CALGARY, Feb. 14, 2020 /CNW/ - Enbridge Inc.
(Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported
fourth quarter and full year 2019 financial results and provided a
quarterly business update.
HIGHLIGHTS
(all financial figures are unaudited and
in Canadian dollars unless otherwise noted)
- Full year GAAP earnings of $5,322
million or $2.64 per common
share compared with $2,515 million or
$1.46 per common share for 2018
- Adjusted earnings of $5,341
million or $2.65 per common
share in 2019 compared with $4,568
million or $2.65 per common
share for 2018
- Adjusted earnings before interest, income tax and depreciation
and amortization (EBITDA) of $13,271
million in 2019 compared with $12,849
million for 2018
- Cash Provided by Operating Activities of $9,398 million in 2019 compared with $10,502 million for 2018
- Distributable Cash Flow (DCF) of $9,224
million in 2019 compared with $7,618
million for 2018
- Achieved the top-end of full-year DCF per share guidance range
of $4.30 to $4.60
- Reaffirmed 2020 DCF per share guidance range of $4.50 to $4.80, and
longer term 5 to 7% DCF per share growth outlook, within an equity
self-funding model
- Increased the quarterly dividend by 9.8% for 2020 to
81 cents per share, reflecting strong
operating and financial performance and the Company's outlook
- Delivered 100 thousand barrels per day (kbpd) of planned
Mainline optimizations, providing much needed egress capacity for
Western Canadian producers
- Placed $7 billion of new projects
into service in the fourth quarter, including the US$0.7 billion investment in the Gray Oak
pipeline, the $1.1 billion
German Hohe See offshore wind
project, and the Canadian segment of the Line 3 Replacement
project, under an interim surcharge agreement
- Filed regulatory application in support of contracting the
Liquids Mainline System on December
19, with support from shippers representing over 70% of
current throughput
- Minnesota Public Utilities Commission (MPUC) re-certified the
Line 3 Replacement project Final Environmental Impact Statement
(FEIS), the Certificate of Need and the Route Permit on
February 3, 2020
- Advanced LNG supply strategy with the announcement of agreement
to expand our system to supply the Annova LNG facility in the Port
of Brownsville, Texas, and
agreements to acquire the Rio
Bravo pipeline development project and supply the Rio Grande
LNG facility
- Closed second phase of the Canadian midstream sale,
successfully concluding previously announced $8 billion asset sale program; achieved 4.5x
Debt/EBITDA at year end
- Announced the $0.2 billion sale
of the Montana-Alberta Tie Line (MATL); further increasing
financial flexibility
CEO COMMENT
"2019 was a successful year for Enbridge", commented
Al Monaco, President and Chief
Executive Officer of Enbridge. "Our low risk pipeline-utility model
continued to deliver strong financial results and we advanced our
strategic priorities on many fronts.
"Each of our core businesses delivered solid results in 2019
that translated into full-year DCF per share at the top-end of our
guidance range. The Liquids Mainline System achieved record annual
throughput, our gas pipelines were highly utilized, and we're
capturing synergies through the amalgamation of our Ontario Utility
businesses. In addition to strong business performance, we placed a
further $9 billion of new projects
into service, including the Canadian segment of the Line 3
Replacement. Our focus on optimizing our base business and
executing on our secured growth program continues to drive highly
predictable and growing cash flows, which resulted in exceptional
annual dividend growth for our shareholders of 10% in 2019 and 9.8%
in 2020.
"Despite strong utilization and financial performance across our
businesses, we experienced a major incident on our natural gas
system in Kentucky. The safety of
our systems is always our number one priority and we're re-doubling
our efforts to ensure our pipelines continue to be the safest in
the industry.
"In the Liquids Pipeline segment, we delivered on our plan for
100 kbpd of throughput optimizations on the Mainline system by the
end of 2019. We're planning for a further 50 kbpd of Mainline
optimizations and we're moving forward with a 50 kbpd expansion of
the Express Pipeline in 2020. These actions will provide WCSB
producers with at least 200 kbpd of much needed additional pipeline
capacity.
"On the U.S. portion of our Line 3 Replacement Project, on
February 3 the MPUC approved the FEIS
and reinstated the Certificate of Need and Route Permit. This
important decision by the MPUC reflects the most comprehensive
review of a pipeline project in Minnesota history and reaffirms the need for
the pipeline to be replaced. We'll continue to work closely with
State and Federal permitting agencies to secure all necessary
permits prior to commencing construction.
"In addition, following almost two years of extensive
negotiation with our shippers, we filed the Mainline Contract
Offering with the Canada Energy Regulator (CER). The priority
access offering is in direct response to what our shippers have
asked us for and balances their diverse needs. Ultimately,
contracting the Mainline will provide all shippers with priority
access at competitive tolls, and supports further improvement in
netbacks for WCSB producers. Most notably, it secures long-term
demand for Canadian crude oil, while ensuring that all interested
shippers can participate in a fair and transparent open season
process. For example, we've made this offering accessible to
smaller producers by reducing the minimum volume required to
contract on the system and introducing a Requirements Contract with
very attractive terms. We expect the CER will conduct a thorough
review of our application which will include input from Enbridge
and the industry. Importantly, we included in our application 13
letters from the shippers representing well over 70 percent of the
Mainline volumes to demonstrate the support we have for the
offering.
"We've also been advancing our liquids strategy to extend our
integrated value chain from Western
Canada down to the U.S. Gulf Coast. We're moving ahead with
developing a terminal at Jones Creek, Texas, which will be fully integrated with our
Seaway pipeline system and will provide connectivity and services
to local refineries as well as export facilities. We've also
secured an option to purchase an ownership interest in an offshore
VLCC-capable oil export terminal, further advancing our energy
export strategy in the U.S. Gulf Coast.
"Our Gas Transmission and Midstream business is awaiting a
decision from the FERC on a settlement agreement on the Texas
Eastern rate case and are entering rate proceedings on several
other pipelines this year. These are important milestones as they
will allow us to rebase our rates and set us up for recovery of
future modernization costs.
"Also, in Gas Transmission and Midstream, we've again advanced
our LNG supply strategy by leveraging our incumbent position in the
U.S. Gulf Coast, with the announcement of the agreements to supply
both the Annova LNG facility and the Rio Grande LNG facility, along
with acquiring the Rio Bravo
pipeline development project.
Finally, in the fourth quarter, we closed the second phase of
the divestiture of our Canadian midstream assets, which completes
our $8 billion asset sale program.
These non-core asset sales have further strengthened our balance
sheet and focused our business on our low risk pipeline-utility
model.
"In summary, we're pleased with the Company's performance in
2019 and the successful completion of the 3-year plan we announced
in early 2017 following the Spectra merger. As we look ahead to our
new 3-year plan through 2022, our strategic priorities for the
business remain focused on optimizing our base business, executing
our secured growth program and growing the business through
in-franchise, capital efficient investment. The combination of our
strong financial position, disciplined capital allocation, and
low-risk business model, positions us well to sustain attractive
shareholder returns well into the future," concluded Mr.
Monaco.
FINANCIAL RESULTS SUMMARY
Financial results for the three and twelve months ended
December 31, 2019, are summarized in
the table below:
|
|
|
|
|
Three months
ended
December 31,
|
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars, except per share
amounts;
|
|
|
|
|
|
number of shares in
millions)
|
|
|
|
|
|
GAAP Earnings
attributable to common shareholders
|
746
|
1,089
|
|
5,322
|
2,515
|
GAAP Earnings per
common share
|
0.37
|
0.60
|
|
2.64
|
1.46
|
Cash provided by
operating activities
|
1,993
|
2,503
|
|
9,398
|
10,502
|
Adjusted
EBITDA1
|
3,186
|
3,320
|
|
13,271
|
12,849
|
Adjusted
Earnings1
|
1,228
|
1,166
|
|
5,341
|
4,568
|
Adjusted Earnings per
common share1
|
0.61
|
0.65
|
|
2.65
|
2.65
|
Distributable Cash
Flow1
|
2,051
|
1,863
|
|
9,224
|
7,618
|
Weighted average
common shares outstanding
|
2,018
|
1,806
|
|
2,017
|
1,724
|
1
|
Non-GAAP financial
measures. Schedules reconciling adjusted EBITDA, adjusted earnings,
adjusted earnings per common share and distributable cash flow are
available as Appendices to this news release.
|
GAAP earnings attributable to common shareholders for the fourth
quarter of 2019 decreased by $343
million or $0.23 per share
compared with the same period in 2018. The period-over-period
comparability of earnings attributable to common shareholders was
impacted by certain unusual, infrequent factors or other
non-operating factors, which are noted in the reconciliation
schedule included in Appendix A of this news release.
Adjusted earnings in the fourth quarter 2019 increased by
$62 million. The increase was
primarily driven by strong operating results across many of the
Company's business units and from new projects placed into service
in 2019, partially offset by weaker performance in Energy Services
due to the narrowing of certain location and quality differentials.
On a per share basis, adjusted earnings decreased by $0.04 per share compared with the same period in
2018, reflecting the same operating factors noted above, partially
offset by a higher share count which reflected common shares issued
by the Company to buy-in the public interests in its sponsored
vehicles during the fourth quarter of 2018.
Adjusted earnings for the year ended 2019 increased by
$773 million compared with the year
ended 2018. The increase is primarily due to strong operating
results across many of the Company's business units, as well as new
projects placed into service in 2019 and in late 2018. These
factors were partially offset by the disposition of certain Gas
Transmission and Midstream assets, which included the provincially
regulated portion of the Canadian natural gas gathering and
processing assets sold on October 1,
2018, as well as the disposition of Midcoast Operating,
L.P., sold on August 1, 2018.
DCF for the fourth quarter was $2,051
million, an increase of $188
million over the comparable prior period in 2018, while DCF
for the year ended 2019 was $9,224
million, which is an increase of $1,606 million over 2018. The increased DCF in
2019 for both the fourth quarter and full year over the comparable
periods in 2018 was driven largely by the operating factors noted
above, as well as lower distributions to noncontrolling interests
following the completion of the Company's buy-in of the publicly
held interest in its sponsored vehicles.
Detailed segmented financial information and analysis can be
found below under Adjusted EBITDA by Segments.
PROJECT EXECUTION UPDATE
Over the course of 2019, the Company placed $9 billion of secured growth projects into
service, including $7 billion in the
fourth quarter. These projects further strengthen Enbridge's
footprint in all business lines, including enhancing the safety of
the Liquids Mainline, advancing the Company's U.S. Gulf Coast
Liquids competitive position, expanding and extending its gas
pipelines, completing its largest offshore wind project in
Europe, and investing in its
Utilities business to reinforce the distribution system and connect
new customers. The successful execution of the Company's secured
growth program in 2019 contributes reliable earnings and cash flow
growth and advances the Company's strategic priorities.
In the fourth quarter, several projects were placed into
service, including:
- A US$0.7 billion investment in
the Gray Oak Pipeline, which provides incremental crude pipeline
capacity out of the Eagle Ford and Permian basins and is
underpinned by long-term take-or-pay transportation contracts.
- The $1.1 billion HoHe See
Offshore Wind Project and adjacent expansion, which are both fully
operational with a combined capacity of 609MW, and are fully back
stopped by a government legislated 20-year revenue support
mechanism.
- The $5.0 billion Canadian segment
of the Line 3 Replacement project (discussed in the Line 3
Replacement section).
Enbridge continues to make progress on its $11 billion secured growth capital program, which
includes projects at various stages of execution across all
businesses. 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
regulatory jurisdictions.
U.S. Gulf Coast LNG Strategy
Enbridge announced yesterday that it had executed a Purchase and
Sale Agreement with NextDecade to acquire the Rio Bravo Pipeline
development project. In addition, Enbridge and NextDecade have
negotiated a precedent agreement, to be executed at closing, under
which Enbridge will provide firm transportation capacity on the Rio
Bravo Pipeline to NextDecade's Rio Grande LNG export facility for a
term of at least twenty years. The capital cost of the pipeline is
approximately US$1.2 billion with
opportunities for further expansion, subject to FID and the final
design specifications for the LNG facility.
The Company also announced that it has signed a Precedent
Agreement to supply the Annova LNG facilities in the Port of
Brownsville, Texas for a term of
at least twenty years, by expanding Enbridge's existing Valley
Crossing system. The expansion will be subject to the Annova
facility reaching FID. The capital cost of the expansion is
expected to be approximately US$0.5
billion subject to the final design specifications of the
LNG facility.
Line 3 Replacement
The $9 billion Line 3 Replacement
Project is a significant component of the Company's secured project
inventory. It is a critical integrity replacement project that will
enhance the safety and reliability of Enbridge's Liquids Mainline
System.
The Company placed the Canadian segment of the Line 3
Replacement into service on December 1,
2019, with an interim surcharge of US$0.20 per barrel. This safety-driven
maintenance project reflects the importance of protecting the
environment and ensuring the continued safe and reliable operations
of our Canadian Mainline System well into the future. The capital
cost for the Canadian portion of Line 3 Replacement Project came in
slightly below budget.
In Minnesota, the Department of
Commerce issued a FEIS on December 9
and the MPUC gathered public comment through January 16, 2020. On February 3, 2020, the MPUC approved the adequacy
of the FEIS and reinstated the Certificate of Need and Route
Permit, clearing the way for construction of the pipeline to
commence following the issuance of required permits. The State and
Federal environmental permitting agencies have continued to advance
their work, including the initiation of public consultation
processes, in parallel with the ongoing MPUC process.
Depending on the final in-service date, there is a risk that the
project may exceed the Company's total cost estimate of
$9 billion for the combined Line 3
Replacement Project. However, at this time, the Company does not
anticipate any capital cost impacts that would be material to
Enbridge's financial position and outlook.
OTHER BUSINESS UPDATES
Mainline Contracting
On December 19, 2019, the Company
submitted an application to the CER to implement term contracts on
the Liquids Canadian Mainline System. The application for
contracted and uncommitted service included the associated terms,
conditions and tolls of each service, which would be offered in an
open season following approval by the CER. The tolls and services
will replace the current Competitive Toll Settlement (CTS) that is
in place until June 30, 2021. If a
replacement agreement is not in place by that time, the CTS tolls
will continue on an interim basis.
The application that the Company filed is the result of two
years of extensive negotiations with a diverse group of shippers
and has been designed to align the interests of its shippers and
Enbridge. Shippers representing well over 70% of the current
Mainline system throughput have filed letters supporting the
application with the CER demonstrating the strong shipper backing
for the offering.
The application highlights benefits of the Mainline contract
offering for both shippers and the public, including the
following:
- Secures long-term demand for WCSB heavy and light barrels in
premium markets;
- Supports the best netbacks for WCSB producers;
- Competitive and stable tolls for customers; and
- Flexibility for shippers of all types and sizes to participate
by offering both a traditional take-or-pay and producer and refiner
requirements contracts.
On January 16, 2020, the CER
issued a letter inviting comments from interested persons to
identify issues to be considered during the regulatory proceeding
and on procedural matters, such as processes the CER may establish
to consider the application efficiently. On February 7, 2020, Enbridge replied to the letters
solicited by the CER and we expect a thorough regulatory process to
continue through substantially all of 2020.
Line 5 Tunnel
On October 31, 2019, the Michigan Court of Claims ruled in favor of
Enbridge, recognizing the constitutionality of the legislation
underpinning the tunnel agreement with the State of Michigan. As part of Enbridge's
agreement with the State of
Michigan, the Company plans to replace its existing Line 5
dual pipelines at the Straits of Mackinac with a pipeline secured in an
underground tunnel, deep under the Straits, making a safe pipeline
even safer. This state-of-the-art tunnel, with enhanced safety
features, demonstrates Enbridge's commitment to protecting
Michigan's natural resources.
Enbridge plans to begin filing permit applications with the State
to proceed with constructing the tunnel across the Line 5 Straits
in the first quarter of 2020.
Gas Transmission and Midstream Rate Cases
One of the Company's strategic priorities is to ensure timely and
fair returns on the Company's U.S. natural gas transmission
systems. Following extensive negotiations with shippers on the
Texas Eastern rate case, Enbridge filed a settlement agreement on
October 28, 2019, with the FERC. On
January 13, 2020, the Administrative
Law Judge certified this uncontested settlement agreement to the
FERC and the Company expects a decision from the FERC in the second
quarter of 2020. The Company has also commenced rate discussions
with Algonquin and East Tennessee Natural Gas customers. If a
pre-packaged settlement on these pipelines is not reached,
Algonquin will file a Section 4 rate case by March 31, 2020, and East Tennessee will file in the second quarter
of this year. Additionally, rate proceedings are planned on
the Alliance U.S. pipeline and on Maritimes and Northeast U.S.
pipeline in the second quarter of 2020.
NON-CORE ASSET SALES & FINANCING UPDATE
In December 2019, Enbridge closed
the sale of its federally regulated Canadian midstream assets,
completing the second phase of the $4.3
billion transaction. In aggregate, the Company has now
received total proceeds of approximately $8
billion from previously announced non-core asset sales. In
addition to that, in January 2020,
Enbridge entered into an agreement for the sale of the MATL
transmission assets for $0.2 billion
subject to certain regulatory approvals and customary closing
conditions. The transaction is expected to close in the first
quarter of 2020. These sales provide the Company with further
financial flexibility to self-fund its secured growth program.
On the financing front, the Company continued to execute on its
funding plan with term debt issuances in the fourth quarter
exceeding $3.5 billion. These
included a $1 billion single tranche
offering of 10-year notes by Enbridge Inc. in the Canadian debt
capital markets and a US$2 billion
three-tranche offering of 5-year, 10-year and 30-year fixed rate
notes in the U.S. debt capital markets. Proceeds were used to
re-finance maturing debt and fund new growth projects within the
Company's financial capacity.
As of December 31, 2019, the
Company's consolidated Debt-to-EBITDA ratio was 4.5x on a trailing
twelve month basis. This is at the low end of the Company's
long-term target credit metric range of 4.5x to below 5.0x
Debt-to-EBITDA.
2020 GUIDANCE AND LONGER TERM GROWTH OUTLOOK
At its
December 2019 investor conference the
Company highlighted that its key strategic priorities are focused
on optimizing existing operations while preserving financial
flexibility and prudently growing its three world-class core
franchises: Liquids Pipelines, Gas Transmission and Midstream, and
Gas Distribution and Storage. Specific priorities include:
- Ensuring safe and reliable operations and providing effective
and cost-efficient transportation solutions for customers;
- Enhancing the business through asset optimization, cost
efficiencies and low-risk growth;
- Executing on an $11 billion
secured growth capital program, including the U.S. segment of the
Line 3 Replacement project; and
- Growing core businesses through capital efficient organic
growth and disciplined capital allocation.
Enbridge provided its financial guidance for 2020 including
EBITDA of approximately $13.7 billion
and a projected range of 2020 DCF of $4.50 to $4.80 per
share. The Company also announced a 9.8% dividend increase for 2020
to a quarterly dividend of $0.81 per
share, commencing with the dividend payable on March 1, 2020, to shareholders of record on
February 14, 2020. Post 2020, the
Company re-affirmed expected annual DCF per share growth rate in
the range of 5-7%, driven by a operating efficiencies and a
significant opportunity to invest in new low risk growth projects
within its core franchises.
FOURTH QUARTER AND YEAR-END 2019 FINANCIAL RESULTS
The following table summarizes 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 of 2019.
GAAP SEGMENT EBITDA AND CASH FLOW FROM OPERATIONS
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Liquids
Pipelines
|
1,971
|
978
|
7,681
|
5,331
|
Gas Transmission and
Midstream
|
638
|
1,254
|
3,371
|
2,334
|
Gas Distribution and
Storage
|
443
|
449
|
1,747
|
1,711
|
Renewable Power
Generation
|
(189)
|
83
|
111
|
369
|
Energy
Services
|
(68)
|
374
|
250
|
482
|
Eliminations and
Other
|
114
|
(340)
|
429
|
(708)
|
EBITDA
|
2,909
|
2,798
|
13,589
|
9,519
|
|
|
|
Earnings
attributable to common shareholders
|
746
|
1,089
|
5,322
|
2,515
|
|
|
|
Cash provided by
operating activities
|
1,993
|
2,503
|
9,398
|
10,502
|
For purposes of evaluating performance, the Company makes
adjustments for unusual, infrequent or other non-operating factors
to GAAP reported earnings, segment EBITDA, and cash flow provided
by operating activities, which allow Management and investors to
more accurately compare the Company's performance across periods,
normalizing for factors that are not indicative of the underlying
business performance. Tables incorporating these adjustments follow
below. Schedules reconciling EBITDA, adjusted EBITDA, adjusted
EBITDA by segment, adjusted earnings, adjusted earnings per share
and DCF to their closest GAAP equivalent are provided in the
Appendices to this news release.
DISTRIBUTABLE CASH FLOW
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
Liquids
Pipelines
|
1,720
|
1,728
|
7,041
|
6,617
|
Gas Transmission and
Midstream
|
948
|
952
|
3,868
|
4,068
|
Gas Distribution and
Storage
|
481
|
452
|
1,819
|
1,726
|
Renewable Power
Generation
|
119
|
98
|
424
|
435
|
Energy
Services
|
(22)
|
73
|
269
|
167
|
Eliminations and
Other
|
(60)
|
17
|
(150)
|
(164)
|
Adjusted
EBITDA1,3
|
3,186
|
3,320
|
13,271
|
12,849
|
Maintenance
capital
|
(342)
|
(361)
|
(1,083)
|
(1,144)
|
Interest
expense1
|
(704)
|
(675)
|
(2,716)
|
(2,735)
|
Current income
tax1
|
(81)
|
(156)
|
(386)
|
(384)
|
Distributions to
noncontrolling interests and redeemable
|
|
|
|
|
noncontrolling
interests1
|
(54)
|
(281)
|
(204)
|
(1,182)
|
Cash distributions in
excess of equity earnings1
|
107
|
51
|
534
|
318
|
Preference share
dividends
|
(96)
|
(96)
|
(383)
|
(364)
|
Other receipts of
cash not recognized in revenue2
|
30
|
51
|
169
|
208
|
Other non-cash
adjustments
|
5
|
10
|
22
|
52
|
DCF3
|
2,051
|
1,863
|
9,224
|
7,618
|
Weighted average
common shares outstanding
|
2,018
|
1,806
|
2,017
|
1,724
|
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.
|
3
|
Schedules
reconciling adjusted EBITDA and DCF are available as Appendices to
this news release.
|
Fourth quarter 2019 DCF increased $188
million compared with the same period of 2018. Key
performance drivers of quarter-over-quarter growth included:
- Adjusted EBITDA reflected strong operating performance,
increased asset utilization and contributions from assets placed
into service in late 2018 and through 2019, offset by the absence
of contributions from the sale of assets in the Gas Transmission
and Midstream segment during 2018, as well as lower EBITDA from
Energy Services crude operations due to narrowing of certain
location and quality differentials during the fourth quarter.
- Lower distributions to noncontrolling and redeemable
noncontrolling interests following the completion of Enbridge's
buy-in of the publicly held interests in its sponsored vehicles,
which were completed in the fourth quarter of 2018.
- Higher cash distributions in excess of equity earnings from
equity investments primarily due to higher distributions as a
result of strong performance, as well as new equity investments
placed into service, including the Valley Crossing Pipeline, the
NEXUS Gas Transmission Pipeline, and the Big Foot Pipeline.
DCF increased $1,606 million for
the year ended December 31, 2019,
compared to the year ended December 31,
2018, due to the same factors discussed above as well
as:
- Increased adjusted EBITDA contributions from Energy Services
for the year 2019 when compared to 2018 due to the widening of
certain location and quality differentials benefiting the first
half of 2019.
ADJUSTED
EARNINGS
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
Adjusted
EBITDA2
|
3,186
|
3,320
|
13,271
|
12,849
|
Depreciation and
amortization
|
(865)
|
(794)
|
(3,391)
|
(3,246)
|
Interest
expense1
|
(687)
|
(656)
|
(2,649)
|
(2,637)
|
Income
taxes1
|
(237)
|
(421)
|
(1,381)
|
(1,122)
|
Noncontrolling
interests and redeemable
|
|
|
|
|
noncontrolling
interests1
|
(73)
|
(188)
|
(126)
|
(909)
|
Preference share
dividends
|
(96)
|
(95)
|
(383)
|
(367)
|
Adjusted
earnings2
|
1,228
|
1,166
|
5,341
|
4,568
|
Adjusted earnings
per common share
|
0.61
|
0.65
|
2.65
|
2.65
|
1
|
Presented net of
adjusting items.
|
2
|
Schedules
reconciling adjusted EBITDA and adjusted earnings are available as
Appendices to this news release.
|
Adjusted earnings increased $62
million for the fourth quarter of 2019 compared with the
same period in 2018. Growth in adjusted earnings was driven by the
same factors impacting business performance and adjusted EBITDA as
discussed under Distributable Cash Flow above, partially
offset by the following factors:
- Higher depreciation and amortization expense as a result of new
assets placed into service, net of depreciation expense no longer
recorded for assets which were classified as assets held for sale
or sold during second half of 2018.
- Higher interest expense due to the absence of capitalized
interest related to assets that were placed into service in late
2018 and 2019.
- Lower income taxes due to lower adjusted earnings before tax
for the fourth quarter of 2019 when compared with the fourth
quarter of 2018.
Adjusted earnings per share for the fourth quarter of 2019
decreased $0.04 compared with the
fourth quarter of 2018. The increase in adjusted earnings noted
above was more than offset on a per share basis by the issuance
during the fourth quarter of 2018 of approximately 297 million
common shares to acquire, in separate transactions, all of the
outstanding equity securities of the Company's sponsored vehicles
not beneficially owned by Enbridge.
For the year ended December 31,
2019, adjusted earnings increased $773 million over the same period in 2018. The
increase is primarily driven by the increased adjusted EBITDA from
strong asset performance, as well as lower distributions to
noncontrolling and redeemable noncontrolling interests following
the completion of Enbridge's buy-in of the publicly held interests
in its sponsored vehicles as discussed under Distributable Cash
Flow above. The increase to adjusted earnings was offset by
increased income tax expense, in part due to higher earnings before
tax and a higher effective income tax rate. The period-over-period
increase in the effective income tax rate is partly due to the
buy-in of the U.S. Master Limited Partnerships (MLP), Enbridge
Energy Partners, L.P. and Spectra Energy Partners, LP, which
resulted in the Company being taxed on 100% of the MLP earnings
rather than the Company's proportionate share of their
earnings.
Adjusted earnings per share for the year of 2019 are the same as
in 2018 as a result of the increased adjusted earnings discussed
above being offset on a per share basis by the increase in common
shares issued to acquire the outstanding equity securities of the
Company's sponsored vehicles, also discussed above.
ADJUSTED EBITDA BY SEGMENTS
Adjusted EBITDA by segment is reported on a Canadian dollar
basis. Adjusted EBITDA generated from U.S. dollar
denominated businesses was translated at the same average Canadian
dollar exchange rates in the fourth quarter of 2019 (C$1.32/US$) when compared with the corresponding
2018 period (C$1.32/US$).
On a full year basis, adjusted EBITDA generated from U.S. dollar
denominated businesses for the year ended December 31, 2019, was translated at a weaker
Canadian exchange rate of C$1.33/US$ compared with
C$1.30/US$ for the year ended
December 31, 2018.
A portion of the U.S. dollar earnings is 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,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Mainline
System1
|
960
|
997
|
3,900
|
3,847
|
Regional Oil Sands
System
|
208
|
209
|
856
|
851
|
Gulf Coast and
Mid-Continent System
|
214
|
201
|
922
|
709
|
Other2
|
338
|
321
|
1,363
|
1,210
|
Adjusted
EBITDA3
|
1,720
|
1,728
|
7,041
|
6,617
|
|
|
|
|
|
Operating Data
(average deliveries – thousands of bpd)
|
|
|
|
|
Mainline System -
ex-Gretna volume4
|
2,728
|
2,685
|
2,705
|
2,631
|
Regional Oil Sands
System5
|
1,864
|
1,856
|
1,817
|
1,830
|
International Joint
Tariff (IJT)6
|
$4.21
|
$4.15
|
$4.18
|
$4.11
|
1
|
Mainline System
includes the Canadian Mainline and the Lakehead System, which were
previously reported separately.
|
2
|
Included within
Other are Southern Lights Pipeline, Express-Platte System, Bakken
System and Feeder Pipelines & Other.
|
3
|
Schedules
reconciling adjusted EBITDA are provided in the Appendices to this
news release.
|
4
|
Mainline System
throughput volume represents mainline system deliveries ex-Gretna,
Manitoba which is made up of United States and eastern Canada
deliveries originating from Western Canada.
|
5
|
Volumes are for
the Athabasca mainline, Athabasca Twin, Waupisoo Pipeline and
Woodland Pipeline and exclude laterals on the Regional Oil Sands
System.
|
6
|
The IJT benchmark
toll and its components are set in U.S. dollars and the majority of
the Company's foreign exchange risk on the Canadian portion of the
Mainline is hedged. The Canadian portion of the Mainline represents
approximately 45% of total Mainline System revenue and the average
effective FX rate for the Canadian portion of the Mainline during
the fourth quarter of 2019 as well as full year, was C$1.19/US$ (Q4
and full year 2018: C$1.26/US$).
The U.S. portion of the Mainline System is subject to FX
translation similar to the Company's other U.S. based businesses,
which are translated at the average spot rate for a given period. A
portion of this U.S. dollar translation exposure is hedged under
the Company's enterprise-wide financial risk management program.
The offsetting hedge settlements are reported within Eliminations
and Other.
|
Liquids Pipelines adjusted EBITDA decreased $8 million for the fourth quarter of 2019
compared with the same period of 2018. Key quarter-over-quarter
performance drivers included:
- Mainline System adjusted EBITDA reflected higher throughput,
driven by strong supply and continued optimizations of the system,
as well as a higher period-over-period International Joint Toll
(IJT). In addition, the Canadian portion of the Line 3 Replacement
project was placed into service on December
1, 2019, with an interim surcharge on all mainline volumes
of US$0.20 per barrel. However, these
increases to EBITDA were more than offset by a lower foreign
exchange rate on contracts used to hedge U.S. dollar denominated
revenues from the Canadian portion of the Mainline System (2019:
C$1.19/US; 2018: C$1.26/US), as well as higher operating costs due
to timing of expenditures.
- Gulf Coast and Mid-Continent System growth was driven by strong
Gulf Coast demand resulting from favourable price differentials, as
well as modest contributions from the Gray Oak Pipeline project
that commenced service late in the fourth quarter of 2019, with
volume expected to ramp up in the first half of 2020.
Liquids Pipelines adjusted EBITDA increased $424 million for the year ended 2019 compared
with 2018. In addition to factors discussed above, key
year-over-year performance drivers included:
- Gulf Coast and Mid-Continent System growth was a result of
higher volumes on the Flanagan South and Seaway pipelines due to
strong Gulf Coast demand resulting from favourable price
differentials.
- Other EBITDA increased primarily due to increased volume
throughput on the Bakken Pipeline System driven by strong
production in the region.
GAS TRANSMISSION AND MIDSTREAM
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
US Gas
Transmission
|
678
|
646
|
2,730
|
2,625
|
Canadian Gas
Transmission1
|
191
|
208
|
760
|
983
|
US
Midstream
|
48
|
54
|
194
|
319
|
Other
|
31
|
44
|
184
|
141
|
Adjusted
EBITDA2
|
948
|
952
|
3,868
|
4,068
|
1
|
Canadian Gas
Transmission includes Alliance Pipeline, which was previously
reported separately.
|
2
|
Schedules
reconciling adjusted EBITDA are available as Appendices to this
news release.
|
Gas Transmission and Midstream adjusted EBITDA decreased
$4 million for the fourth quarter of
2019 compared with the same period of 2018. Key
quarter-over-quarter performance drivers included:
- US Gas Transmission adjusted EBITDA reflected a full quarter of
contributions from new assets placed into service in late 2018,
including Valley Crossing Pipeline and the NEXUS Gas Transmission
Pipeline. The increase in EBITDA was partially offset by higher
planned integrity expenditures, lower AFUDC on decreased capital
spend, as well as both lower revenues and higher operating costs
associated with the Texas Eastern pipeline incident in Lincoln County, Kentucky that occurred in the
third quarter of 2019.
- Canadian Gas Transmission adjusted EBITDA decreased
period-over-period due to a decrease in interruptible service
revenue in 2019 as a result of a weaker AECO-Chicago basis.
- US Midstream adjusted EBITDA primarily reflects the impact of
lower commodity prices on fractionation margins at Aux Sable
partially offset by higher volumes and more favourable margins at
DCP Midstream.
Gas Transmission and Midstream adjusted EBITDA decreased
$200 million for the year ended 2019
compared with 2018. In addition to factors discussed above, key
year-over-year performance included:
- Canadian Gas Transmission adjusted EBITDA period-over-period
results primarily reflect the absence of contributions from the
provincially regulated Canadian natural gas gathering and
processing business which was sold October
1, 2018. The sale of the remaining federally regulated
Canadian natural gas gathering and processing assets closed on
December 31, 2019.
- US Midstream adjusted EBITDA primarily reflects the absence of
EBITDA from Midcoast Operating, L.P. which was sold on August 1, 2018.
- Other EBITDA has increased in 2019 primarily due to
contributions from the Big Foot Pipeline which was placed into
service in the fourth quarter of 2018.
GAS DISTRIBUTION AND STORAGE
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Enbridge Gas Inc.
(EGI)
|
444
|
407
|
1,714
|
1,598
|
Other
|
37
|
45
|
105
|
128
|
Adjusted
EBITDA1
|
481
|
452
|
1,819
|
1,726
|
|
|
|
|
|
Operating
Data
|
|
|
|
|
EGI
|
|
|
|
|
Volumes (billions of
cubic feet)
|
532
|
531
|
1,860
|
1,821
|
Number of active
customers (thousands)2
|
|
|
3,755
|
3,713
|
Heating degree
days3
|
|
|
|
|
Actual
|
1,383
|
1,406
|
4,082
|
3,932
|
Forecast based on
normal weather4
|
1,314
|
1,310
|
3,849
|
3,843
|
1
|
Schedules
reconciling adjusted EBITDA are available as Appendices to this
news release.
|
2
|
Number of active
customers at the end of the reported period.
|
3
|
Heating degree
days is a measure of coldness that is indicative of volumetric
requirements for natural gas utilized for heating purposes in EGI's
distribution franchise areas.
|
4
|
As per Ontario
Energy Board approved methodology used in setting
rates.
|
Enbridge Gas Distribution (EGD) and Union Gas were amalgamated
on January 1, 2019. The amalgamated
company is named Enbridge Gas Inc. (EGI). Post amalgamation the
financial results of EGI reflect the combined performance of the
two legacy utility operations.
Gas Distribution and Storage adjusted EBITDA will typically
follow a seasonal profile. It is generally highest in the first and
fourth quarters of the year reflecting greater volumetric demand
during the heating season and lowest in the third quarter as there
is generally less volumetric demand during the summer. The
magnitude of the seasonal EBITDA fluctuations will vary from
year-to-year reflecting the impact of colder or warmer than normal
weather on distribution volumes.
Gas Distribution and Storage adjusted EBITDA increased
$29 million for the fourth quarter
2019 compared with the same period of 2018. Key
quarter-over-quarter performance drivers included:
- EGI adjusted EBITDA increased due to higher distribution
charges primarily resulting from increases in distribution rates
and customer base, synergies realized from the amalgamation of EGD
and Union Gas, as well as the absence of earnings sharing in 2019
which was recognized in 2018 under EGD's previous incentive rate
structure.
- These contributions were partially offset due to warmer weather
in EGI's franchise areas in the fourth quarter which led to lower
utilization, as well as the effects of the accelerated capital cost
allowance deductions reflected as a pass through to customers,
consistent with the Ontario Energy Board's prescribed deferral
account treatment.
- Other Gas Distribution and Storage adjusted EBITDA decreased
due to closing of the sale of Enbridge Gas New Brunswick on
October 1, 2019, and St. Lawrence Gas
Company, Inc. on November 1,
2019.
Gas Distribution and Storage adjusted EBITDA increased
$93 million for the year ended 2019
compared with 2018. The key year-over-year performance drivers
reflected the same factors discussed above in the fourth quarter
analysis as well as the impact of colder weather in EGI's franchise
areas in 2019 when compared to 2018, which drove higher demand.
For the year ended December 31,
2019, Adjusted EBITDA at EGI was positively impacted by
$67 million due to colder weather
experienced in the franchise area relative to the assumptions for
normal weather embedded in customer rates.
RENEWABLE POWER GENERATION
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA1
|
119
|
98
|
424
|
435
|
1
|
Shedules
reconciling adjusted EBITDA are available as Appendices to this
news release.
|
Renewable Power Generation adjusted EBITDA increased
$21 million for the fourth quarter of
2019 compared with the same period of 2018. Key
quarter-over-quarter performance drivers included:
- Higher adjusted EBITDA as a result of contributions from the
Hohe See Offshore Wind Project, which reached full operating
capacity in October 2019. The
adjacent expansion project, Albatros, came into service in
January 2020.
- Stronger wind resources across the Company's Canadian wind
facilities.
Renewable Power Generation adjusted EBITDA decreased
$11 million for the year ended 2019
compared with 2018. In addition to factors discussed above, key
year-over-year performance drivers included:
- Absence of a positive arbitration settlement of $11 million from a warranty claim that occurred
in the first quarter of 2018.
- Weaker wind resources, availability, and higher mechanical
repair costs primarily at US wind facilities in the first half of
2019, net of insurance recoveries.
ENERGY SERVICES
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
earnings/(loss) before interest, income
|
|
|
|
|
taxes, and
depreciation and amortization1
|
(22)
|
73
|
269
|
167
|
1
|
Schedules
reconciling adjusted EBITDA are available as Appendices to this
news release.
|
Energy Services adjusted EBITDA decreased $95 million for the fourth quarter of 2019
compared with the same period of 2018. Key quarter-over-quarter
performance drivers included:
- Lower EBITDA contributions from Energy Services crude
operations as a result of narrowing of certain location and quality
differentials during the fourth quarter.
Full year 2019 Adjusted EBITDA results for Energy Services
increased $102 million compared with
full year results of 2018 primarily due to higher EBITDA
contributions from Energy Services crude operations as a result of
widening of certain location and quality differentials during the
second half of 2018 and the first half of 2019, which increased
opportunities to generate profitable margins that were realized
during 2019.
ELIMINATIONS AND OTHER
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Operating and
administrative (expenses)/recoveries
|
(10)
|
82
|
66
|
55
|
Realized foreign
exchange hedge settlements
|
(50)
|
(65)
|
(216)
|
(219)
|
Adjusted
earnings/(loss) before interest, income
|
|
|
|
|
taxes, and
depreciation and amortization1
|
(60)
|
17
|
(150)
|
(164)
|
1
|
Schedules
reconciling adjusted EBITDA are available as Appendices to this
news release.
|
Operating and administrative costs captured in this segment
reflect the cost of centrally delivered services (including
depreciation of corporate assets) inclusive of amounts recovered
from business units for the provision of those services. Also, as
previously noted, U.S. dollar denominated earnings within the
segment results are translated at average foreign exchange rates
during the quarter. The offsetting impact of settlements made under
the Company's enterprise foreign exchange hedging program are
captured in this segment.
Eliminations and Other adjusted EBITDA decreased $77 million for the fourth quarter of 2019,
compared with the same period of 2018. Key quarter-over-quarter
performance drivers included:
- The timing of the recovery of certain operating and
administrative costs allocated to the business segments, partially
offset by lower operating and administrative costs.
- Lower realized foreign exchange settlement losses in the fourth
quarter of 2019 primarily due to a narrower spread between the
average exchange rate of $1.32 for
the fourth quarter of 2019 (Q4 2018:$1.32) and the fourth quarter 2019 hedge rate of
$1.24 (Q4 2018:$1.20).
Eliminations and Other adjusted EBITDA increased $14 million for the year ended 2019 compared with
the same period of 2018. This increase was a result of:
- Lower operating and administrative expenses.
- Lower realized foreign exchange settlement losses in 2019
primarily due to a narrower spread between the average exchange
rate of $1.33 for 2019
(2018:$1.30) and the 2019 hedge rate
of $1.24 (2018:$1.16).
CONFERENCE CALL
Enbridge will host a conference call and webcast on
February 14, 2020 at 9:00 a.m. Eastern Time (7:00
a.m. Mountain Time) to provide an enterprise wide business
update and review 2019 fourth quarter and full-year 2019 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 7174457#. The call will be audio
webcast live at https://edge.media-server.com/mmc/p/nkzon3c7. 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 7174457#).
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.
DIVIDEND DECLARATION
On December 9, 2019, the Company's
Board of Directors declared the following quarterly dividends. All
dividends are payable on March 1, 2020 to shareholders of
record on February 14, 2020.
Common
Shares1
|
$0.81000
|
Preference Shares,
Series A
|
$0.34375
|
Preference Shares,
Series B
|
$0.21340
|
Preference Shares,
Series C2
|
$0.25305
|
Preference Shares,
Series D
|
$0.27875
|
Preference Shares,
Series F
|
$0.29306
|
Preference Shares,
Series H
|
$0.27350
|
Preference Shares,
Series J
|
US$0.30540
|
Preference Shares,
Series L
|
US$0.30993
|
Preference Shares,
Series N
|
$0.31788
|
Preference Shares,
Series P3
|
$0.27369
|
Preference Shares,
Series R4
|
$0.25456
|
Preference Shares,
Series 1
|
US$0.37182
|
Preference Shares,
Series 35
|
$0.23356
|
Preference Shares,
Series 56
|
US$0.33596
|
Preference Shares,
Series 77
|
$0.27806
|
Preference Shares,
Series 98
|
$0.25606
|
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
|
$0.30625
|
1
|
The quarterly
dividend per common share was increased 9.8% to $0.81000 from
$0.73800, effective March 1, 2020.
|
2
|
The quarterly
dividend per share paid on Series C was decreased to $0.25395 from
$0.25459 on March 1, 2019, increased to $0.25647 from $0.25395 on
June 1, 2019, decreased to $0.25243 from $0.25647 on September 1,
2019, and increased to $0.25305 from $0.25243 on December 1, 2019,
due to reset on a quarterly basis following the date of issuance of
the Series C Preference Shares.
|
3
|
The quarterly
dividend per share paid on Series P was increased to $0.27369 from
$0.25000 on March 1, 2019, due to reset of the annual dividend on
March 1, 2019, and every five years thereafter.
|
4
|
The quarterly
dividend per share paid on Series R was increased to $0.25456 from
$0.25000 on June 1, 2019, due to the reset of the annual dividend
on June 1, 2019, and every five year thereafter.
|
5
|
The quarterly
dividend per share paid on Series 3 was decreased to $0.23356 from
$0.25000 on September 1, 2019, due to the reset of the annual
dividend on September 1, 2019, and every five year
thereafter.
|
6
|
The quarterly
dividend per share paid on Series 5 was increased to US $0.33596
from US $0.27500 on March 1, 2019, due to reset of the annual
dividend on March 1, 2019, and every five years
thereafter.
|
7
|
The quarterly
dividend per share paid on Series 7 was increased to $0.27806 from
$0.27500 on March 1, 2019, due to reset of the annual dividend on
March 1, 2019, and every five years thereafter.
|
8
|
The quarterly
dividend per share paid on Series 9 was decreased to $0.25606 from
$0.27500 on December 1, 2019, due to the reset of the annual
dividend on December 1, 2019, and every five years
thereafter.
|
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 cost of capital and costs related
to announced projects and projects under construction; expected
in-service dates for announced projects and projects under
construction; expected capital expenditures; expected equity
funding requirements for the Company's commercially secured growth
program; expected future growth and expansion opportunities,
including optimization plans; expectations about the Company's
joint ventures and our partners' ability to complete and finance
announced projects and projects under construction; expected
closing of acquisitions and dispositions and the timing thereof;
expected future actions of regulators and courts;
expectations regarding commodity prices; supply forecasts;
expectations regarding the impact of transactions; plans to launch
binding open seasons, including the terms and timing thereof; toll
and rate case discussions and filings, including Mainline
Contracting and the anticipated benefits thereof; 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 timing and
closing of acquisitions and dispositions; the realization of
anticipated benefits and synergies of transactions; governmental
legislation; litigation; the success of integration plans; impact
of the Company's dividend policy on its 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 expected EBITDA, expected adjusted EBITDA, earnings/(loss),
expected adjusted earnings/(loss), expected DCF and associated per
share amounts, or estimated future dividends. The most relevant
assumptions associated with forward-looking statements regarding
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 realization of anticipated
benefits and synergies of projects and transactions, operating
performance, the Company's dividend policy, regulatory parameters,
changes in regulations applicable to the Company's business,
acquisitions and dispositions, litigation, 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
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 a leading
North American energy infrastructure company. We safely and
reliably deliver the energy people need and want to fuel quality of
life. Our core businesses include Liquids Pipelines, which
transports approximately 25 percent of the crude oil produced in
North America; Gas Transmission
and Midstream, which transports approximately 20 percent of the
natural gas consumed in the U.S.; Gas Distribution and Storage,
which serves approximately 3.8 million retail customers in
Ontario and Quebec; and Renewable Power Generation, which
generates approximately 1,750 MW of net renewable power in
North America and Europe. The Company's common shares trade on
the Toronto and New York stock exchanges under the symbol ENB.
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.
FOR FURTHER
INFORMATION PLEASE
CONTACT:
|
|
|
Enbridge Inc. –
Media
|
|
Enbridge Inc. –
Investment Community
|
Jesse
Semko
|
|
Jonathan
Morgan
|
Toll Free: (888)
992-0997
|
|
Toll Free: (800)
481-2804
|
Email:
media@enbridge.com
|
|
Email:
investor.relations@enbridge.com
|
NON-GAAP RECONCILIATIONS APPENDICES
This news release contains references to adjusted EBITDA,
adjusted earnings, adjusted earnings per common share, and DCF.
Management believes the presentation of these metrics 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,
infrequent or other 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 and its Business
Units.
Adjusted earnings represent earnings attributable to common
shareholders adjusted for unusual, infrequent or other
non-operating factors included in adjusted EBITDA, as well as
adjustments for unusual, infrequent or other 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 measure of the Company's ability to
generate earnings.
DCF is defined as cash flow provided by operating
activities before the impact of 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,
infrequent or other 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 certain contingent liabilities, and non-cash
unrealized derivative fair value losses and gains which are subject
to market variability. Because of those challenges, a
reconciliation of forward-looking non-GAAP financial measures 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 RECONCILIATIONS – ADJUSTED
EBITDA AND ADJUSTED
EARNINGS
CONSOLIDATED EARNINGS
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Liquids
Pipelines
|
1,971
|
978
|
7,681
|
5,331
|
Gas Transmission and
Midstream
|
638
|
1,254
|
3,371
|
2,334
|
Gas Distribution and
Storage
|
443
|
449
|
1,747
|
1,711
|
Renewable Power
Generation
|
(189)
|
83
|
111
|
369
|
Energy
Services
|
(68)
|
374
|
250
|
482
|
Eliminations and
Other
|
114
|
(340)
|
429
|
(708)
|
EBITDA
|
2,909
|
2,798
|
13,589
|
9,519
|
Depreciation and
amortization
|
(865)
|
(794)
|
(3,391)
|
(3,246)
|
Interest
expense
|
(697)
|
(661)
|
(2,663)
|
(2,703)
|
Income tax
expense
|
(433)
|
(60)
|
(1,708)
|
(237)
|
Earnings attributable
to noncontrolling interests and
|
|
|
|
|
redeemable
noncontrolling interests
|
(72)
|
(99)
|
(122)
|
(451)
|
Preference share
dividends
|
(96)
|
(95)
|
(383)
|
(367)
|
Earnings
attributable to common shareholders
|
746
|
1,089
|
5,322
|
2,515
|
ADJUSTED EBITDA TO ADJUSTED EARNINGS
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
Liquids
Pipelines
|
1,720
|
1,728
|
7,041
|
6,617
|
Gas Transmission and
Midstream
|
948
|
952
|
3,868
|
4,068
|
Gas Distribution and
Storage
|
481
|
452
|
1,819
|
1,726
|
Renewable Power
Generation
|
119
|
98
|
424
|
435
|
Energy
Services
|
(22)
|
73
|
269
|
167
|
Eliminations and
Other
|
(60)
|
17
|
(150)
|
(164)
|
Adjusted
EBITDA
|
3,186
|
3,320
|
13,271
|
12,849
|
Depreciation and
amortization
|
(865)
|
(794)
|
(3,391)
|
(3,246)
|
Interest
expense
|
(687)
|
(656)
|
(2,649)
|
(2,637)
|
Income
taxes
|
(237)
|
(421)
|
(1,381)
|
(1,122)
|
Earnings attributable
to noncontrolling interests and
|
|
|
|
|
redeemable
noncontrolling interests
|
(73)
|
(188)
|
(126)
|
(909)
|
Preference share
dividends
|
(96)
|
(95)
|
(383)
|
(367)
|
Adjusted
earnings
|
1,228
|
1,166
|
5,341
|
4,568
|
Adjusted earnings
per common share
|
0.61
|
0.65
|
2.65
|
2.65
|
EBITDA TO ADJUSTED EARNINGS
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
EBITDA
|
2,909
|
2,798
|
13,589
|
9,519
|
Adjusting
items:
|
|
|
|
|
Change in unrealized
derivative fair value (gain)/loss
|
(754)
|
378
|
(1,806)
|
660
|
Hedging program
pre-settlement payment
|
310
|
—
|
310
|
—
|
Asset write-down
loss
|
318
|
32
|
423
|
2,118
|
(Gain)/loss on sale of
assets
|
278
|
(72)
|
278
|
22
|
Employee severance,
transition and transformation
|
|
|
|
|
costs
|
52
|
60
|
140
|
203
|
Asset monetization
transaction costs
|
—
|
23
|
—
|
88
|
Equity investment
asset impairment
|
34
|
14
|
96
|
47
|
Write-down of
inventory to the lower of cost or market
|
17
|
291
|
188
|
327
|
Regulatory liability
adjustment
|
—
|
(223)
|
—
|
(223)
|
Other
|
22
|
19
|
53
|
88
|
Total adjusting
items
|
277
|
522
|
(318)
|
3,330
|
Adjusted
EBITDA
|
3,186
|
3,320
|
13,271
|
12,849
|
Depreciation and
amortization
|
(865)
|
(794)
|
(3,391)
|
(3,246)
|
Interest
expense
|
(697)
|
(661)
|
(2,663)
|
(2,703)
|
Income tax
expense
|
(433)
|
(60)
|
(1,708)
|
(237)
|
Earnings attributable
to noncontrolling interests and
|
|
|
|
|
redeemable
noncontrolling interests
|
(72)
|
(99)
|
(122)
|
(451)
|
Preference share
dividends
|
(96)
|
(95)
|
(383)
|
(367)
|
Adjusting items in
respect of:
|
|
|
|
|
Interest
expense
|
10
|
5
|
14
|
66
|
Income
taxes
|
196
|
(361)
|
327
|
(885)
|
Earnings attributable
to noncontrolling interests and
|
|
|
|
|
redeemable
noncontrolling interests
|
(1)
|
(89)
|
(4)
|
(458)
|
Adjusted
earnings
|
1,228
|
1,166
|
5,341
|
4,568
|
Adjusted earnings
per common share
|
0.61
|
0.65
|
2.65
|
2.65
|
APPENDIX B
NON-GAAP RECONCILIATION – SEGMENTED
EBITDA TO ADJUSTED EBITDA
LIQUIDS PIPELINES
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
1,720
|
1,728
|
7,041
|
6,617
|
Change in unrealized
derivative fair value gain/(loss)
|
586
|
(715)
|
976
|
(1,077)
|
Hedging program
pre-settlement payment
|
(310)
|
—
|
(310)
|
—
|
Asset write-down
loss
|
(21)
|
(32)
|
(21)
|
(186)
|
Employee severance,
transition and transformation
|
|
|
|
|
costs
|
—
|
(1)
|
—
|
(26)
|
Other
|
(4)
|
(2)
|
(5)
|
3
|
Total
adjustments
|
251
|
(750)
|
640
|
(1,286)
|
EBITDA
|
1,971
|
978
|
7,681
|
5,331
|
GAS TRANSMISSION AND MIDSTREAM
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
948
|
952
|
3,868
|
4,068
|
Change in unrealized
derivative fair value gain/(loss)
|
—
|
(1)
|
—
|
24
|
Asset write-down loss
- US Midstream
|
—
|
—
|
—
|
(1,932)
|
Asset write-down loss
- US Gas Transmission
|
—
|
—
|
(105)
|
—
|
Equity investment
asset impairment
|
(24)
|
—
|
(86)
|
—
|
Gain/(loss) on sale of
assets
|
(268)
|
72
|
(268)
|
(2)
|
Asset monetization
transaction costs
|
—
|
—
|
—
|
(20)
|
Employee severance,
transition and transformation
|
|
|
|
|
costs
|
(5)
|
(3)
|
(5)
|
(13)
|
Regulatory liability
adjustment
|
—
|
223
|
—
|
223
|
Other
|
(13)
|
11
|
(33)
|
(14)
|
Total
adjustments
|
(310)
|
302
|
(497)
|
(1,734)
|
EBITDA
|
638
|
1,254
|
3,371
|
2,334
|
GAS DISTRIBUTION AND STORAGE
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited;
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
481
|
452
|
1,819
|
1,726
|
Change in unrealized
derivative fair value gain/(loss)
|
(21)
|
3
|
(12)
|
6
|
Loss on sale of
assets
|
(10)
|
—
|
(10)
|
—
|
Noverco Inc. equity
earnings adjustment
|
—
|
—
|
—
|
(9)
|
Employee severance,
transition and transformation
|
|
|
|
|
costs
|
(8)
|
(6)
|
(51)
|
(12)
|
Other
|
1
|
—
|
1
|
—
|
Total
adjustments
|
(38)
|
(3)
|
(72)
|
(15)
|
EBITDA
|
443
|
449
|
1,747
|
1,711
|
RENEWABLE POWER GENERATION
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
119
|
98
|
424
|
435
|
Change in unrealized
derivative fair value gain/(loss)
|
—
|
(1)
|
2
|
1
|
Asset write-down
loss
|
(297)
|
—
|
(297)
|
—
|
Equity investment
asset impairment
|
(10)
|
(14)
|
(10)
|
(47)
|
Loss on sale of
assets
|
—
|
—
|
—
|
(20)
|
Other
|
(1)
|
—
|
(8)
|
—
|
Total
adjustments
|
(308)
|
(15)
|
(313)
|
(66)
|
EBITDA
|
(189)
|
83
|
111
|
369
|
ENERGY SERVICES
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
(22)
|
73
|
269
|
167
|
Change in unrealized
derivative fair value gain/(loss)
|
(29)
|
592
|
169
|
642
|
Write-down of
inventory to the lower of cost or market
|
(17)
|
(291)
|
(188)
|
(327)
|
Total
adjustments
|
(46)
|
301
|
(19)
|
315
|
EBITDA
|
(68)
|
374
|
250
|
482
|
ELIMINATIONS AND OTHER
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
(60)
|
17
|
(150)
|
(164)
|
Change in unrealized
derivative fair value gain/(loss)
|
218
|
(256)
|
671
|
(256)
|
Asset monetization
transaction costs
|
—
|
(23)
|
—
|
(68)
|
Employee severance,
transition and transformation
|
|
|
|
|
costs
|
(39)
|
(50)
|
(84)
|
(152)
|
Other
|
(5)
|
(28)
|
(8)
|
(68)
|
Total
adjustments
|
174
|
(357)
|
579
|
(544)
|
EBITDA
|
114
|
(340)
|
429
|
(708)
|
APPENDIX
C
NON-GAAP RECONCILIATION – CASH PROVIDED BY OPERATING
ACTIVITIES TO DCF
|
Three months
ended
December 31,
|
Twelve months
ended
December 31,
|
|
2019
|
2018
|
2019
|
2018
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Cash provided by
operating activities
|
1,993
|
2,503
|
9,398
|
10,502
|
Adjusted for changes
in operating assets and liabilities1
|
(192)
|
28
|
259
|
(915)
|
|
1,801
|
2,531
|
9,657
|
9,587
|
Distributions to
noncontrolling interests and redeemable
|
|
|
|
|
noncontrolling
interests4
|
(54)
|
(281)
|
(204)
|
(1,182)
|
Preference share
dividends
|
(96)
|
(96)
|
(383)
|
(364)
|
Maintenance capital
expenditures2
|
(342)
|
(361)
|
(1,083)
|
(1,144)
|
Significant adjusting
items:
|
|
|
|
|
Other receipts of
cash not recognized in revenue3
|
30
|
51
|
169
|
208
|
Employee severance,
transition and transformation
|
|
|
|
|
costs
|
52
|
59
|
143
|
248
|
Asset monetization
costs
|
—
|
23
|
—
|
107
|
Distributions from
equity investments in excess of
|
|
|
|
|
cumulative
earnings4
|
154
|
35
|
361
|
326
|
Regulatory liability
adjustment
|
—
|
(223)
|
—
|
(223)
|
Hedging program
pre-settlement payment
|
310
|
—
|
310
|
—
|
Other
items
|
196
|
125
|
254
|
55
|
DCF
|
2,051
|
1,863
|
9,224
|
7,618
|
1
|
Changes in
operating assets and liabilities, net of recoveries.
|
2
|
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.
|
3
|
Consists of cash
received net of revenue recognized for contracts under make-up
rights and similar deferred revenue arrangements.
|
4
|
Presented net of
adjusting items.
|
View original
content:http://www.prnewswire.com/news-releases/enbridge-inc-reports-strong-fourth-quarter--full-year-2019-results-301005108.html
SOURCE Enbridge Inc.