Enbridge Inc. Reports Fourth Quarter 2017 Results
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 Year ended
December 31, 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 EBITDA(1) 2,963 1,762 10,317 6,902
Adjusted Earnings(1) 1,013 522 2,982 2,078
Adjusted Earnings per common share(1) 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 Year ended
December 31, 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, (1,823) 1,791 6,288 6,281
depreciation and amortization
=============================
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 Year ended
December 31, 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 EBITDA(1) 2,963 1,762 10,317 6,902
Maintenance Capital (345) (205) (1,261) (671)
Interest expense(1) (665) (403) (2,421) (1,545)
Current income tax(1) (49) (31) (154) (92)
Distributions to noncontrolling interests and (272) (236) (1,042) (922)
redeemable noncontrolling interests(1)
Cash distributions in excess of equity earnings(1) 118 67 279 183
Preference share dividends (84) (76) (330) (293)
Other receipts of cash not recognized in revenue(2) 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 Year ended
ended December 31,
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 Year ended
December 31, 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
Other(1) 292 213 1,075 872
------- --- --- ----- ---
Adjusted EBITDA(2) 1,482 1,355 5,484 5,327
================= ===== ===== ===== =====
Operating Data (average deliveries -
thousands of bpd)
------------------------------------
Canadian Mainline(3) 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 Year ended
December 31, 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 EBITDA(1) 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 Year ended
December 31, 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 EBITDA(1) 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 Gas(2)
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 Year ended
December 31, December 31,
------------ ------------
2017 2016 2017 2016
---- ---- ---- ----
(millions of Canadian
dollars)
Adjusted EBITDA(1) 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 Year ended
December 31, December 31,
------------ ------------
2017 2016 2017 2016
---- ---- ---- ----
(millions of Canadian dollars)
Adjusted earnings/(loss) before
interest, income taxes, (21) (4) (52) 30
depreciation and amortization(1)
-------------------------------
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 Year ended
December 31, 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, (77) (84) (223) (302)
depreciation and amortization(1)
===============================
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 B(1) 0.21340
Preference Shares, Series C(2) 0.20342
Preference Shares, Series D 0.25000
Preference Shares, Series F 0.25000
Preference Shares, Series H 0.25000
Preference Shares, Series J(3) 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 Year ended
December 31, 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, (1,823) 1,791 6,288 6,281
depreciation and amortization
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 226 (406) (407) (240)
redeemable noncontrolling interests
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 Year ended
December 31, 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 (212) (61) (743) (226)
interests
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 Year ended
December 31, December 31,
------------ ------------
2017 2016 2017 2016
---- ---- ---- ----
(millions of Canadian dollars, except per share amounts)
Earnings/(loss) before interest, income taxes, (1,823) 1,791 6,288 6,281
depreciation and amortization
-----------------------------
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, 2,963 1,762 10,317 6,902
depreciation and amortization
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 226 (406) (407) (240)
redeemable noncontrolling interests
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 Year ended
December 31, December 31,
------------ ------------
2017 2016 2017 2016
---- ---- ---- ----
(millions of Canadian dollars)
Adjusted earnings before interest, income taxes, 1,482 1,355 5,484 5,327
depreciation and amortization
-----------------------------
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 1,555 1,733 6,395 4,926
and amortization
================
GAS TRANSMISSION AND MIDSTREAM
Three months
ended Year ended
December 31, December 31,
------------ ------------
2017 2016 2017 2016
---- ---- ---- ----
(millions of Canadian
dollars)
Adjusted earnings before
interest, income taxes, 1,020 166 3,350 659
depreciation and
amortization
----------------
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, (3,532) 95 (1,269) 464
depreciation and
amortization
================
GAS DISTRIBUTION
Three months ended Year ended
December 31, December 31,
------------ ------------
2017 2016 2017 2016
---- ---- ---- ----
(millions of Canadian dollars)
Adjusted earnings before interest, income taxes, 450 238 1,379 833
depreciation and amortization
-----------------------------
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 453 238 1,390 831
and amortization
================
GREEN POWER AND TRANSMISSION
Three months
ended Year ended
December 31, December 31,
------------ ------------
2017 2016 2017 2016
---- ---- ---- ----
(millions of
Canadian
dollars)
Adjusted
earnings
before
interest,
income
taxes, 109 91 379 355
depreciation
and
amortization
-------------
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 102 78 372 344
and
amortization
=============
ENERGY SERVICES
Three months
ended Year ended
December 31, December 31,
------------ ------------
2017 2016 2017 2016
---- ---- ---- ----
(millions of Canadian
dollars)
Adjusted earnings/(loss)
before interest, income
taxes, (21) (4) (52) 30
depreciation and
amortization
----------------
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 (252) (146) (263) (183)
amortization
============
ELIMINATIONS AND OTHER
Three months
ended Year ended
December 31, December 31,
------------ ------------
2017 2016 2017 2016
---- ---- ---- ----
(millions of Canadian
dollars)
Adjusted loss before
interest, income taxes,
depreciation (77) (84) (223) (302)
and amortization
----------------
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 (149) (207) (337) (101)
amortization
============
APPENDIX C
NON-GAAP RECONCILIATION - CASH PROVIDED BY OPERATING ACTIVITIES TO DCF
Three months
ended Year ended
December 31, 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
liabilities(1) 461 272 412 362
----------------------- --- --- --- ---
1,802 1,330 6,996 5,573
Distributions to
noncontrolling interests
and redeemable (272) (236) (1,042) (922)
noncontrolling interests(2)
Preference share dividends (84) (76) (330) (293)
Maintenance capital
expenditures(3) (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.
