelines |
569 |
|
584 |
|
2,144 |
|
2,182 |
|
U.S. Natural Gas
Pipelines |
604 |
|
570 |
|
2,357 |
|
1,682 |
|
Mexico Natural Gas
Pipelines |
116 |
|
119 |
|
519 |
|
332 |
|
Liquids Pipelines |
401 |
|
302 |
|
1,348 |
|
1,152 |
|
Energy |
214 |
|
304 |
|
1,030 |
|
1,281 |
|
Corporate |
(1 |
) |
11 |
|
(21 |
) |
18 |
|
Comparable
EBITDA |
1,903 |
|
1,890 |
|
7,377 |
|
6,647 |
|
Depreciation and amortization |
(516 |
) |
(514 |
) |
(2,048 |
) |
(1,939 |
) |
Comparable
EBIT |
1,387 |
|
1,376 |
|
5,329 |
|
4,708 |
|
Specific items: |
|
|
|
|
Energy
East impairment charge |
(1,256 |
) |
— |
|
(1,256 |
) |
— |
|
Integration and acquisition related costs – Columbia |
— |
|
(47 |
) |
(91 |
) |
(179 |
) |
Keystone
XL asset costs |
(11 |
) |
(15 |
) |
(34 |
) |
(52 |
) |
Net
gain/(loss) on sales of U.S. Northeast power assets |
15 |
|
(839 |
) |
484 |
|
(844 |
) |
Gain on
sale of Ontario solar assets |
127 |
|
— |
|
127 |
|
— |
|
Foreign
exchange gain – inter-affiliate loan |
64 |
|
— |
|
63 |
|
— |
|
Ravenswood goodwill impairment |
— |
|
— |
|
— |
|
(1,085 |
) |
Alberta
PPA terminations and settlement |
— |
|
(92 |
) |
— |
|
(332 |
) |
Restructuring costs |
— |
|
(8 |
) |
— |
|
(22 |
) |
TC
Offshore loss on sale |
— |
|
— |
|
— |
|
(4 |
) |
Risk management activities |
164 |
|
101 |
|
62 |
|
123 |
|
Segmented earnings |
490 |
|
476 |
|
4,684 |
|
2,313 |
|
|
|
|
|
|
|
|
|
|
Condensed consolidated statement of income
|
|
|
|
three months ended December
31 |
year ended December 31 |
(unaudited - millions of Canadian $, except per shareamounts) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Revenues |
|
|
|
|
|
|
Canadian Natural Gas
Pipelines |
|
968 |
|
|
1,005 |
|
|
3,693 |
|
|
3,682 |
|
U.S. Natural Gas
Pipelines |
|
900 |
|
|
941 |
|
|
3,584 |
|
|
2,526 |
|
Mexico Natural Gas
Pipelines |
|
138 |
|
|
129 |
|
|
570 |
|
|
378 |
|
Liquids Pipelines |
|
599 |
|
|
463 |
|
|
2,009 |
|
|
1,755 |
|
Energy |
|
1,012 |
|
|
1,097 |
|
|
3,593 |
|
|
4,206 |
|
|
|
3,617 |
|
|
3,635 |
|
|
13,449 |
|
|
12,547 |
|
Income from
Equity Investments |
|
246 |
|
|
159 |
|
|
773 |
|
|
514 |
|
Operating and
Other Expenses |
|
|
|
|
Plant operating costs
and other |
|
944 |
|
|
1,189 |
|
|
3,906 |
|
|
3,861 |
|
Commodity purchases
resold |
|
671 |
|
|
544 |
|
|
2,382 |
|
|
2,172 |
|
Property taxes |
|
127 |
|
|
150 |
|
|
569 |
|
|
555 |
|
Depreciation and
amortization |
|
516 |
|
|
514 |
|
|
2,055 |
|
|
1,939 |
|
Goodwill
and other asset impairment charges |
|
1,257 |
|
|
92 |
|
|
1,257 |
|
|
1,388 |
|
|
|
3,515 |
|
|
2,489 |
|
|
10,169 |
|
|
9,915 |
|
Gain/(Loss) on
Assets Held for Sale/Sold |
|
142 |
|
|
(829 |
) |
|
631 |
|
|
(833 |
) |
Financial
Charges |
|
|
|
|
Interest expense |
|
541 |
|
|
542 |
|
|
2,069 |
|
|
1,998 |
|
Allowance for funds
used during construction |
|
(140 |
) |
|
(97 |
) |
|
(507 |
) |
|
(419 |
) |
Interest
income and other |
|
9 |
|
|
15 |
|
|
(184 |
) |
|
(103 |
) |
|
|
410 |
|
|
460 |
|
|
1,378 |
|
|
1,476 |
|
Income before Income Taxes |
|
80 |
|
|
16 |
|
|
3,306 |
|
|
837 |
|
Income Tax
(Recovery)/Expense |
|
|
|
|
Current |
|
21 |
|
|
53 |
|
|
149 |
|
|
156 |
|
Deferred |
|
(87 |
) |
|
221 |
|
|
566 |
|
|
196 |
|
Deferred
- U.S. Tax Reform |
|
(804 |
) |
|
— |
|
|
(804 |
) |
|
— |
|
|
|
(870 |
) |
|
274 |
|
|
(89 |
) |
|
352 |
|
Net
Income/(Loss) |
|
950 |
|
|
(258 |
) |
|
3,395 |
|
|
485 |
|
Net
income attributable to non-controlling interests |
|
49 |
|
|
68 |
|
|
238 |
|
|
252 |
|
Net
Income/(Loss)Attributable to Controlling Interests |
|
901 |
|
|
(326 |
) |
|
3,157 |
|
|
233 |
|
Preferred
share dividends |
|
40 |
|
|
32 |
|
|
160 |
|
|
109 |
|
Net Income/(Loss) Attributable to Common
Shares |
|
861 |
|
|
(358 |
) |
|
2,997 |
|
|
124 |
|
Net
Income/(Loss) per Common Share |
|
|
|
|
Basic |
$0.98 |
|
|
($0.43 |
) |
$3.44 |
|
$0.16 |
|
Diluted |
$0.98 |
|
|
($0.43 |
) |
$3.43 |
|
$0.16 |
|
Dividends Declared per Common Share |
$0.625 |
|
$0.565 |
|
$2.50 |
|
$2.26 |
|
Weighted Average Number of Common
Shares (millions) |
|
|
|
|
Basic |
|
877 |
|
|
832 |
|
|
872 |
|
|
759 |
|
Diluted |
|
879 |
|
|
833 |
|
|
874 |
|
|
760 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensed consolidated statement of cash
flows
|
|
|
|
three months ended December
31 |
year ended December 31 |
(unaudited - millions of Canadian $) |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
Cash Generated
from Operations |
|
|
|
|
Net income/(loss) |
950 |
|
(258 |
) |
3,395 |
|
485 |
|
Depreciation and
amortization |
516 |
|
514 |
|
2,055 |
|
1,939 |
|
Goodwill and other
asset impairment charges |
1,257 |
|
92 |
|
1,257 |
|
1,388 |
|
Deferred income
taxes |
(87 |
) |
221 |
|
566 |
|
196 |
|
Deferred income taxes -
U.S. Tax Reform |
(804 |
) |
— |
|
(804 |
) |
— |
|
Income from equity
investments |
(246 |
) |
(159 |
) |
(773 |
) |
(514 |
) |
Distributions received
from operating activities of equity investments |
227 |
|
219 |
|
970 |
|
844 |
|
Employee
post-retirement benefits funding, net of expense |
— |
|
2 |
|
(64 |
) |
(3 |
) |
(Gain)/loss on assets
held for sale/sold |
(142 |
) |
829 |
|
(631 |
) |
833 |
|
Equity allowance for
funds used during construction |
(113 |
) |
(58 |
) |
(362 |
) |
(253 |
) |
Unrealized gains on
financial instruments |
(163 |
) |
(78 |
) |
(149 |
) |
(149 |
) |
Other |
44 |
|
31 |
|
43 |
|
55 |
|
(Increase)/decrease in operating working capital |
(49 |
) |
220 |
|
(273 |
) |
248 |
|
Net cash
provided by operations |
1,390 |
|
1,575 |
|
5,230 |
|
5,069 |
|
Investing
Activities |
|
|
|
|
Capital
expenditures |
(2,000 |
) |
(1,745 |
) |
(7,383 |
) |
(5,007 |
) |
Capital projects in
development |
(11 |
) |
(76 |
) |
(146 |
) |
(295 |
) |
Contributions to equity
investments |
(541 |
) |
(195 |
) |
(1,681 |
) |
(765 |
) |
Acquisitions, net of
cash acquired |
— |
|
— |
|
— |
|
(13,608 |
) |
Proceeds from sales of
assets, net of transaction costs |
1,170 |
|
— |
|
5,317 |
|
6 |
|
Other distributions
from equity investments |
— |
|
2 |
|
362 |
|
727 |
|
Deferred
amounts and other |
(81 |
) |
141 |
|
(168 |
) |
159 |
|
Net cash
used in investing activities |
(1,463 |
) |
(1,873 |
) |
(3,699 |
) |
(18,783 |
) |
Financing
Activities |
|
|
|
|
Notes payable
(repaid)/issued, net |
(194 |
) |
(229 |
) |
1,038 |
|
(329 |
) |
Long-term debt issued,
net of issue costs |
1,675 |
|
— |
|
3,643 |
|
12,333 |
|
Long-term debt
repaid |
(1,570 |
) |
(4,810 |
) |
(7,085 |
) |
(7,153 |
) |
Junior subordinated
notes issued, net of issue costs |
— |
|
(2 |
) |
3,468 |
|
1,549 |
|
Dividends on common
shares |
(357 |
) |
(277 |
) |
(1,339 |
) |
(1,436 |
) |
Dividends on preferred
shares |
(39 |
) |
(26 |
) |
(155 |
) |
(100 |
) |
Distributions paid to
non-controlling interests |
(68 |
) |
(78 |
) |
(283 |
) |
(279 |
) |
Common shares issued,
net of issue costs |
232 |
|
3,410 |
|
274 |
|
7,747 |
|
Common shares
repurchased |
— |
|
— |
|
— |
|
(14 |
) |
Preferred shares
issued, net of issue costs |
— |
|
982 |
|
— |
|
1,474 |
|
Partnership units of TC
PipeLines, LP issued, net of issue costs |
63 |
|
64 |
|
225 |
|
215 |
|
Common
units of Columbia Pipeline Partners LP acquired |
— |
|
— |
|
(1,205 |
) |
— |
|
Net cash
(used in)/provided by financing activities |
(258 |
) |
(966 |
) |
(1,419 |
) |
14,007 |
|
Effect of Foreign Exchange Rate Changes on
Cash and Cash Equivalents |
(4 |
) |
— |
|
(39 |
) |
(127 |
) |
(Decrease)/Increase in Cash and Cash
Equivalents |
(335 |
) |
(1,264 |
) |
73 |
|
166 |
|
Cash and Cash
Equivalents |
|
|
|
|
Beginning
of period |
1,424 |
|
2,280 |
|
1,016 |
|
850 |
|
Cash and Cash
Equivalents |
|
|
|
|
End of
period |
1,089 |
|
1,016 |
|
1,089 |
|
1,016 |
|
|
|
|
|
|
|
|
|
|
Condensed consolidated balance sheet
(unaudited - millions of Canadian $) |
|
December 31, 2017 |
|
December 31,2016 |
|
ASSETSCurrent
Assets |
|
|
|
Cash and cash
equivalents |
|
1,089 |
|
1,016 |
|
Accounts
receivable |
|
2,522 |
|
2,075 |
|
Inventories |
|
378 |
|
368 |
|
Assets held for
sale |
|
— |
|
3,717 |
|
Other |
|
691 |
|
908 |
|
|
|
4,680 |
|
8,084 |
|
Plant, Property
and Equipment |
net of accumulated
depreciation of $23,734 and$22,288, respectively |
57,277 |
|
54,475 |
|
Equity
Investments |
|
6,366 |
|
6,544 |
|
Regulatory
Assets |
|
1,376 |
|
1,322 |
|
Goodwill |
|
13,084 |
|
13,958 |
|
Loan Receivable
from Affiliate |
|
919 |
|
— |
|
Intangible and
Other Assets |
|
1,484 |
|
3,026 |
|
Restricted Investments |
|
915 |
|
642 |
|
|
|
86,101 |
|
88,051 |
|
LIABILITIES |
|
|
|
Current Liabilities |
|
|
|
Notes payable |
|
1,763 |
|
774 |
|
Accounts payable and
other |
|
4,057 |
|
3,861 |
|
Dividends payable |
|
586 |
|
526 |
|
Accrued interest |
|
605 |
|
595 |
|
Liabilities related to
assets held for sale |
|
— |
|
86 |
|
Current
portion of long-term debt |
|
2,866 |
|
1,838 |
|
|
|
9,877 |
|
7,680 |
|
Regulatory
Liabilities |
|
4,321 |
|
2,121 |
|
Other Long-Term
Liabilities |
|
727 |
|
1,183 |
|
Deferred Income Tax
Liabilities |
|
5,403 |
|
7,662 |
|
Long-Term Debt |
|
31,875 |
|
38,312 |
|
Junior Subordinated Notes |
|
7,007 |
|
3,931 |
|
|
|
59,210 |
|
60,889 |
|
Common Units Subject to Rescission or
Redemption |
— |
|
1,179 |
|
EQUITY |
|
|
|
Common shares, no par
value |
|
21,167 |
|
20,099 |
|
Issued
and outstanding: |
December
31, 2017 - 881 million shares |
|
|
|
December
31, 2016 - 864 million shares |
|
|
Preferred shares |
|
3,980 |
|
3,980 |
|
Additional paid-in
capital |
|
— |
|
— |
|
Retained earnings |
|
1,623 |
|
1,138 |
|
Accumulated other comprehensive loss |
|
(1,731 |
) |
(960 |
) |
Controlling Interests |
|
25,039 |
|
24,257 |
|
Non-controlling interests |
|
1,852 |
|
1,726 |
|
|
|
26,891 |
|
25,983 |
|
|
|
86,101 |
|
88,051 |
|
|
|
|
|
|
|
Segmented information
|
Canadian |
|
U.S. |
|
Mexico |
|
|
|
|
|
|
|
|
|
three months
ended December 31, 2017 |
Natural |
|
Natural |
|
Natural |
|
|
|
|
|
|
|
|
|
|
Gas |
|
Gas |
|
Gas |
|
Liquids |
|
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
Pipelines |
|
Pipelines |
|
Pipelines |
|
Pipelines |
|
Energy |
|
Corporate1 |
|
Total |
|
Revenues |
968 |
|
900 |
|
138 |
|
599 |
|
1,012 |
|
— |
|
3,617 |
|
Intersegment revenues |
— |
|
20 |
|
— |
|
— |
|
— |
|
(20 |
) |
— |
|
|
968 |
|
920 |
|
138 |
|
599 |
|
1,012 |
|
(20 |
) |
3,617 |
|
Income (loss) from
equity investments |
2 |
|
65 |
|
(9 |
) |
(6 |
) |
130 |
|
64 2 |
|
246 |
|
Plant operating costs
and other |
(342 |
) |
(336 |
) |
(13 |
) |
(186 |
) |
(86 |
) |
19 |
|
(944 |
) |
Commodity purchases
resold |
— |
|
— |
|
— |
|
— |
|
(671 |
) |
— |
|
(671 |
) |
Property taxes |
(59 |
) |
(45 |
) |
— |
|
(22 |
) |
(1 |
) |
— |
|
(127 |
) |
Depreciation and
amortization |
(236 |
) |
(143 |
) |
(23 |
) |
(81 |
) |
(33 |
) |
— |
|
(516 |
) |
Goodwill and other
asset impairment charges |
— |
|
— |
|
— |
|
(1,236 |
) |
(21 |
) |
— |
|
(1,257 |
) |
Gain on
sale of assets |
— |
|
— |
|
— |
|
— |
|
142 |
|
— |
|
142 |
|
Segmented earnings/(losses) |
333 |
|
461 |
|
93 |
|
(932 |
) |
472 |
|
63 |
|
490 |
|
Interest expense |
|
|
|
|
|
|
(541 |
) |
Allowance for funds
used during construction |
|
|
|
|
|
|
140 |
|
Interest
income and other |
|
|
|
|
|
|
(9 |
) |
Income before income
taxes |
|
|
|
|
|
|
80 |
|
Income
tax recovery |
|
|
|
|
|
|
870 |
|
Net
income |
|
|
|
|
|
|
950 |
|
Net
income attributable to non-controlling interests |
|
|
|
|
|
|
(49 |
) |
Net income
attributable to controlling interests |
|
|
|
|
|
|
901 |
|
Preferred
share dividends |
|
|
|
|
|
|
(40 |
) |
Net income attributable to common
shares |
|
|
|
|
|
861 |
|
1 The Company records intersegment sales at contracted rates.
For segmented reporting, these transactions are included as
revenues in the segment providing the service, as expenses in the
segment receiving the service and are eliminated on consolidation
within the Corporate segment. Intersegment profit is recognized
when the product or service has been provided to third parties.2
This income from equity investments relates to 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.
|
|
|
|
|
|
|
|
|
Canadian |
|
U.S. |
|
Mexico |
|
|
|
|
|
|
|
|
|
three
months ended December 31, 2016 |
Natural |
|
Natural |
|
Natural |
|
|
|
|
|
|
|
|
|
|
Gas |
|
Gas |
|
Gas |
|
Liquids |
|
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
Pipelines |
|
Pipelines |
|
Pipelines |
|
Pipelines |
|
Energy |
|
Corporate1 |
|
Total |
|
Revenues |
1,005 |
|
941 |
|
129 |
|
463 |
|
1,097 |
|
— |
|
3,635 |
|
Intersegment revenue |
— |
|
11 |
|
— |
|
— |
|
— |
|
(11 |
) |
— |
|
|
1,005 |
|
952 |
|
129 |
|
463 |
|
1,097 |
|
(11 |
) |
3,635 |
|
Income/(loss) from
equity investments |
3 |
|
64 |
|
(1 |
) |
— |
|
93 |
|
— |
|
159 |
|
Plant operating costs
and other |
(359 |
) |
(415 |
) |
(9 |
) |
(151 |
) |
(233 |
) |
(22 |
) |
(1,189 |
) |
Commodity purchases
resold |
— |
|
— |
|
— |
|
— |
|
(544 |
) |
— |
|
(544 |
) |
Property taxes |
(65 |
) |
(42 |
) |
— |
|
(21 |
) |
(22 |
) |
— |
|
(150 |
) |
Depreciation and
amortization |
(220 |
) |
(156 |
) |
(16 |
) |
(78 |
) |
(44 |
) |
— |
|
(514 |
) |
Asset impairment
charges |
— |
|
— |
|
— |
|
— |
|
(92 |
) |
— |
|
(92 |
) |
Loss on
sale of assets |
— |
|
— |
|
— |
|
— |
|
(829 |
) |
— |
|
(82 |
) |
Segmented earnings/(losses) |
364 |
|
403 |
|
103 |
|
213 |
|
(574 |
) |
(33 |
) |
476 |
|
Interest expense |
|
|
|
|
|
|
(542 |
) |
Allowance for funds
used during construction |
|
|
|
|
|
|
97 |
|
Interest
income and other |
|
|
|
|
|
|
(15 |
) |
Loss before income
taxes |
|
|
|
|
|
|
16 |
|
Income
tax recovery |
|
|
|
|
|
|
(274 |
) |
Net
loss |
|
|
|
|
|
|
(258 |
) |
Net
income attributable to non-controlling interests |
|
|
|
|
|
|
(68 |
) |
Net loss
attributable to controlling interests |
|
|
|
|
|
|
(326 |
) |
Preferred
share dividends |
|
|
|
|
|
|
(32 |
) |
Net loss attributable to common shares |
|
|
|
|
|
|
(358 |
) |
1 The Company records intersegment sales at contracted rates.
For segmented reporting, these transactions are included as
revenues in the segment providing the service, as expenses in the
segment receiving the service and are eliminated on consolidation
within the Corporate segment. Intersegment profit is recognized
when the product or service has been provided to third parties.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian |
|
U.S. |
|
Mexico |
|
|
|
|
|
|
|
|
|
year ended
December 31, 2017 |
Natural |
|
Natural |
|
Natural |
|
|
|
|
|
|
|
|
|
|
Gas |
|
Gas |
|
Gas |
|
Liquids |
|
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
Pipelines |
|
Pipelines |
|
Pipelines |
|
Pipelines |
|
Energy |
|
Corporate1 |
|
Total |
|
Revenues |
3,693 |
|
3,584 |
|
570 |
|
2,009 |
|
3,593 |
|
— |
|
13,449 |
|
Intersegment revenues |
— |
|
51 |
|
— |
|
— |
|
— |
|
(51 |
) |
— |
|
|
3,693 |
|
3,635 |
|
570 |
|
2,009 |
|
3,593 |
|
(51 |
) |
13,449 |
|
Income/(loss) from
equity investments |
11 |
|
240 |
|
(9 |
) |
(3 |
) |
471 |
|
63 2 |
|
773 |
|
Plant operating costs
and other |
(1,300 |
) |
(1,340 |
) |
(42 |
) |
(623 |
) |
(550 |
) |
(51 |
) |
(3,906 |
) |
Commodity purchases
resold |
— |
|
— |
|
— |
|
— |
|
(2,382 |
) |
— |
|
(2,382 |
) |
Property taxes |
(260 |
) |
(181 |
) |
— |
|
(89 |
) |
(39 |
) |
— |
|
(569 |
) |
Depreciation and
amortization |
(908 |
) |
(594 |
) |
(93 |
) |
(309 |
) |
(151 |
) |
— |
|
(2,055 |
) |
Goodwill and other
asset impairment charges |
— |
|
— |
|
— |
|
(1,236 |
) |
(21 |
) |
— |
|
(1,257 |
) |
Gain on
assets held for sale/sold |
— |
|
— |
|
— |
|
— |
|
631 |
|
— |
|
631 |
|
Segmented earnings/(losses) |
1,236 |
|
1,760 |
|
426 |
|
(251 |
) |
1,552 |
|
(39 |
) |
4,684 |
|
Interest expense |
|
|
|
|
|
|
(2,069 |
) |
Allowance for funds
used during construction |
|
|
|
|
|
|
507 |
|
Interest
income and other |
|
|
|
|
|
|
184 |
|
Income before income
taxes |
|
|
|
|
|
|
3,306 |
|
Income
tax recovery |
|
|
|
|
|
|
89 |
|
Net
income |
|
|
|
|
|
|
3,395 |
|
Net
income attributable to non-controlling interests |
|
|
|
|
|
|
(238 |
) |
Net income
attributable to controlling interests |
|
|
|
|
|
|
3,157 |
|
Preferred
share dividends |
|
|
|
|
|
|
(160 |
) |
Net income attributable to common
shares |
|
|
|
|
|
2,997 |
|
1 The Company records intersegment sales at contracted rates.
For segmented reporting, these transactions are included as
revenues in the segment providing the service, as expenses in the
segment receiving the service and are eliminated on consolidation
within the Corporate segment. Intersegment profit is recognized
when the product or service has been provided to third parties.2
This income from equity investments relates to 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian |
|
U.S. |
|
Mexico |
|
|
|
|
|
|
|
|
|
year
ended December 31, 2016 |
Natural |
|
Natural |
|
Natural |
|
|
|
|
|
|
|
|
|
|
Gas |
|
Gas |
|
Gas |
|
Liquids |
|
|
|
|
|
|
|
(unaudited - millions of Canadian $) |
Pipelines |
|
Pipelines |
|
Pipelines |
|
Pipelines |
|
Energy |
|
Corporate1 |
|
Total |
|
Revenues |
3,682 |
|
2,526 |
|
378 |
|
1,755 |
|
4,206 |
|
— |
|
12,547 |
|
Intersegment revenues |
— |
|
56 |
|
— |
|
— |
|
— |
|
(56 |
) |
— |
|
|
3,682 |
|
2,582 |
|
378 |
|
1,755 |
|
4,206 |
|
(56 |
) |
12,547 |
|
Income/(loss) from
equity investments |
12 |
|
214 |
|
(3 |
) |
(1 |
) |
292 |
|
— |
|
514 |
|
Plant operating costs
and other |
(1,245 |
) |
(1,057 |
) |
(43 |
) |
(568 |
) |
(884 |
) |
(64 |
) |
(3,861 |
) |
Commodity purchases
resold |
— |
|
— |
|
— |
|
— |
|
(2,172 |
) |
— |
|
(2,172 |
) |
Property taxes |
(267 |
) |
(120 |
) |
— |
|
(88 |
) |
(80 |
) |
— |
|
(555 |
) |
Depreciation and
amortization |
(875 |
) |
(425 |
) |
(45 |
) |
(292 |
) |
(302 |
) |
— |
|
(1,939 |
) |
Asset impairment
charges |
— |
|
— |
|
— |
|
— |
|
(1,388 |
) |
— |
|
(1,388 |
) |
Loss on
sale of assets |
— |
|
(4 |
) |
— |
|
— |
|
(829 |
) |
— |
|
(833 |
) |
Segmented earnings/(losses) |
1,307 |
|
1,190 |
|
287 |
|
806 |
|
(1,157 |
) |
(120 |
) |
2,313 |
|
Interest expense |
|
|
|
|
|
|
(1,998 |
) |
Allowance for funds
used during construction |
|
|
|
|
|
|
419 |
|
Interest
income and other |
|
|
|
|
|
|
103 |
|
Income before income
taxes |
|
|
|
|
|
|
837 |
|
Income
tax expense |
|
|
|
|
|
|
(352 |
) |
Net
Income |
|
|
|
|
|
|
485 |
|
Net income attributable to non-controlling
interests |
|
|
|
|
|
(252 |
) |
Net
Income attributable to controlling interests |
|
|
|
|
|
233 |
|
Preferred
share dividends |
|
|
|
|
|
|
(109 |
) |
Net Income attributable to common shares |
|
|
|
|
|
|
124 |
|
1 The Company records intersegment sales at contracted rates.
For segmented reporting, these transactions are included as
revenues in the segment providing the service, as expenses in the
segment receiving the service and are eliminated on consolidation
within the Corporate segment. Intersegment profit is recognized
when the product or service has been provided to third parties.
TOTAL ASSETS
|
|
(unaudited - millions of Canadian $) |
December 31, 2017 |
December 31, 2016 |
Canadian Natural Gas
Pipelines |
16,904 |
15,816 |
U.S. Natural Gas
Pipelines |
35,898 |
34,422 |
Mexico Natural Gas
Pipelines |
5,716 |
5,013 |
Liquids Pipelines |
15,438 |
16,896 |
Energy |
8,503 |
13,169 |
Corporate |
3,642 |
2,735 |
|
86,101 |
88,051 |
|
|
|
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