CALGARY, Feb. 16, 2018 /PRNewswire/ - Enbridge Inc.
(Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported
fourth quarter 2017 financial results and provided a quarterly
business update.
FOURTH QUARTER AND FULL YEAR HIGHLIGHTS
(all
financial figures are unaudited and in Canadian dollars unless
otherwise noted)
- Earnings of $207 million or
$0.13 per common share for the fourth
quarter and earnings of $2,529
million or $1.66 per common
share for the full year, both including the impact of a number of
unusual, non-recurring or non-operating factors
- Adjusted earnings were $1,013
million or $0.61 per common
share for the fourth quarter and $2,982
million or $1.96 per common
share for the full year
- Adjusted earnings before interest, income tax and depreciation
and amortization (EBITDA) was $2,963
million for the fourth quarter and $10,317 million for the full year
- Distributable Cash Flow (DCF) was $1,741
million for the fourth quarter and $5,614 million for the full year; Cash provided
by operating activities was $1,341
million for the fourth quarter and $6,584 million for the full year
- Completed merger with Spectra Energy (Merger Transaction)
creating the largest North American energy infrastructure company
with leading liquids, natural gas transmission and natural gas
distribution utilities footprints
- Achieved 2017 target synergy capture and progressed cost
management initiatives
- Completed corporate simplification transactions through several
sponsored vehicle actions, and filed a utility amalgamation plan
with the Ontario Energy Board
- Brought a total of $12 billion of
growth projects into service in 2017, with an additional
$22 billion of secured growth
projects expected to come into service through 2020
- Advanced Line 3 Replacement Project construction in
Canada; Minnesota regulatory process reaffirmed with
the Minnesota Public Utilities Commission (MPUC), permit decisions
expected in the second quarter of 2018
- Executed $14 billion of new
capital markets funding in 2017 and completed $2.6 billion of asset sales post the Merger
Transaction announcement
- Announced the details of the Company's updated 2018 to 2020
strategic business outlook and funding plan; including 2018 DCF
guidance of $4.15 - $4.45/share
- Increased the dividend by 15% in 2017, increased the dividend
by another 10% for 2018 and guided to 10% compound annual dividend
per share growth through 2020
CEO COMMENT
"This has been a transformational year for our company,"
commented Al Monaco, President and
Chief Executive Officer of Enbridge. "With the Spectra Energy
assets now in the fold, we have successfully delivered on our
strategy to re-balance our business mix with best in class natural
gas transmission assets and further enhance and extend our growth
potential. We've substantially integrated the two companies and are
slightly ahead of target for capturing cost synergies as we
streamline operations and create an even more effective and
efficient organization.
"In addition to the merger, we significantly added to our
leading infrastructure footprint, bringing a total of $12 billion of new assets into service,
substantially on time and on budget. This marks the single largest
year for project completion in our history and these assets will
provide growing and predictable cash flows to support our premium
dividend growth.
"Our full year financial results came in roughly where we
expected and within our DCF/share guidance range. However, as we
had previously identified, the timing of the closing of the merger,
customer project delays and facility outages, and a weak commodity
price environment affecting the gas midstream and energy services
businesses impacted our full year results.
"Fourth quarter results were strong and demonstrate the earnings
power of our core businesses. Liquids Pipelines volumes reached
record levels in December and the demand outlook remains robust
into 2018 as WCSB crude production volumes continue to rise. Our
Gas Transmission business delivered another rock solid quarter with
steady volumes and new projects in service, and the Gas
Distribution businesses continued to have strong rate base growth
within their franchises. Importantly, we accomplished all of this
while maintaining our leading operational safety and reliability
performance.
"We also made good progress on our priority to strengthen the
balance sheet as we build out our secured growth program, raising
about $5 billion of equity or equity
equivalent funding during the year. And we have a readily
executable plan to achieve our longer term leverage targets by the
end of 2018.
"Looking forward, with our updated strategic and financial plan,
we've set a course for the next three years that reflects the right
combination of capital discipline while deleveraging the balance
sheet and maintaining ample funding flexibility for our
$22 billion secured project
inventory. We continue to see a significant opportunity set for new
low risk growth in our core footprint beyond the 2020 horizon.
"We accomplished several important milestones in 2017 and we are
well positioned heading into 2018 and beyond."
FINANCIAL RESULTS SUMMARY
Financial results for the three and twelve months ended
December 31, 2017, are summarized in
the table below:
|
|
|
|
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars, except per share amounts; number of
shares in millions)
|
|
|
|
|
|
Earnings
|
207
|
365
|
|
2,529
|
1,776
|
Earnings per common
share
|
0.13
|
0.39
|
|
1.66
|
1.95
|
Cash provided by
operating activities
|
1,341
|
1,058
|
|
6,584
|
5,211
|
Adjusted
EBITDA1
|
2,963
|
1,762
|
|
10,317
|
6,902
|
Adjusted
Earnings1
|
1,013
|
522
|
|
2,982
|
2,078
|
Adjusted Earnings per
common share1
|
0.61
|
0.56
|
|
1.96
|
2.28
|
Distributable Cash
Flow1,2
|
1,741
|
879
|
|
5,614
|
3,713
|
Weighted average
common shares outstanding
|
1,652
|
927
|
|
1,525
|
911
|
|
|
|
|
|
|
1
Schedules reconciling adjusted EBITDA, adjusted earnings,
adjusted earnings per common share and distributable cash flow
are available as an Appendix to this news release.
|
2
Formerly referred to as Adjusted Cash Flow From Operations
(ACFFO). Calculation methodology remains unchanged.
|
Earnings attributable to common shareholders for the year ended
December 31, 2017 increased by
$753 million relative to 2016,
primarily as a result of the Merger Transaction. Earnings for the
fourth quarter of 2017 decreased by $158
million relative to the comparable period in 2016. The
year-over-year and fourth quarter-over-quarter comparability of
earnings attributable to common shareholders was impacted by
certain unusual and infrequent factors, including a non-cash
accounting charge resulting from the write down of assets held for
sale of $2.8 billion after tax,
partially offset by a non-cash accounting benefit resulting from
U.S. Tax Reform of $2.0 billion.
Adjusted earnings growth for the fourth quarter and full year
2017 benefited from the net effect of higher contributions from
Enbridge's new natural gas, liquids and utility assets. Also
contributing to earnings growth was stronger crude oil throughput
on the Mainline system, new projects coming into service in the
Liquids Pipelines, Gas Transmission & Midstream and Gas
Distribution segments, and stronger realized settlements on foreign
exchange hedges. These positive contributors were partially offset
by lower natural gas gathering and processing volumes and margins
on certain U.S. midstream assets and weaker performance in the
Energy Services segment.
DCF for the fourth quarter was $1,741
million, an increase of $862
million over the comparable prior period in 2016, driven
largely by the same factors noted above.
PROJECT EXECUTION UPDATE
Enbridge continues to make good progress executing on its
secured growth capital program. These projects are supported
by long-term take-or-pay contracts, cost-of-service frameworks or
similar low-risk commercial arrangements and are diversified across
a wide range of business platforms and regulatory
jurisdictions.
In 2017, $12 billion of
commercially secured projects were brought into service,
substantially on time and on budget. This execution success
highlights Enbridge's strong project management capability and its
commitment to managing all critical stakeholder relationships.
These projects meaningfully contributed to DCF growth in 2017, with
full contributions expected in 2018 and 2019 as contracted capacity
ramps up on certain projects and all contribute a full year of
earnings and cash flow.
Enbridge is also advancing the remaining $22 billion secured growth project inventory.
Construction has commenced on the US$1.3
billion NEXUS gas pipeline and is expected to be in service
in the third quarter of 2018. Construction on the US$1.5 billion Valley Crossing pipeline in
Texas is progressing well and
remains on schedule for a fourth quarter 2018 in service date. The
$0.8 billion Rampion offshore wind
power generation project in the United
Kingdom has begun generating power and full operations are
expected in the first half of 2018 as the remaining turbines are
connected to the grid.
Following the receipt of all required regulatory permitting for
the Line 3 Replacement in Canada,
construction began in August 2017 on
certain segments of the pipeline and construction will continue
through the winter. Regulatory permitting is also in place in
North Dakota as well as in
Wisconsin where construction is
substantially complete.
In Minnesota, the MPUC is
expected to vote on the Certificate of Need and Route Permit at the
end of the second quarter of 2018. In parallel with this process,
additional clarification and analysis will be provided to support
the adequacy of the Final Environmental Impact Statement, as
requested by the MPUC in December. Management continues to
anticipate an in-service date for the project in the second half of
2019.
STRATEGIC & FINANCIAL UPDATE
On November 29th, Enbridge
released the details of its updated strategic business plan. The
strategic planning process included a review of all existing
businesses post-Merger Transaction. The conclusion reached was to
focus Enbridge's asset mix to a pure regulated pipeline and utility
business model over time, which emphasizes low risk and strong
growth in its three crown jewel businesses: liquids pipelines and
terminals, natural gas transmission and storage and natural gas
utilities. This focused approach will result in disciplined
capital allocation for growth projects and additional non-core
asset sales.
The Company also provided details on its secured funding plan
designed to fund Enbridge's secured growth program while
deleveraging the balance sheet. The plan achieves strong,
investment grade credit metrics throughout the three-year period,
with the Company's Debt to EBITDA metric expected to reach 5.0x by
the end of 2018, and remaining below this long term target level
going forward.
In 2017, close to $14 billion of
new long term capital was raised across the Enbridge group, of
which $5 billion was equity or equity
equivalent funding. The 2018 funding plan includes the issuance of
$3.5 billion of hybrid securities and
sale or monetization of at least $3.0
billion of non-core assets in 2018. The remaining equity
funding requirement can readily be met through a combination of
additional hybrid equity, asset monetization or issuances of common
shares under the Company's DRIP program.
Enbridge made good progress in 2017 with its strategic priority
to restructure and simplify the organization by taking several
sponsored vehicle actions, including: the Enbridge Energy Partners,
L.P. (EEP) restructuring, Midcoast Energy privatization, DCP
Midstream simplification and Spectra Energy Partners, LP (SEP)
incentive distribution elimination. Enbridge plan to continue to
identify and evaluate further streamlining opportunities as
appropriate.
U.S. TAX REFORM
On December 22, 2017, the United States implemented U.S. Tax
Reform. The "Tax Cuts and Jobs Act" (the TCJA) was signed into
law and became enacted for tax purposes. Substantially all of the
provisions of the TCJA are effective for taxation years beginning
after December 31, 2017. The most
significant change included in the TCJA with respect to Enbridge's
2017 financial statements was a reduction in the corporate federal
income tax rate from 35% to 21%. This resulted in the Company
booking a $2.0 billion reduction to
its deferred income tax provision for the year, which has been
normalized for adjusted earnings purposes. The reduced tax rate
will benefit the Company's DCF once it becomes subject to U.S.
current tax in the future.
While certain elements of the TCJA require clarification through
more detailed regulation or interpretive guidance, Enbridge does
not expect any material impact to consolidated DCF over the plan
horizon.
US Tax Reform impacts arising from commercial arrangements at
the Company's sponsored vehicles are not expected to be significant
over the 2018-2020 plan horizon. The Company estimates that EEP
will realize a reduction in the income tax allowance component of
its cost of service toll revenue of approximately US$55 million per year. Enbridge Income Fund
would expect to realize the offsetting gain to annual revenue due
to the nature of the sharing of the International Joint Toll on the
Mainline system. While SEP has a portion of its revenue derived
from cost of service assets, any revenue loss associated with the
change in tax rate is expected to be immaterial in the event of a
future rate case where many other factors would be considered.
FOURTH QUARTER AND YEAR-END 2017 FINANCIAL RESULTS
The following table includes the Company's GAAP reported results
for segment EBITDA, earnings attributable to common shareholders,
and cash provided by operating activities for the fourth quarter
and full year 2017.
EBITDA AND CASH FLOW FROM OPERATIONS
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Liquids
Pipelines
|
1,555
|
1,733
|
|
6,395
|
4,926
|
Gas Transmission and
Midstream
|
(3,532)
|
95
|
|
(1,269)
|
464
|
Gas
Distribution
|
453
|
238
|
|
1,390
|
831
|
Green Power and
Transmission
|
102
|
78
|
|
372
|
344
|
Energy
Services
|
(252)
|
(146)
|
|
(263)
|
(183)
|
Eliminations and
Other
|
(149)
|
(207)
|
|
(337)
|
(101)
|
Earnings/(loss)
before interest, income taxes,
depreciation and amortization
|
(1,823)
|
1,791
|
|
6,288
|
6,281
|
|
|
|
|
|
|
Earnings
|
207
|
365
|
|
2,529
|
1,776
|
|
|
|
|
|
|
Cash provided by
operating activities
|
1,341
|
1,058
|
|
6,584
|
5,211
|
For purposes of evaluating performance the Company makes
adjustments for unusual, non-recurring or non-operating factors to
GAAP reported earnings, segment EBITDA, and cash flow provided by
operating activities, as it allows Management and investors to more
accurately compare the Company's performance across periods and the
factors being adjusted for are not indicative of the underlying
performance and cash flows of the business. These tables follow
below. Schedules reconciling adjusted EBITDA, adjusted EBITDA by
segment, adjusted earnings, adjusted earnings per common share and
distributable cash flow to their closest GAAP equivalent are
available as an Appendix to this news release.
DISTRIBUTABLE CASH FLOW
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
|
Liquids
Pipelines
|
1,482
|
1,355
|
|
5,484
|
5,327
|
Gas Transmission and
Midstream
|
1,020
|
166
|
|
3,350
|
659
|
Gas
Distribution
|
450
|
238
|
|
1,379
|
833
|
Green Power and
Transmission
|
109
|
91
|
|
379
|
355
|
Energy
Services
|
(21)
|
(4)
|
|
(52)
|
30
|
Eliminations and
Other
|
(77)
|
(84)
|
|
(223)
|
(302)
|
Adjusted
EBITDA1
|
2,963
|
1,762
|
|
10,317
|
6,902
|
Maintenance
Capital
|
(345)
|
(205)
|
|
(1,261)
|
(671)
|
Interest
expense1
|
(665)
|
(403)
|
|
(2,421)
|
(1,545)
|
Current income
tax1
|
(49)
|
(31)
|
|
(154)
|
(92)
|
Distributions to
noncontrolling interests and
redeemable noncontrolling interests1
|
(272)
|
(236)
|
|
(1,042)
|
(922)
|
Cash distributions in
excess of equity earnings1
|
118
|
67
|
|
279
|
183
|
Preference share
dividends
|
(84)
|
(76)
|
|
(330)
|
(293)
|
Other receipts of
cash not recognized in revenue2
|
25
|
37
|
|
196
|
119
|
Other non-cash
adjustments
|
50
|
(36)
|
|
30
|
32
|
Distributable cash
flow
|
1,741
|
879
|
|
5,614
|
3,713
|
Weighted average
common shares outstanding
|
1,652
|
927
|
|
1,525
|
911
|
1
|
Presented net of
adjusting items.
|
2
|
Consists of cash
received net of revenue recognized for contracts under make-up
rights and similar deferred revenue arrangements.
|
- DCF for both the fourth quarter and full year of 2017 increased
significantly compared to the prior period primarily as a result of
adjusted EBITDA from assets acquired in the Merger
Transaction.
- Adjusted EBITDA also increased as a result of higher throughput
on the Liquids Pipelines Mainline system in 2017 and from the
contribution of $12 billion of new
projects placed into service across the business segments
throughout the year.
- For further detail on business performance refer to Adjusted
EBITDA by Segments.
- The increase in DCF from higher EBITDA was partially offset by
higher maintenance capital expenditures, higher interest expense
and higher current income tax, all as a result of the Merger
Transaction.
- The increase in DCF was also offset by the increased
distributions to noncontrolling interests related to assets
acquired in the Merger Transaction, increased public ownership in
Enbridge Income Fund Holdings Inc, offset by reduced distributions
at EEP.
ADJUSTED EARNINGS
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
|
Adjusted
EBITDA
|
2,963
|
1,762
|
|
10,317
|
6,902
|
|
Depreciation and
amortization expense
|
(764)
|
(564)
|
|
(3,152)
|
(2,240)
|
|
Interest
expense
|
(638)
|
(403)
|
|
(2,305)
|
(1,545)
|
|
Income
taxes
|
(252)
|
(136)
|
|
(805)
|
(520)
|
|
Noncontrolling
interests and redeemable noncontrolling interests
|
(212)
|
(61)
|
|
(743)
|
(226)
|
|
Preference share
dividends
|
(84)
|
(76)
|
|
(330)
|
(293)
|
Adjusted
earnings
|
1,013
|
522
|
|
2,982
|
2,078
|
Adjusted earnings
per common share
|
0.61
|
0.56
|
|
1.96
|
2.28
|
- The year-over-year growth in Adjusted Earnings was driven by
the same business performance factors as discussed in
Distributable Cash Flow above.
- Depreciation and amortization expense, interest expense, income
taxes, preference share dividends and noncontrolling interest and
redeemable noncontrolling interest all increased period-over-period
due to the Merger Transaction.
- On a per share basis, adjusted earnings per share for 2017 was
lower relative to the corresponding 2016 period due to the mildly
dilutive impact of having a full year of shares issued as part of
the Spectra merger transaction. However, business performance,
growth projects coming into service and the realization of cost
savings and merger synergies throughout 2017 has increased fourth
quarter earnings per share above the corresponding period in
2016.
ADJUSTED EBITDA BY SEGMENTS
The following adjusted EBITDA by segment is reported on a
Canadian dollar basis. Adjusted EBITDA generated from US dollar
denominated businesses were translated at stronger average Canadian
dollar exchange rates both in the fourth quarter and full year 2017
when compared to the corresponding 2016 periods negatively
impacting results. A portion of the US dollar earnings are hedged
under the Company's enterprise-wide financial risk management
program. The offsetting hedge settlements are reported within
Eliminations and Other.
LIQUIDS PIPELINES
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Canadian
Mainline
|
367
|
318
|
|
1,342
|
1,240
|
Lakehead
System
|
441
|
507
|
|
1,786
|
1,905
|
Regional Oil Sands
System
|
182
|
129
|
|
600
|
510
|
Gulf Coast and
Mid-Continent
|
200
|
188
|
|
681
|
800
|
Other1
|
292
|
213
|
|
1,075
|
872
|
Adjusted
EBITDA2
|
1,482
|
1,355
|
|
5,484
|
5,327
|
|
|
|
|
|
|
Operating Data
(average deliveries – thousands of bpd)
|
|
|
|
|
|
Canadian
Mainline3
|
2,586
|
2,481
|
|
2,530
|
2,405
|
Lakehead
System4
|
2,724
|
2,624
|
|
2,673
|
2,574
|
Regional Oil Sands
System5
|
1,392
|
1,197
|
|
1,301
|
1,032
|
International Joint
Tariff
|
4.07
|
4.05
|
|
4.06
|
4.06
|
Lakehead System Local
Toll
|
2.43
|
2.58
|
|
2.47
|
2.55
|
Canadian Mainline IJT
Residual Toll
|
1.64
|
1.47
|
|
1.59
|
1.51
|
Canadian Mainline
Apportionment
|
10%
|
21%
|
|
20%
|
13%
|
Canadian Mainline
Effective FX Rate
|
$1.07
|
$1.06
|
|
$1.06
|
$1.07
|
1
|
Included within
Other are Southern Lights Pipeline, Express-Platte System, Bakken
System and Feeder Pipelines & Other
|
2
|
Schedules
reconciling adjusted EBITDA are available as an Appendix to this
news release.
|
3
|
Canadian Mainline
throughput volume represents mainline system deliveries ex-Gretna,
Manitoba which is made up of United States and eastern Canada
deliveries originating from western Canada
|
4
|
Lakehead System
throughput volume represents mainline system deliveries to the
United States mid-west and eastern Canada
|
5
|
Volumes are for
the Athabasca mainline, Athabasca Twin, Waupisoo Pipeline and
Woodland Pipeline and exclude laterals on the Regional Oil Sands
System
|
Liquids Pipelines adjusted EBITDA increased by $127 million and $157
million for the fourth quarter and full year 2017,
respectively, compared to the same periods in 2016. The key
period-over-period performance drivers were as follows:
- Canadian Mainline 2017 fourth quarter and full year adjusted
EBITDA increased as a result of a higher toll and strong throughput
supported by continued growth in oil sands production and capacity
optimization initiatives enabled in the third quarter of 2017.
- Regional Oil Sands adjusted EBITDA growth was driven by
contributions from new projects placed into service in 2017, most
recently the Wood Buffalo Extension Pipeline in December, which
supports the Fort Hills oil sands project.
- Lakehead System adjusted EBITDA decreased as a result of a
lower Lakehead System Toll and higher operating costs, which were
partially offset by higher throughput as noted above.
- Gulf Coast and Mid-Continent year-over-year adjusted EBITDA
decreased largely due to a change in reporting practice. As of
January 1, 2017 the impact of cash
collected under take-or-pay contracts with make-up rights are no
longer reflected in adjusted EBITDA, however they continue to be
included as a component of DCF. Higher apportionment in 2017
compared with 2016, primarily during the first half of the year
also contributed to lower adjusted EBITDA as Mainline apportionment
allows relief on certain take or pay obligations on the Flanagan
South pipeline.
GAS TRANSMISSION AND MIDSTREAM
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
US Gas
Transmission
|
650
|
10
|
|
2,215
|
31
|
Canadian Gas
Transmission & Midstream
|
196
|
41
|
|
575
|
142
|
Alliance
Pipeline
|
56
|
40
|
|
205
|
184
|
US
Midstream
|
69
|
48
|
|
218
|
207
|
Other
|
49
|
27
|
|
137
|
95
|
Adjusted
EBITDA1
|
1,020
|
166
|
|
3,350
|
659
|
1 Schedules
reconciling adjusted EBITDA are available as an Appendix to this
news release.
|
Gas Transmission and Midstream adjusted EBITDA increased by
$854 million and $2,691 million for the fourth quarter and full
year 2017, respectively, compared to the same periods in 2016. The
key period-over-period performance drivers were as follows:
- US Gas Transmission's operating results were primarily driven
by contributions from the legacy Spectra assets. During the year,
this segment also benefitted from contributions from expansion
projects completed in 2016 and 2017 on the Texas Eastern and
Algonquin systems.
- Canadian Gas Transmission & Midstream results increased
primarily as a result of the legacy Spectra assets.
- US Midstream results reflected the addition of earnings from
DCP Midstream as well as an improving commodity price environment
and stronger fractionation margins driving higher equity earnings
from Aux Sable, offset by weaker
processing volumes and margins in the legacy Midcoast
business.
GAS DISTRIBUTION
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Enbridge Gas
Distribution Inc. (EGD)
|
201
|
199
|
|
701
|
709
|
Union Gas Limited
(Union Gas)
|
208
|
—
|
|
551
|
—
|
Other Gas
Distribution and Storage
|
41
|
39
|
|
127
|
124
|
Adjusted
EBITDA1
|
450
|
238
|
|
1,379
|
833
|
|
|
|
|
|
|
Operating
Data
|
|
|
|
|
|
Enbridge Gas
Distribution
|
|
|
|
|
|
|
Volumes (billions of
cubic feet)
|
135
|
119
|
|
421
|
414
|
|
Number of active
customers (thousands)3
|
2,190
|
2,158
|
|
2,190
|
2,158
|
|
Heating degree
days4
|
|
|
|
|
|
|
|
Actual
|
1,285
|
1,129
|
|
3,499
|
3,412
|
|
|
Forecast based on
normal weather
|
1,226
|
1,243
|
|
3,639
|
3,617
|
Union
Gas2
|
|
|
|
|
|
|
Volumes (billions of
cubic feet)
|
370
|
—
|
|
944
|
—
|
|
Number of active
customers (thousands)3
|
1,475
|
—
|
|
1,475
|
—
|
|
Heating degree
days4, 2
|
|
|
|
|
|
|
|
Actual
|
1,433
|
—
|
|
2,688
|
—
|
|
|
Forecast based on
normal weather
|
1,377
|
—
|
|
2,636
|
—
|
1
|
Schedules
reconciling adjusted EBITDA are available as an Appendix to this
news release.
|
2
|
Reflects operating
data post-Spectra Merger.
|
3
|
Number of active
customers is the number of EGD and Union Gas customers at the end
of the period.
|
4
|
Heating degree
days is a measure of coldness that is indicative of volumetric
requirements for natural gas utilized for heating purposes in EGD's
and Union Gas's franchise area. It is calculated by accumulating,
for the fiscal period, the total number of degrees each day by
which the daily mean temperature falls below 18 degrees
Celsius.
|
Gas Distribution adjusted EBITDA increased by $212 million and $546
million for the fourth quarter and full year 2017,
respectively, compared to the same periods in 2016. The key
period-over-period performance drivers were as follows:
- The primary driver of the Adjusted EBITDA increase is the
inclusion of Union Gas assets acquired through the Merger
Transaction. During the year, Union Gas also benefited from
increased contributions from the Dawn-Parkway expansion projects,
increased storage optimization and increases in delivery
rates.
- EGD full year 2017 adjusted EBITDA contribution was slightly
lower than the comparable period due to lower distribution
revenues, reflecting warmer than normal weather in the first
quarter, partially offset by colder than normal weather in the
fourth quarter. Prior to 2017, EGD adjusted for the effect of
warmer/colder weather for the purposes of Adjusted EBITDA. Had EGD
continued its policy of adjusting for the effects of warmer/colder
weather, adjusted EBITDA for 2017 would have been $15 million higher.
- Union is subject to similar weather impacts as EGD. For the 10
month period post-Merger Transaction, Union Gas adjusted EBITDA
would have been $3 million higher had
the company adjusted for the effects of weather.
GREEN POWER AND TRANSMISSION
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Adjusted
EBITDA1
|
109
|
91
|
|
379
|
355
|
1 Schedules
reconciling adjusted EBITDA are available as an Appendix to this
news release.
|
Green Power & Transmission adjusted EBITDA increased by
$18 million and $24 million in the fourth quarter and full year
2017, respectively, compared to the same periods in 2016. The key
period-over-period performance drivers were as follows:
- Stronger wind resources across the Company's North American
portfolio drove higher EBITDA for both the quarter and full
year.
- Also contributing to higher EBITDA were contributions from new
assets, including the Chapman Ranch wind farm placed into service
in the fourth quarter of 2017.
ENERGY SERVICES
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Adjusted
earnings/(loss) before interest, income taxes,
depreciation and amortization1
|
(21)
|
(4)
|
|
(52)
|
30
|
1 Schedules
reconciling adjusted EBITDA are available as an Appendix to this
news release.
|
Energy Services adjusted loss before interest, income taxes,
depreciation and amortization increased by $17 million and $82
million, respectively, for the fourth quarter and full year
2017 when compared to the same periods in 2016. The key
period-over-period performance drivers were as follows:
- For both the fourth quarter and full year, Energy Services
results were negatively impacted by low commodity prices which
affected location and quality differentials and resulted in fewer
opportunities to achieve profitable margins for assets on which
capacity obligations are held.
ELIMINATIONS AND OTHER
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Operating and
administrative
|
(52)
|
(8)
|
|
(39)
|
(5)
|
Realized foreign
exchange hedge settlements
|
(25)
|
(76)
|
|
(184)
|
(297)
|
Adjusted loss
before interest, income taxes,
depreciation and amortization1
|
(77)
|
(84)
|
|
(223)
|
(302)
|
1 Schedules
reconciling adjusted EBITDA are available as an Appendix to this
news release.
|
Eliminations and Other adjusted loss before interest, income
taxes, depreciation and amortization decreased by $7 million and $79
million for the fourth quarter and full year 2017,
respectively, when compared to the same periods in 2016. The key
period-over-period performance drivers were as follows:
- Eliminations and Other benefited from reduced hedge settlement
losses in 2017 relative to 2016 due to a stronger Canadian dollar
and more favourable hedge rates. On a consolidated basis, this
benefit partially offset the effect of less favourable US dollar
currency translation impacts in the business segment results.
- This was partially offset by higher unallocated operating and
administrative costs net of corporate synergies.
CONFERENCE CALL
Enbridge will host a joint conference call and webcast on
February 16, 2018 at 9:00
a.m. Eastern Time (7:00 a.m. Mountain Time) with Enbridge
Income Fund Holdings Inc., Enbridge Energy Partners, L.P. and
Spectra Energy Partners, LP to provide an enterprise wide business
update and review 2017 fourth quarter and year end financial
results. Analysts, members of the media and other interested
parties can access the call toll free at (877) 930-8043 or within
and outside North America at (253)
336-7522 using the access code of 4939158#. The call will be audio
webcast live at https://edge.media-server.com/m6/p/rudushbf. A
webcast replay and podcast will be available approximately two
hours after the conclusion of the event and a transcript will be
posted to the website within 24 hours. The replay will be available
for seven days after the call toll-free (855) 859-2056 or within
and outside North America at (404)
537-3406 (access code 4939158#).
The conference call format will include prepared remarks from
the executive team followed by a question and answer session for
the analyst and investor community only. Enbridge's media and
investor relations teams will be available after the call for any
additional questions.
FORWARD-LOOKING INFORMATION
Forward-looking
information, or forward-looking statements, have been included in
this news release to provide information about the Company and its
subsidiaries and affiliates, including management's assessment of
Enbridge and its subsidiaries' future plans and operations. This
information may not be appropriate for other purposes.
Forward-looking statements are typically identified by words such
as ''anticipate'', ''expect'', ''project'', ''estimate'',
''forecast'', ''plan'', ''intend'', ''target'', ''believe'',
"likely" and similar words suggesting future outcomes or statements
regarding an outlook. Forward-looking information or statements
included or incorporated by reference in this document include, but
are not limited to, statements with respect to the following:
expected EBITDA or expected adjusted EBITDA; expected
earnings/(loss) or adjusted earnings/(loss); expected
earnings/(loss) or adjusted earnings/(loss) per share; expected DCF
or DCF per share; expected future cash flows; expected performance
of the Company's businesses; financial strength and flexibility;
expectations on sources of liquidity and sufficiency of financial
resources; expected credit metrics and debt to EBITDA levels;
expected costs related to announced projects and projects under
construction; expected in-service dates for announced
projects and projects under construction; expected capital
expenditures; expected impact on cash flows of the Company's
commercially secured growth program; expected future growth and
expansion opportunities; expectations about the Company's
joint venture partners' ability to complete and finance projects
under construction; expected closing of acquisitions and
dispositions; estimated future dividends; expected outcome
of the Minnesota Public Utilities Commission review of the Line 3
Replacement Project; expected future actions of regulators;
expectations regarding commodity prices; supply forecasts;
expectations regarding the impact of the Merger Transaction
including the combined Company's scale, financial flexibility,
growth program, future business prospects and performance and
streamlining opportunities; expected impact of U.S. Tax Reform;
dividend payout policy; and dividend growth and dividend payout
expectation.
Although Enbridge believes these forward-looking statements
are reasonable based on the information available on the date such
statements are made and processes used to prepare the information,
such statements are not guarantees of future performance and
readers are cautioned against placing undue reliance on
forward-looking statements. By their nature, these statements
involve a variety of assumptions, known and unknown risks and
uncertainties and other factors, which may cause actual results,
levels of activity and achievements to differ materially from those
expressed or implied by such statements. Material assumptions
include assumptions about the following: the expected supply of and
demand for crude oil, natural gas, natural gas liquids (NGL) and
renewable energy; prices of crude oil, natural gas, NGL and
renewable energy; exchange rates; inflation; interest rates;
availability and price of labour and construction materials;
operational reliability; customer and regulatory approvals;
maintenance of support and regulatory approvals for the Company's
projects; anticipated in-service dates; weather; the
realization of anticipated benefits and synergies of the Merger
Transaction; governmental legislation; acquisitions and the timing
thereof; the success of integration plans; impact of capital
project execution on the Company's future cash flows; credit
ratings; capital project funding; expected EBITDA or expected
adjusted EBITDA; expected earnings/(loss) or adjusted
earnings/(loss); expected earnings/(loss) or adjusted
earnings/(loss) per share; expected future cash flows and expected
future DCF and DCF per share; and estimated future dividends.
Assumptions regarding the expected supply of and demand for crude
oil, natural gas, NGL and renewable energy, and the prices of these
commodities, are material to and underlie all forward-looking
statements, as they may impact current and future levels of demand
for the Company's services. Similarly, exchange rates, inflation
and interest rates impact the economies and business environments
in which the Company operates and may impact levels of demand for
the Company's services and cost of inputs, and are therefore
inherent in all forward-looking statements. Due to the
interdependencies and correlation of these macroeconomic factors,
the impact of any one assumption on a forward-looking statement
cannot be determined with certainty, particularly with
respect to the impact of the Merger Transaction on the Company,
expected EBITDA, adjusted EBITDA, earnings/(loss), adjusted
earnings/(loss) and associated per share amounts, or estimated
future dividends. The most relevant assumptions associated with
forward-looking statements on announced projects and projects under
construction, including estimated completion dates and expected
capital expenditures, include the following: the availability and
price of labour and construction materials; the effects of
inflation and foreign exchange rates on labour and material
costs; the effects of interest rates on borrowing costs; the impact
of weather and customer, government and regulatory approvals on
construction and in-service schedules and cost recovery
regimes.
Enbridge's forward-looking statements are subject to risks
and uncertainties pertaining to the impact of the Merger
Transaction, operating performance, regulatory parameters, dividend
policy, project approval and support, renewals of rights of way,
weather, economic and competitive conditions, public opinion,
changes in tax laws and tax rates, changes in trade agreements,
exchange rates, interest rates, commodity prices, political
decisions and supply of and demand for commodities,
including but not limited to those risks and uncertainties
discussed in this news release and in the Company's other filings
with Canadian and United States
securities regulators. The impact of any one risk, uncertainty or
factor on a particular forward-looking statement is not
determinable with certainty as these are interdependent and
Enbridge's future course of action depends on management's
assessment of all information available at the relevant time.
Except to the extent required by applicable law, Enbridge assumes
no obligation to publicly update or revise any forward-looking
statements made in this news release or otherwise, whether as a
result of new information, future events or otherwise. All
subsequent forward-looking statements, whether written or oral,
attributable to Enbridge or persons acting on the Company's behalf,
are expressly qualified in their entirety by these cautionary
statements.
ABOUT ENBRIDGE INC.
Enbridge Inc. is North America's premier energy infrastructure
company with strategic business platforms that include an extensive
network of crude oil, liquids and natural gas pipelines, regulated
natural gas distribution utilities and renewable power generation.
The Company safely delivers an average of 2.8 million barrels of
crude oil each day through its Mainline and Express Pipeline;
accounts for approximately 65% of U.S.-bound Canadian crude oil
exports; and moves approximately 20% of all natural gas consumed in
the U.S., serving key supply basins and demand markets. The
Company's regulated utilities serve approximately 3.7 million
retail customers in Ontario,
Quebec and New Brunswick. Enbridge also has interests in
more than 2,500 MW of net renewable generating capacity in
North America and Europe. The Company has ranked on the Global
100 Most Sustainable Corporations index for the past eight years;
its common shares trade on the Toronto and New
York stock exchanges under the symbol ENB.
Life takes energy and Enbridge exists to fuel people's
quality of life. For more information, visit
www.enbridge.com.
None of the information contained in, or connected to,
Enbridge's website is incorporated in or otherwise part of this
news release.
DIVIDEND DECLARATION
Our Board of Directors has declared the following quarterly
dividends. All dividends are payable on March 1, 2018 to
shareholders of record on February 15, 2018.
|
|
|
|
|
Common
Shares
|
|
|
|
0.67100
|
Preference Shares,
Series A
|
|
|
0.34375
|
Preference Shares,
Series B1
|
|
|
0.21340
|
Preference Shares,
Series C2
|
|
|
0.20342
|
Preference Shares,
Series D
|
|
|
0.25000
|
Preference Shares,
Series F
|
|
|
0.25000
|
Preference Shares,
Series H
|
|
|
0.25000
|
Preference Shares,
Series J3
|
|
|
US$0.30540
|
Preference Shares,
Series L4
|
|
|
US$0.30993
|
Preference Shares,
Series N
|
|
|
0.25000
|
Preference Shares,
Series P
|
|
|
0.25000
|
Preference Shares,
Series R
|
|
|
0.25000
|
Preference Shares,
Series 1
|
|
|
US$0.25000
|
Preference Shares,
Series 3
|
|
|
0.25000
|
Preference Shares,
Series 5
|
|
|
US$0.27500
|
Preference Shares,
Series 7
|
|
|
0.27500
|
Preference Shares,
Series 9
|
|
|
0.27500
|
Preference Shares,
Series 11
|
|
|
0.27500
|
Preference Shares,
Series 13
|
|
|
0.27500
|
Preference Shares,
Series 15
|
|
|
0.27500
|
Preference Shares,
Series 17
|
|
|
0.32188
|
Preference Shares,
Series 19
|
|
|
0.26850
|
1
|
The quarterly
dividend amount of Series B was decreased to $0.21340 from
$0.25000 on June 1, 2017, due to the reset of the annual
dividend rate on every fifth anniversary of the date of issuance of
the Series B Preference Shares.
|
2
|
The
quarterly dividend amount of Series C was set at $0.18600 on June
1, 2017, $0.19571 on September 1, 2017 and $0.20342 on December 1,
2017, due to reset on a quarterly basis following the date of
issuance of the Series C Preference Shares.
|
3
|
The quarterly
dividend amount of Series J was increased to US$0.30540 from
US$0.25000 on June 1, 2017, due to the reset of the annual dividend
rate on every fifth anniversary of the date of issuance of the
Series J Preference Shares.
|
4
|
The quarterly
dividend amount of Series L was increased to US$0.30993 from
US$0.25000 on September 1, 2017, due to the reset of the annual
dividend rate on every fifth anniversary of the date of issuance of
the Series L Preference Shares.
|
NON-GAAP RECONCILATIONS APPENDICES
This news release contains references to adjusted EBITDA,
adjusted earnings, adjusted earnings per common share, and DCF.
Management believes the presentation of adjusted EBITDA, adjusted
earnings, adjusted earnings per common share and DCF gives useful
information to investors and shareholders as they provide increased
transparency and insight into the performance of the Company.
Adjusted EBITDA represents EBITDA adjusted for unusual,
non-recurring or non-operating factors on both a consolidated and
segmented basis. Management uses adjusted EBITDA to set targets and
to assess the performance of the Company.
Adjusted earnings represent earnings attributable to common
shareholders adjusted for unusual, non-recurring or non-operating
factors included in adjusted EBITDA, as well as adjustments for
unusual, non-recurring or non-operating factors in respect of
depreciation and amortization expense, interest expense, income
taxes, noncontrolling interests and redeemable noncontrolling
interests on a consolidated basis. Management uses adjusted
earnings as another reflection of the Company's ability to generate
earnings.
DCF is defined as cash flow provided by operating activities
before changes in operating assets and liabilities (including
changes in environmental liabilities) less distributions to
noncontrolling interests and redeemable noncontrolling interests,
preference share dividends and maintenance capital expenditures,
and further adjusted for unusual, non-recurring or non-operating
factors. Management also uses DCF to assess the performance
of the Company and to set its dividend payout target.
Reconciliations of forward looking non-GAAP financial measures
to comparable GAAP measures are not available due to the challenges
and impracticability with estimating some of the items,
particularly with estimates for certain contingent liabilities, and
estimating non-cash unrealized derivative fair value losses and
gains and ineffectiveness on hedges which are subject to market
variability and therefore a reconciliation is not available without
unreasonable effort.
Our non-GAAP measures described above are not measures that have
standardized meaning prescribed by generally accepted accounting
principles in the United States of
America (U.S. GAAP) and are not U.S. GAAP measures.
Therefore, these measures may not be comparable with similar
measures presented by other issuers.
The tables below provide a reconciliation of the non-GAAP
measures to comparable GAAP measures.
APPENDIX A
NON- GAAP RECONCILATIONS: ADJUSTED
EBITDA AND ADJUSTED EARNINGS
CONSOLIDATED EARNINGS
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Liquids
Pipelines
|
1,555
|
1,733
|
|
6,395
|
4,926
|
Gas Transmission and
Midstream
|
(3,532)
|
95
|
|
(1,269)
|
464
|
Gas
Distribution
|
453
|
238
|
|
1,390
|
831
|
Green Power and
Transmission
|
102
|
78
|
|
372
|
344
|
Energy
Services
|
(252)
|
(146)
|
|
(263)
|
(183)
|
Eliminations and
Other
|
(149)
|
(207)
|
|
(337)
|
(101)
|
Earnings/(loss)
before interest, income taxes,
depreciation and amortization
|
(1,823)
|
1,791
|
|
6,288
|
6,281
|
Depreciation and
amortization
|
(775)
|
(564)
|
|
(3,163)
|
(2,240)
|
Interest
expense
|
(852)
|
(412)
|
|
(2,556)
|
(1,590)
|
Income
taxes
|
3,515
|
32
|
|
2,697
|
(142)
|
Earnings attributable
to noncontrolling interests and
redeemable noncontrolling interests
|
226
|
(406)
|
|
(407)
|
(240)
|
Preference share
dividends
|
(84)
|
(76)
|
|
(330)
|
(293)
|
Earnings
attributable to common shareholders
|
207
|
365
|
|
2,529
|
1,776
|
ADJUSTED EBITDA TO ADJUSTED EARNINGS
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars, except per share amounts)
|
|
|
|
|
|
Liquids
Pipelines
|
1,482
|
1,355
|
|
5,484
|
5,327
|
Gas Transmission and
Midstream
|
1,020
|
166
|
|
3,350
|
659
|
Gas
Distribution
|
450
|
238
|
|
1,379
|
833
|
Green Power and
Transmission
|
109
|
91
|
|
379
|
355
|
Energy
Services
|
(21)
|
(4)
|
|
(52)
|
30
|
Eliminations and
Other
|
(77)
|
(84)
|
|
(223)
|
(302)
|
Adjusted
EBITDA
|
2,963
|
1,762
|
|
10,317
|
6,902
|
Depreciation and
amortization expense
|
(764)
|
(564)
|
|
(3,152)
|
(2,240)
|
Interest
expense
|
(638)
|
(403)
|
|
(2,305)
|
(1,545)
|
Income
taxes
|
(252)
|
(136)
|
|
(805)
|
(520)
|
Noncontrolling
interests and redeemable noncontrolling
interests
|
(212)
|
(61)
|
|
(743)
|
(226)
|
Preference share
dividends
|
(84)
|
(76)
|
|
(330)
|
(293)
|
Adjusted
earnings
|
1,013
|
522
|
|
2,982
|
2,078
|
Adjusted earnings
per common share
|
0.61
|
0.56
|
|
1.96
|
2.28
|
EBITDA TO ADJUSTED EARNINGS
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars, except per share amounts)
|
|
|
|
|
|
Earnings/(loss)
before interest, income taxes,
depreciation and amortization
|
(1,823)
|
1,791
|
|
6,288
|
6,281
|
Adjusting
items:
|
|
|
|
|
|
|
Changes in unrealized
derivative fair value (gain)/loss
|
130
|
277
|
|
(1,109)
|
(543)
|
|
Asset and investment
write-down loss
|
4,565
|
433
|
|
4,565
|
1,630
|
|
Gain on sale of
asset
|
—
|
(850)
|
|
(27)
|
(850)
|
|
Alberta wildfire
pipeline and facilities restart costs
|
—
|
8
|
|
—
|
47
|
|
Losses on sale of
non-core assets and investment, net of gains
|
9
|
—
|
|
9
|
4
|
|
Unrealized
intercompany foreign exchange (gain)/loss
|
9
|
(10)
|
|
29
|
43
|
|
Hydrostatic
testing
|
—
|
(1)
|
|
—
|
(15)
|
|
Make-up rights
adjustment
|
—
|
(1)
|
|
—
|
130
|
|
Leak remediation
costs, net of leak insurance recoveries
|
1
|
(11)
|
|
10
|
(8)
|
|
Warmer than normal
weather
|
—
|
10
|
|
—
|
18
|
|
Project development
and transaction costs
|
(1)
|
56
|
|
205
|
86
|
|
Employee severance
and restructuring costs
|
70
|
52
|
|
354
|
82
|
|
Other
|
3
|
8
|
|
(7)
|
(3)
|
Total adjusting
items
|
4,786
|
(29)
|
|
4,029
|
621
|
Adjusted earnings
before interest, income taxes,
depreciation and amortization
|
2,963
|
1,762
|
|
10,317
|
6,902
|
|
Depreciation and
amortization
|
(775)
|
(564)
|
|
(3,163)
|
(2,240)
|
|
Interest
expense
|
(852)
|
(412)
|
|
(2,556)
|
(1,590)
|
|
Income
taxes
|
3,515
|
32
|
|
2,697
|
(142)
|
|
Earnings attributable
to noncontrolling interests and
redeemable noncontrolling interests
|
226
|
(406)
|
|
(407)
|
(240)
|
|
Preference share
dividends
|
(84)
|
(76)
|
|
(330)
|
(293)
|
Adjusting items in
respect of:
|
|
|
|
|
|
|
Depreciation and
amortization
|
11
|
—
|
|
11
|
—
|
|
Interest
expense
|
214
|
9
|
|
251
|
45
|
|
Income
taxes
|
(3,767)
|
(168)
|
|
(3,502)
|
(378)
|
|
Noncontrolling
interests and redeemable noncontrolling interests
|
(438)
|
345
|
|
(336)
|
14
|
Adjusted
earnings
|
1,013
|
522
|
|
2,982
|
2,078
|
Adjusted earnings
per common share
|
0.61
|
0.56
|
|
1.96
|
2.28
|
APPENDIX B
NON-GAAP RECONCILIATION – SEGMENTED EBITDA TO ADJUSTED
EBITDA
LIQUIDS PIPELINES
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Adjusted earnings
before interest, income taxes,
depreciation and amortization
|
1,482
|
1,355
|
|
5,484
|
5,327
|
|
Changes in unrealized
derivative fair value gain/(loss)
|
94
|
(92)
|
|
875
|
474
|
|
Leak remediation
costs, net of leak insurance recoveries
|
(1)
|
11
|
|
(10)
|
8
|
|
Hydrostatic
testing
|
—
|
1
|
|
—
|
15
|
|
Employee severance
and restructuring costs
|
(9)
|
—
|
|
(30)
|
—
|
|
Alberta wildfire
pipelines and facility restart cost
|
—
|
(8)
|
|
—
|
(47)
|
|
Make-up rights
adjustment
|
—
|
1
|
|
—
|
(129)
|
|
Asset and investment
impairment loss
|
—
|
(383)
|
|
—
|
(1,561)
|
|
Gain on sale of pipe
and project wind-down costs
|
6
|
—
|
|
72
|
—
|
|
Gain on sale of
asset
|
—
|
850
|
|
27
|
850
|
|
Derecognition of
regulatory balances
|
—
|
—
|
|
—
|
(6)
|
|
Project development
and transaction costs
|
2
|
(2)
|
|
(4)
|
(5)
|
|
Other
|
(19)
|
—
|
|
(19)
|
—
|
Total
adjustments
|
73
|
378
|
|
911
|
(401)
|
Earnings before
interest, income taxes, depreciation
and amortization
|
1,555
|
1,733
|
|
6,395
|
4,926
|
GAS TRANSMISSION AND MIDSTREAM
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Adjusted earnings
before interest, income taxes,
depreciation and amortization
|
1,020
|
166
|
|
3,350
|
659
|
|
Asset write-down
loss
|
(4,552)
|
(37)
|
|
(4,552)
|
(51)
|
|
Changes in unrealized
derivative fair value loss
|
(8)
|
(34)
|
|
(1)
|
(139)
|
|
DCP Midstream equity
earnings adjustment
|
(7)
|
—
|
|
(28)
|
—
|
|
Grizzly Valley
flood
|
12
|
—
|
|
16
|
—
|
|
Inspection, repair
and other costs
|
13
|
—
|
|
(26)
|
—
|
|
Loss on disposal of
non-core assets
|
—
|
—
|
|
—
|
(4)
|
|
Make-up rights
adjustment
|
—
|
—
|
|
—
|
(1)
|
|
Project development
and transaction costs
|
1
|
—
|
|
(4)
|
—
|
|
Employee severance
and restructuring costs
|
(11)
|
—
|
|
(24)
|
—
|
Total
adjustments
|
(4,552)
|
(71)
|
|
(4,619)
|
(195)
|
Earnings/(loss)
before interest, income taxes,
depreciation and amortization
|
(3,532)
|
95
|
|
(1,269)
|
464
|
GAS DISTRIBUTION
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Adjusted earnings
before interest, income taxes,
depreciation and amortization
|
450
|
238
|
|
1,379
|
833
|
|
Warmer than normal
weather
|
—
|
(10)
|
|
—
|
(18)
|
|
Changes in unrealized
derivative fair value gain/(loss)
|
3
|
—
|
|
16
|
(6)
|
|
Asset impairment
loss
|
—
|
—
|
|
—
|
(5)
|
|
Other regulatory
adjustments
|
—
|
—
|
|
—
|
17
|
|
Employee severance
and restructuring costs
|
—
|
10
|
|
(5)
|
10
|
Total
adjustments
|
3
|
—
|
|
11
|
(2)
|
Earnings before
interest, income taxes, depreciation
and amortization
|
453
|
238
|
|
1,390
|
831
|
GREEN POWER AND TRANSMISSION
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Adjusted earnings
before interest, income taxes,
depreciation and amortization
|
109
|
91
|
|
379
|
355
|
|
Changes in unrealized
derivative fair value gain
|
2
|
—
|
|
2
|
2
|
|
Loss on sale of
investment
|
(9)
|
|
|
(9)
|
|
|
Investment impairment
loss
|
—
|
(13)
|
|
—
|
(13)
|
Total
adjustments
|
(7)
|
(13)
|
|
(7)
|
(11)
|
Earnings before
interest, income taxes, depreciation
and amortization
|
102
|
78
|
|
372
|
344
|
ENERGY SERVICES
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Adjusted
earnings/(loss) before interest, income taxes,
depreciation and amortization
|
(21)
|
(4)
|
|
(52)
|
30
|
|
Changes in unrealized
derivative fair value loss
|
(222)
|
(134)
|
|
(200)
|
(205)
|
|
Employee severance
and restructuring costs
|
(1)
|
—
|
|
(3)
|
—
|
|
Other
|
(8)
|
(8)
|
|
(8)
|
(8)
|
Total
adjustments
|
(231)
|
(142)
|
|
(211)
|
(213)
|
Loss before
interest, income taxes, depreciation and
amortization
|
(252)
|
(146)
|
|
(263)
|
(183)
|
ELIMINATIONS AND OTHER
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
Adjusted loss before
interest, income taxes, depreciation
and amortization
|
(77)
|
(84)
|
|
(223)
|
(302)
|
|
Changes in unrealized
derivative fair value gain/(loss)
|
1
|
(17)
|
|
417
|
417
|
|
Unrealized
intercompany foreign exchange gain/(loss)
|
(9)
|
10
|
|
(29)
|
(43)
|
|
Asset and investment
impairment loss
|
(13)
|
—
|
|
(13)
|
—
|
|
Project development
and transaction costs
|
(2)
|
(54)
|
|
(197)
|
(81)
|
|
Employee severance
and restructuring costs
|
(49)
|
(62)
|
|
(292)
|
(92)
|
Total
adjustments
|
(72)
|
(123)
|
|
(114)
|
201
|
Loss before
interest, income taxes, depreciation and
amortization
|
(149)
|
(207)
|
|
(337)
|
(101)
|
APPENDIX C
NON-GAAP RECONCILIATION – CASH PROVIDED BY OPERATING ACTIVITIES TO
DCF
|
|
|
Three months
ended
December 31,
|
|
Year ended
December 31,
|
|
|
2017
|
2016
|
|
2017
|
2016
|
(millions of
Canadian dollars)
|
|
|
|
|
|
|
Cash provided by
operating activities
|
|
1,341
|
1,058
|
|
6,584
|
5,211
|
Adjusted for changes
in operating assets and liabilities1
|
|
461
|
272
|
|
412
|
362
|
|
|
1,802
|
1,330
|
|
6,996
|
5,573
|
Distributions to
noncontrolling interests and redeemable
noncontrolling interests2
|
|
(272)
|
(236)
|
|
(1,042)
|
(922)
|
Preference share
dividends
|
|
(84)
|
(76)
|
|
(330)
|
(293)
|
Maintenance capital
expenditures3
|
|
(345)
|
(205)
|
|
(1,261)
|
(671)
|
Significant adjusting
items:
|
|
|
|
|
|
|
|
Pre-issuance hedge
settlement4
|
|
431
|
—
|
|
431
|
—
|
|
Weather
normalization
|
|
—
|
7
|
|
—
|
13
|
|
Other receipts of
cash not recognized in revenue5
|
|
25
|
36
|
|
196
|
249
|
|
Project development
and transaction costs
|
|
9
|
44
|
|
210
|
74
|
|
Realized inventory
revaluation allowance6
|
|
(17)
|
1
|
|
(56)
|
(345)
|
|
Employee severance,
transition and restructuring costs
|
|
81
|
43
|
|
359
|
73
|
|
Other
items
|
|
111
|
(65)
|
|
111
|
(38)
|
Distributable cash
flow
|
|
1,741
|
879
|
|
5,614
|
3,713
|
1
|
Changes in
operating assets and liabilities include changes in environmental
liabilities, net of recoveries.
|
2
|
Presented net of
adjusting items.
|
3
|
Maintenance
capital expenditures are expenditures that are required for the
ongoing support and maintenance of the existing pipeline system or
that are necessary to maintain the service capability of the
existing assets (including the replacement of components that are
worn, obsolete or completing their useful lives). For the purpose
of DCF, maintenance capital excludes expenditures that extend asset
useful lives, increase capacities from existing levels or reduce
costs to enhance revenues or provide enhancements to the service
capability of the existing assets.
|
4
|
Related to
termination of interest rate swaps as not highly probable to issue
long-term debt.
|
5
|
Consists of cash
received net of revenue recognized for contracts under make-up
rights and similar deferred revenue arrangements.
|
6
|
Realized inventory
revaluation allowance relates to losses on sale of previously
written down inventory for which there is an approximate offsetting
realized derivative gain in DCF.
|
FOR FURTHER INFORMATION PLEASE CONTACT:
Enbridge Inc. – Media
Suzanne Wilton
Toll Free: (888) 992-0997
Email: suzanne.wilton@enbridge.com
Enbridge Inc. – Investment Community
Jonathan Gould
Toll Free: (800) 481-2804
Email: jonathan.gould@enbridge.com
SOURCE Enbridge Inc.