CALGARY, AB, July 29, 2020
/CNW/ - Enbridge Inc. (Enbridge or the Company) (TSX: ENB) (NYSE:
ENB) today reported second quarter 2020 financial results and
provided a quarterly business update.
Second Quarter 2020 Highlights
(all financial
figures are unaudited and in Canadian dollars unless otherwise
noted)
- GAAP earnings of $1,647 million
or $0.82 earnings per common share,
compared with GAAP earnings of $1,736
million or $0.86 per common
share in 2019
- Adjusted earnings were $1,133
million or $0.56 per common
share, compared with $1,349 million
or $0.67 per common share in 2019
- Adjusted earnings before interest, income tax and depreciation
and amortization (EBITDA) were $3,312
million, compared with $3,208
million in 2019
- Cash Provided by Operating Activities was $2,416 million, compared with $2,494 million in 2019
- Distributable Cash Flow (DCF) was $2,437
million, compared with $2,310
million in 2019
- Re-affirmed financial guidance range for 2020 of $4.50 to $4.80
DCF/share
- Reliably served North American energy needs through continued
safe operations during the ongoing COVID-19 pandemic
- To further bolster resiliency, the Company executed several
actions to enable $300 million of
cost reduction in 2020
- Completed 2020 debt funding plan, with more than $14 billion of available liquidity
- Received regulatory approvals on the Algonquin Gas Transmission
and B.C. Pipeline uncontested rate settlements
- Secured the Fécamp offshore wind farm in France, a 500 MW facility underpinned by a
long-term fixed-price power purchase agreement
- Sanctioned four growth projects in Gas Distribution and Storage
to reinforce the distribution network and expand storage capacity
at the Dawn hub
- Progressing execution of $11
billion secured capital program
- Successfully completed Line 3 Minnesota Public Utilities
Commission (MPUC) Petition for Reconsideration process; Minnesota
Pollution Control Agency (MPCA) progressing towards November 14th permitting milestone
- Regulatory review process established by the Canada Energy
Regulator (CER) for the Mainline Contract application; Enbridge
responded to initial Information Requests demonstrating clear
benefits to the public and shippers
CEO COMMENT - Al Monaco,
President and Chief Executive Officer
"The COVID-19 pandemic has had an unprecedented impact on our
society, our economies and the global energy industry. At Enbridge,
we responded quickly and effectively to ensure safe and
uninterrupted energy delivery to our customers across North America while protecting the health of
our people. As COVID unfolded early in the year, we enacted plans
to further bolster our operational and financial strength to
protect against a prolonged downturn, and to mitigate the impact of
lower throughput on our liquids Mainline system. We have weathered
the near-term effects of the pandemic on our business well - and
I'm very proud of the entire Enbridge team and how we have met the
challenge.
"Over the last three years we have been focused on building an
even more resilient business, which put us in a strong position
coming into 2020, pre-COVID. We've materially diversified the
business mix to natural gas, sold our gas gathering and processing
business and significantly reduced leverage while moving to an
equity self-funding model. We have also simplified our corporate
structure, reduced overhead and successfully executed $30 billion of capital projects.
"This year we're taking additional action to further reinforce
our financial strength and flexibility. We took advantage of strong
debt markets to raise $6.9 billion of
capital at attractive rates, which addresses our 2020 growth
capital needs, and available liquidity has been increased to
$14 billion, which means we don't
need to access the capital markets through 2021. We also have now
fully enabled cost reductions for 2020.
"In the face of the worst energy downturn our industry has ever
experienced, the strength and resilience of our assets was
demonstrated once again in the second quarter, with solid financial
results. We achieved DCF per share of $1.21, which exceeded our expectations for the
second quarter and for the first half of the year. While there will
be headwinds in the second half of 2020, which will temper
favourable first half results, we expect to achieve our full year
guidance range of $4.50 to
$4.80 DCF per share.
"All of our business units performed well and contributed to the
strong second quarter results. Most notably, Gas Transmission along
with Gas Distribution and Storage both saw high utilization and
favorable decisions on rates. In Liquids Pipelines, Mainline
throughput was about 400 thousand barrels per day lower than our
first quarter results however, throughput has been improving
steadily and in-line with our expectations. This trend reflects the
strong competitive position of the Midwest and Gulf Coast
refineries that take Canadian heavy barrels off of our system.
"Despite the COVID disruption, we've made good progress on our
strategic priorities this quarter. We are progressing our
$11 billion secured capital program,
including Line 3 in Minnesota,
where we've now completed the regulatory process related to the
Environmental Impact Statement, Certificate of Need and Route
Permit. And, the Pollution Control Agency has established a firm
timeline to finalize construction permits by November 14th.
"This quarter we sanctioned $1
billion of newly secured growth projects comprised of four
gas utility projects and another European offshore wind project.
Our Mainline contract application review is also in full swing; the
CER issued a hearing order outlining the key steps in the process
and we're providing evidence that demonstrates the value that
Mainline contracting will deliver to customers and to ensure the
value of western Canadian resources are maximized.
"In summary, the first half 2020 performance has been stronger
than expected, highlighting the resiliency of our business and our
ability to deliver solid results in difficult market conditions. We
remain focused on executing our secured capital program, which
combined with growth embedded within our business, is expected to
deliver 5 to 7% annual DCF per share growth through 2022."
FINANCIAL RESULTS REVIEW AND 2020 FINANCIAL OUTLOOK
Financial results for three and six months ended June 30, 2020, are summarized in the table
below:
|
|
|
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars, except per share amounts;
number of shares in millions)
|
|
|
|
|
GAAP Earnings
attributable to common shareholders
|
1,647
|
1,736
|
218
|
3,627
|
GAAP Earnings per
common share
|
0.82
|
0.86
|
0.11
|
1.80
|
Cash provided by
operating activities
|
2,416
|
2,494
|
5,225
|
4,670
|
Adjusted
EBITDA1
|
3,312
|
3,208
|
7,075
|
6,977
|
Adjusted
Earnings1
|
1,133
|
1,349
|
2,801
|
2,989
|
Adjusted Earnings per
common share1
|
0.56
|
0.67
|
1.39
|
1.48
|
Distributable Cash
Flow1
|
2,437
|
2,310
|
5,143
|
5,068
|
Weighted average
common shares outstanding
|
2,019
|
2,018
|
2,019
|
2,017
|
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 second
quarter of 2020 decreased by $89
million or $0.04 per share
compared with the same period in 2019. 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 EBITDA in the second quarter of 2020 increased by
$104 million compared with the same
period in 2019.The increase was driven by strong utilization in our
Gas pipelines and utility, incremental earnings from positive rate
settlements on Texas Eastern, contributions from new assets that
were placed into service throughout 2019 and the first quarter of
2020 and Energy Services profits from favourable storage
opportunities. These positive business factors were partially
offset by lower earnings from Liquids Pipelines due to lower
Mainline throughput related to COVID-19 and the absence of
contributions from the federally regulated Canadian natural gas
gathering and processing business sold on December 31, 2019.
Adjusted earnings in the second quarter of 2020 decreased by
$216 million and on a per share basis
by $0.11. The decrease was primarily
driven by a reduction in capitalized interest and higher
depreciation from new assets placed into service throughout 2019,
primarily on the Canadian Line 3 replacement program, where the
Company is currently earning an interim surcharge until the U.S.
portion of Line 3 is completed.
DCF for the second quarter was $2,437
million, an increase of $127
million over the second quarter of 2019 driven largely by
the net impact of the operating factors noted above as well as
lower maintenance capital due to timing of spend in light of
COVID-19. These factors are discussed in detail under
Distributable Cashflow.
Detailed segmented financial information and analysis for the
second quarter of 2020 can be found below under Adjusted EBITDA
by Segments.
Re-affirming 2020 Financial Guidance
Based on its solid performance in the first half and the outlook
for the second half, the Company still expects to generate DCF
within our original guidance range of $4.50 to $4.80 per
share. The Company's outperformance in the first half of the year
is expected to be offset by headwinds unique to the second half of
2020. These include the pace and magnitude of recovery in Mainline
throughput, a catch up in enterprise-wide maintenance spending
consistent with 2020 guidance, lower revenues on the Texas Eastern
system due to temporary operating capacity restrictions, and a
lower contribution from Energy Services. In addition, the Company
continues to expect a favourable U.S. dollar exchange rate which
will benefit unhedged cash flows, low interest rates and related
financing costs, and the realization of company-wide actions to
reduce costs in 2020.
In the first quarter update, the Company provided a revised
outlook for Mainline volumes due to the rapid decline in refined
products demand brought about by COVID-19, and the resulting cuts
to crude oil refining demand. The Company forecasted Mainline
volumes to decline by 400 to 600 thousand barrels per day (kbpd)
for the second quarter, and an average of 300 kbpd for the last
nine months of the year from average expected annual throughput of
2.84 million barrels per day (mbpd). Actual Mainline throughput for
the quarter was 2.44 mbpd, which reflects a slightly faster pace of
recovery in demand for refined products and higher refinery
utilizations, particularly in the U.S. Midwest.
Over the balance of 2020, the Company anticipates a continued
but gradual recovery in demand, consistent with our throughput
guidance, as travel and border restrictions are lifted and mobility
returns to North America. This
view is supported by our expectation that the refineries operating
in Enbridge's core Mainline system markets (i.e. the United States
Midwest, Ontario, Quebec and the United States Gulf Coast) will
continue to experience higher utilization rates given their scale,
complexity and cost competitiveness. The Company continues to
expect that Mainline volumes will be under utilized by 200-400 kbpd
in the third quarter and 100-300 kbpd in the fourth quarter, and
return to full utilization in early 2021.
BUSINESS PERFORMANCE AND STRATEGIC PRIORITIES UPDATE
Executing on $11 billion of
Secured Growth Capital
The Company now has an inventory of approximately $11
billion of secured projects at various stages of execution,
including $0.3 billion of new
projects announced in Gas Distribution and Storage and $0.7 billion in Renewable Power during the second
quarter. Approximately $5 billion of
the $11 billion secured growth
capital remains to be spent through 2022, net of anticipated
project level financing provided by third parties. Details on these
newly secured projects are outlined in the "business
updates" sections below.
Overall, these secured projects are scheduled to come into
service between 2020 and 2023 and once placed in service will
provide approximately $2.5 billion of
incremental cash flows and drive highly transparent growth over the
near to medium term horizon. The individual projects that make up
the secured program 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.
During the second quarter, the Company has continued to advance
the execution of several secured projects, while assuring that
COVID-19 precautionary measures are in place to protect the health
of construction crews. Execution progress includes:
- Completed Phase 1 of the Express Pipeline Expansion, adding 25
kbpd of capacity.
- Progressing construction of the $1.0
billion T-South reliability and expansion project, with over
$30 million in spending directly
benefiting indigenous affiliated companies. The project is on
target for a phased in-service date during 2021.
- Received FERC authorization to proceed with the $0.2 billion Cameron Extension project, which
will connect Texas Eastern to Venture Global's Calcasieu Pass LNG
facility. The project is expected to commence construction in
2020.
- The $0.9 billion Saint Nazaire
French offshore wind project is advancing as planned with major
contractors selected and fabrication of key project components
underway.
- Advancing planned Mainline System optimizations enabling
approximately 50 kbpd of incremental throughput
Liquids Pipeline Update
Mainline Contracting
In May 2020, the CER announced its
plans to immediately commence the regulatory review of the
Company's application to implement contracts on the Liquids
Canadian Mainline System. The proposed contract offering will
replace the current Competitive Toll Settlement (CTS) that is in
place until it expires on June 30,
2021.
The CER issued a hearing order outlining the timelines for the
regulatory review process which includes two rounds of intervenor
information requests, written evidence and Enbridge's replies,
concluding in April 2021. The Company
expects an oral hearing to occur sometime after April 2021, but a hearing date has not yet been
set. If a replacement agreement is not in place by June 30, 2021, the CTS tolls will continue on an
interim basis.
During the second quarter, Enbridge responded to its first round
of information requests from the CER. The evidence further supports
our view that the proposed tolls meet the regulators fair return
standards and that the contract offering will serve the public
interest. The Mainline contract offering supports the best netbacks
for Western Canadian producers, thereby maximizing the value of
Western Canadian crude. This is achieved by providing the lowest
toll into the best markets and securing long-term demand for
Canadian heavy and light barrels.
Line 3 Replacement
The $9 billion Line 3 Replacement
Project is a critical integrity replacement project that will
enhance the continued safe and reliable operations of our Mainline
System well into the future and reflects the importance of
protecting the environment.
In December of 2019, the Company placed the $5 billion Canadian segment of the pipeline
replacement into service, with an interim surcharge of US$0.20 per barrel.
On the U.S. segment of the project, in the second quarter the
MPUC issued its final order to approve the final environmental
impact statement (FEIS) and reinstate the Certificate of Need and
Route Permit, and subsequently denied all related petitions for
reconsideration. This critical milestone substantially concludes
the regulatory process and allows for construction of the pipeline,
which is expected to take 6 to 9 months, following the issuance of
required State and Federal permits.
The MPCA released a draft of the revised 401 Water Quality
Certificate permit in February 2020.
Following a public comment period, the MPCA announced on
June 3, 2020 that it will conduct a
contested case hearing regarding the 401 Water Quality Certificate
permit. This contested case will be focused on construction methods
at water crossings and the appropriate measurement of environmental
impacts, rather than route and need for the project, which has
already been determined by the MPUC. The contested case hearing is
scheduled for August 24-28, 2020,
followed by the Administrative Law Judge (ALJ) issuing their report
on October 16, 2020. The ALJ's
contested case hearing schedule confirms that in order to maintain
jurisdiction the MPCA is required by the Clean Water Act to make a
final decision regarding the 401 certification by November 14, 2020.
U.S. Army Corps of Engineers (USACE) and the Minnesota
Department of Natural Resources (DNR) permitting processes are
ongoing and continue to progress in parallel.
At this time, Enbridge cannot determine when all necessary
permits to commence construction will be issued and as such has not
provided an update to the in-service date for Line 3.
Line 5 Dual Pipelines
Great Lake Tunnel Project
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 a state-of-the-art tunnel under the Straits. The Michigan Courts
have now twice confirmed the constitutionality of the legislation
underpinning the agreements and the State
of Michigan did not file for leave to appeal to the Supreme
Court of Michigan within the
requisite time period so this lawsuit has concluded.
This project will make a safe pipeline even safer, demonstrating
our ongoing commitment to protect Michigan and the Great Lakes' natural
resource. The Company has completed an extensive geotechnical
investigation and the engineering design of the tunnel continues to
progress on schedule.
Enbridge has filed for all major regulatory and environmental
permits, including the joint permit application (JPA) with the
Michigan Department of Environment, Great Lakes and Energy (EGLE)
and the Army Corps. The JPA covers wetlands and waterway permit
requirements from both state and federal agencies and allows for
concurrent review of the application by both agencies. In addition,
the Company filed a regulatory application to the Michigan Public
Service Commission for replacement of the Line 5 pipeline into a
tunnel. The Commission has scheduled a public hearing date for
August 24, 2020.
Upon receipt of all required permits Enbridge will begin
construction of the Line 5 tunnel. Construction and commissioning
of the tunnel and pipeline is expected to be completed in late
2024.
East Segment - Line 5
On June 18, 2020, during seasonal
maintenance work on Line 5, Enbridge discovered that a screw anchor
support had shifted from its original position on the east segment
of the dual Straits crossing pipelines. As a preliminary
precaution, both the east and west segment of the crossing were
immediately shut down and the Company promptly notified the State
and its federal regulator, the Pipeline and Hazardous Materials
Safety Administration (PHMSA). Following the identification of the
shifted anchor, the Company assessed the parallel west segment and
the inspections confirmed that the west segment of the crossing is
safe and fit for service. PHMSA was notified prior to normal
operations commencing on the west segment of Line 5 on June 20, 2020 and did not object to the
re-start.
Despite the Company following standard protocol and being in
full compliance with its 1953 easement, the west segment was
subsequently shut down on June 25,
2020 for five days due to a Temporary Restraining Order
issued by the Michigan Circuit Court. On July 1, the Temporary Restraining Order was
amended allowing Enbridge to resume service of the west segment and
perform an in-line inspection which reconfirmed that the line is
safe to operate as there was no damage to the pipeline. The east
segment of Line 5 remains shut down as we work with the PHMSA to
ensure all safety assessments are complete prior to restarting the
east segment of Line 5.
Gas Transmission and Midstream Update
The Company has made several advancements on the regulatory
front, further optimizing the base business by ensuring fair and
timely cost recovery through rate proceedings. Following on the
successful Texas Eastern settlement in the first quarter, the
Company received approval from the FERC of its uncontested rate
settlement on its Algonquin Gas Transmission pipeline, and approval
by the CER of our uncontested rate settlement on the B.C. Pipeline,
during the second quarter, resulting in a good outcome for both
Enbridge and shippers. The Company has also initiated rate
proceedings on East Tennessee Natural Gas and the U.S portions of
both the Alliance Pipeline and the Maritimes & Northeast
Pipeline.
On May 4, 2020, a rupture occurred
on Line 10, a 30-inch natural gas pipeline that makes up part of
the Texas Eastern natural gas pipeline system in Fleming County, Kentucky. There were no
reported injuries or damaged structures as a result of the rupture.
Texas Eastern crews isolated all three pipelines in this corridor
as part of the initial incident response and investigation. The
Line 25 36-inch pipeline has since been returned to service. The
National Transportation Safety Board is working with the Pipeline
and Hazardous Materials Safety Administration (PHMSA) and Enbridge
to investigate the incident. On June 1,
2020, the PHMSA issued an amendment to the Lincoln County
Corrective Action Order (CAO) addressing the Fleming County rupture. Texas Eastern is
currently performing precautionary integrity assessments in
compliance with the CAO and the Company is focused on restoring the
pipeline to full service by the winter heating season.
Gas Distribution and Storage Update
The Company announced today that it is proceeding with
$0.3 billion of utility growth
capital expenditures including regulated rate base system
reinforcements and an enhancement of its unregulated storage
facilities at Dawn, Ontario. These
projects are expected to come into service between 2021 and
2023.
In May, Enbridge Gas Inc. (EGI) received a positive decision on
its 2020 rate filing from the Ontario Energy Board which included
approval of 2020 rates and the funding of two discrete incremental
capital investments through the incremental capital funding (ICM)
mechanism with a total capital cost of $0.1
billion. The ICM mechanism is a regulatory tool that allows
for recovery of the revenue requirement for certain incremental
capital additions, beyond what is funded through previously
approved rates. This 2020 filing represents the second year of a
five-year incentive rate structure.
The Company continues to advance the capture of synergies from
the amalgamation of Enbridge Gas Distribution Inc. and Union Gas
Limited.
Renewable Power Update
Enbridge has investments in 24 facilities in North America and now has several investments
in offshore wind projects in Europe, both in the development stage as well
as operational. In June of 2020, the Company announced that it is
moving forward with the 500 MW Fécamp offshore wind farm, which is
comprised of 71 wind turbines off the coast of northwest
France, providing annual
electricity to meet the power needs for 770,000 people.
Enbridge has a 35% interest in the project (17.9% after
completion of the CPP Investment transaction discussed below) with
partners EDF Renewables and wpd holding the remaining interest. The
total project capital cost is estimated to be EUR2 billion, of which the majority will be
financed through non-recourse project level debt. The project is
underpinned by a 20-year fixed price power purchase agreement with
the French State and project commissioning is expected in 2023.
In the first quarter, Enbridge announced the execution of
agreements whereby 49% of an entity that holds Enbridge's 50%
interest in Éolien Maritime France SAS (EMF) will be sold to CPP
Investments. The Company's investment in Fécamp is held through its
50% interest in EMF. Completion of the transaction is subject to
customary regulatory approvals and is anticipated to close in the
fourth quarter of 2020.
STRONG FINANCIAL POSITION AND SELF FUNDING MODEL
INTACT
The Company has exited the second quarter in a strong financial
position with over $14 billion of
liquidity and having completed its 2020 funding plan. The
equity-self funding model remains intact and debt to EBITDA is
expected to remain comfortably well-within the target range of 4.5x
to 5.0x for the full year.
The Company continued to secure additional debt financing at
attractive rates and proceeds from these offerings were primarily
used to reduce existing indebtedness and partially fund capital
projects.
In May, the Company raised $1.3
billion with a dual tranche offering of 5-year and 7-year
notes in the Canadian debt capital markets at a weighted average
coupon rate of 2.65%. In addition, subsequent to the second
quarter, Enbridge raised an additional US$1.0 billion of 60-year hybrid subordinated
notes in the United States debt
capital markets. These hybrid notes qualify for 50% equity
treatment from most rating agencies which further bolsters the
Company's financial strength.
In late July, the Company successfully renegotiated and extended
approximately $10 billion of its
364-day extendible credit facilities to July
2021, with the option of a term out date to July 2022.
The above actions have positioned the Company to fund all of our
capital projects and any debt maturities through 2021 in the event
capital markets are inaccessible.
EXECUTIVE LEADERSHIP CHANGES
The Company is announcing that Executive Vice President &
Chief Development Officer, John
Whelen, will retire, effective October 31. Over
the last 28 years, Mr. Whelen has played a pivotal role in
Enbridge's growth and evolution, holding several senior leadership
roles in Finance and Corporate Development. From 2014 to 2019, Mr.
Whelen held the role of Chief Financial Officer, where he oversaw
the financial design and execution of several very significant
funding and investment transactions, including Enbridge's
$37 Billion acquisition of
Spectra.
"Along the way John has played a key role in helping build
Enbridge's financial foundation and laying the groundwork for our
Company's growth and success", said President and CEO Al Monaco. "He will leave a lasting legacy
at Enbridge, and we wish him and his family the very best in the
future."
John's role will be filled by current members of our Executive
Leadership Team. Matthew Akman
will continue in his role as Senior Vice President, Strategy and
Power, and Allen Capps will expand
his corporate development portfolio to include our energy marketing
business as Senior Vice President, Corporate Development and Energy
Services. Both Mr. Akman and Mr. Capps will report directly
to Al Monaco, President and Chief
Executive Officer effective September 15.
SECOND QUARTER 2020 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
second quarter of 2020.
GAAP SEGMENT EBITDA AND CASH FLOW FROM OPERATIONS
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Liquids
Pipelines
|
2,340
|
1,992
|
3,190
|
4,064
|
Gas Transmission and
Midstream
|
950
|
941
|
(104)
|
1,961
|
Gas Distribution and
Storage
|
383
|
390
|
987
|
1,052
|
Renewable Power
Generation
|
163
|
94
|
283
|
218
|
Energy
Services
|
(99)
|
221
|
22
|
227
|
Eliminations and
Other
|
261
|
107
|
(705)
|
355
|
EBITDA
|
3,998
|
3,745
|
3,673
|
7,877
|
|
|
|
|
|
Earnings
attributable to common shareholders
|
1,647
|
1,736
|
218
|
3,627
|
|
|
|
|
|
Cash provided by
operating activities
|
2,416
|
2,494
|
5,225
|
4,670
|
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 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
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
Liquids
Pipelines
|
1,744
|
1,766
|
3,663
|
3,495
|
Gas Transmission and
Midstream
|
975
|
936
|
2,072
|
1,976
|
Gas Distribution and
Storage
|
406
|
390
|
1,015
|
1,083
|
Renewable Power
Generation
|
150
|
100
|
268
|
223
|
Energy
Services
|
86
|
88
|
73
|
264
|
Eliminations and
Other
|
(49)
|
(72)
|
(16)
|
(64)
|
Adjusted
EBITDA1,3
|
3,312
|
3,208
|
7,075
|
6,977
|
Maintenance
capital
|
(135)
|
(269)
|
(339)
|
(448)
|
Interest
expense1
|
(709)
|
(662)
|
(1,420)
|
(1,346)
|
Current income
tax1
|
(134)
|
(53)
|
(242)
|
(211)
|
Distributions to
noncontrolling interests1
|
(88)
|
(54)
|
(164)
|
(100)
|
Cash distributions in
excess of equity earnings1
|
210
|
189
|
282
|
283
|
Preference share
dividends
|
(94)
|
(96)
|
(190)
|
(191)
|
Other receipts of
cash not recognized in revenue2
|
81
|
33
|
132
|
86
|
Other non-cash
adjustments
|
(6)
|
14
|
9
|
18
|
DCF3
|
2,437
|
2,310
|
5,143
|
5,068
|
Weighted average
common shares outstanding
|
2,019
|
2,018
|
2,019
|
2,017
|
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.
|
Second quarter 2020 DCF increased $127
million compared with the same period of 2019. Key
performance drivers of quarter-over-quarter increase included:
- Growth in adjusted EBITDA was driven by strong utilization in
our Gas pipelines and utility, incremental earnings from positive
rate settlements on Texas Eastern, contributions from new assets
that were placed into service throughout 2019 and the first quarter
of 2020 and Energy Services profits from favourable storage
opportunities. These positive business factors were partially
offset by lower earnings from Liquids Pipelines due to lower
Mainline throughput related to COVID-19 and the absence of
contributions from the federally regulated Canadian natural gas
gathering and processing business sold on December 31, 2019. For further detail on business
performance refer to Adjusted EBITDA by Segments.
- Lower maintenance capital due to timing of spend in light of
COVID-19 mobility restrictions.
- Higher interest expense due to a combination of additional new
debt incurred to fund capital expenditures as well as a reduction
in capitalized interest associated with the Canadian portion of
Line 3 placed into service in December
2019, partially offset by lower rates on short-term and
newly issued long-term notes.
- Higher current income tax due to higher minimum US tax and
timing of recognition of newly enacted Canadian tax legislation
that came into effect in the second half of 2019.
- Higher cash distributions in excess of equity earnings due to
both timing of distributions and new assets placed into service,
including Gray Oak crude oil
pipeline and Hohe See Offshore Wind Project; partially offset by a
50% distribution cut at DCP Midstream, LP (DCP Midstream).
ADJUSTED
EARNINGS
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
Adjusted
EBITDA2
|
3,312
|
3,208
|
7,075
|
6,977
|
Depreciation and
amortization
|
(949)
|
(842)
|
(1,831)
|
(1,682)
|
Interest
expense1
|
(695)
|
(643)
|
(1,391)
|
(1,311)
|
Income
taxes1
|
(404)
|
(279)
|
(855)
|
(767)
|
Noncontrolling
interests1
|
(37)
|
1
|
(7)
|
(37)
|
Preference share
dividends
|
(94)
|
(96)
|
(190)
|
(191)
|
Adjusted
earnings2
|
1,133
|
1,349
|
2,801
|
2,989
|
Adjusted earnings
per common share
|
0.56
|
0.67
|
1.39
|
1.48
|
1
|
Presented net of
adjusting items.
|
2
|
Schedules
reconciling adjusted EBITDA and adjusted earnings are available as
Appendices to this news release.
|
Adjusted earnings decreased $216
million and adjusted earnings per share decreased
$0.11 compared with the first quarter
in 2019. Growth in adjusted EBITDA 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 throughout 2019, primarily on Line 3
Canada which entered service in December
2019.
- Higher interest expense due to debt issued to fund new growth
capital as well as a reduction in capitalized interest associated
with the Canadian portion of Line 3, partially offset by lower
rates on short-term debt and newly issued long-term notes.
- Higher income taxes primarily due to higher minimum US tax and
timing of recognition of newly enacted Canadian tax legislation
that came into effect in the second half of 2019.
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 a higher average Canadian
dollar exchange rate in the second quarter of 2020 (C$1.39/US$) when compared with the corresponding
2019 period (C$1.34/US$).
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
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Mainline
System1
|
969
|
950
|
2,076
|
1,914
|
Regional Oil Sands
System
|
199
|
203
|
410
|
430
|
Gulf Coast and
Mid-Continent System
|
257
|
265
|
501
|
481
|
Other2
|
319
|
348
|
676
|
670
|
Adjusted
EBITDA3
|
1,744
|
1,766
|
3,663
|
3,495
|
|
|
|
|
|
Operating Data
(average deliveries – thousands of bpd)
|
|
|
|
|
Mainline System -
ex-Gretna volume4
|
2,439
|
2,661
|
2,641
|
2,689
|
Regional Oil Sands
System5
|
1,399
|
1,818
|
1,632
|
1,785
|
International Joint
Tariff (IJT)6
|
$4.21
|
$4.15
|
$4.21
|
$4.15
|
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 second quarter of 2020 was C$1.17/US$ (Q2 2019:
C$1.19/US$).
|
|
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 $22 million compared to the second quarter of
2019 primarily as a result of the following factors:
- Mainline System contributions was negatively impacted by
reduced utilization rates, with ex-Gretna throughput down on average 222 kbpd,
driven by the impact of COVID-19 on supply and demand for oil and
related products; this was more than offset by a higher IJT
Benchmark Toll and contributions from the Canadian Line 3
Replacement (L3R) Program that was placed into service on
December 1, 2019 with an interim
surcharge on Mainline System volumes of US$0.20 per barrel.
- Regional Oil Sands contributions were consistent despite the
decrease in delivery volumes which is largely due to the majority
of the assets being contracted under take-or-pay arrangements.
- Gulf Coast and Mid-Continent System was slightly down due to
lower period-over-period throughput on the Seaway Crude Pipeline
driven by the impact of COVID-19 on the Gulf Coast demand and lower
Flanagan South Pipeline throughput.
- Other decreased due to lower throughput on our Bakken Pipeline
System driven by the impact of lower prices and COVID-19 on supply
and demand for oil and products.
GAS TRANSMISSION AND MIDSTREAM
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
US Gas
Transmission1
|
791
|
672
|
1,655
|
1,417
|
Canadian Gas
Transmission1
|
105
|
164
|
243
|
352
|
US
Midstream
|
35
|
51
|
80
|
103
|
Other
|
44
|
49
|
94
|
104
|
Adjusted
EBITDA2
|
975
|
936
|
2,072
|
1,976
|
1
|
US Gas
Transmission includes the Canadian portion of the Maritimes &
Northeast Pipeline which was previously included in Canadian Gas
Transmission. The comparable 2019 adjusted EBITDA has been restated
to reflect this change.
|
2
|
Schedules
reconciling adjusted EBITDA are available as Appendices to this
news release.
|
Gas Transmission and Midstream adjusted EBITDA increased
$39 million compared to the second
quarter of 2019 primarily due to the following factors:
- US Gas Transmission adjusted EBITDA increased primarily due to
higher revenues from Texas Eastern resulting from the recent rate
settlement and contributions from the Stratton Ridge project and
the second phase of the Atlantic Bridge project that were placed
into service in the third and fourth quarters of 2019,
respectively; partly offset by higher operating costs.
- Canadian Gas Transmission adjusted EBITDA decreased primarily
due to the absence of contributions from federally regulated
Canadian gas gathering and processing assets that were sold on
December 31, 2019. Further,
contributions from the Alliance Pipeline and Aux Sable are also lower driven by narrowed
AECO-Chicago basis and lower commodity prices impacting
fractionation margins, respectively.
GAS DISTRIBUTION AND STORAGE
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Enbridge Gas Inc.
(EGI)
|
385
|
373
|
959
|
1,015
|
Other
|
21
|
17
|
56
|
68
|
Adjusted
EBITDA1
|
406
|
390
|
1,015
|
1,083
|
|
|
|
|
|
Operating
Data
|
|
|
|
|
EGI
|
|
|
|
|
Volumes (billions of
cubic feet)
|
351
|
340
|
989
|
1,059
|
Number of active
customers (thousands)2
|
|
|
3,750
|
3,723
|
Heating degree
days3
|
|
|
|
|
Actual
|
606
|
593
|
2,333
|
2,639
|
Forecast based on
normal weather4
|
516
|
516
|
2,439
|
2,438
|
1
|
Schedules
reconciling adjusted EBITDA are available as Appendices to this
news release.
|
2
|
Number of active
customers is the number of natural gas consuming 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
|
Normal weather is
the weather forecast by EGI in its legacy rate zones, using the
forecasting methodologies approved by the Ontario Energy
Board.
|
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. 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
$16 million compared to the second
quarter of 2019 primarily due to:
- Colder weather experienced in our franchise service areas which
led to higher utilization. When compared with the normal weather
forecast embedded in rates, the colder weather in the second
quarter of 2020 positively impacted EBITDA by approximately
$22 million (Q2 2019: ~$19 million); and
- Higher distribution revenues resulting from increases in rates
and customer base growth, as well as synergy capture realized from
the amalgamation of Enbridge Gas Distribution Inc. and Union Gas
Limited.
The positive business factors above were partially offset by the
absence of earnings in 2020 from Enbridge Gas New Brunswick and St.
Lawrence Gas Company, Inc. which were sold on October 1, 2019, and November 1, 2019, respectively.
RENEWABLE POWER GENERATION
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA1
|
150
|
100
|
268
|
223
|
1
|
Schedules
reconciling adjusted EBITDA are available as Appendices to this
news release.
|
Renewable Power Generation adjusted EBITDA increased
$50 million compared to second
quarter of 2019 primarily due to:
- Stronger wind resources at United
States wind facilities;
- Contributions from the Hohe See Offshore Wind Project, which
reached full operating capacity in October
2019, and the Albatros expansion, which was placed into
service in January 2020; and
- Reimbursements received at certain Canadian wind facilities
resulting from a change in operator.
These factors were partially offset by higher mechanical repair
costs at certain United States
wind facilities.
ENERGY SERVICES
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA1
|
86
|
88
|
73
|
264
|
1
|
Schedules
reconciling adjusted EBITDA are available as Appendices to this
news release.
|
Energy Services adjusted EBITDA decreased $2 million compared to the second quarter of 2019
as a result of compression of location and quality differentials in
certain markets which lead to fewer opportunities to achieve
profitable margins on capacity obligations, partially offset by
favorable storage opportunities.
ELIMINATIONS AND OTHER
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Operating and
administrative recoveries
|
29
|
(11)
|
108
|
52
|
Realized foreign
exchange hedge settlements
|
(78)
|
(61)
|
(124)
|
(116)
|
Adjusted
EBITDA1
|
(49)
|
(72)
|
(16)
|
(64)
|
1
|
Schedules
reconciling adjuted EBITDA are available as Appendices to this news
release.
|
Operating and administrative recoveries 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 increased $23 million compared with the second quarter of
2019. Key quarter-over-quarter performance drivers included:
- Lower operating and administrative costs as a result of cost
containment actions, as well as timing related to the recovery of
certain operating and administrative costs allocated to the
business segments offset by
- Higher realized foreign exchange settlement losses primarily
due to a wider spread between the average exchange rate of
$1.39 for the second quarter of 2020
(Q2 2019:$1.34) and the second
quarter 2020 hedge rate of $1.29 (Q2
2019:$1.24).
CONFERENCE CALL
Enbridge will host a conference call and webcast on
July 29, 2020 at 9:00 a.m. Eastern Time (7:00
a.m. Mountain Time) to provide an enterprise wide business
update and review 2020 second quarter 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 5290259#. The call will be audio webcast live at
https://edge.media-server.com/mmc/p/ih678xin. It is recommended
that participants dial in or join the audio webcast fifteen minutes
prior to the scheduled start time. 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
5290259#).
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
The Company's Board of Directors declared the following
quarterly dividends, payable on September 1,
2020, to shareholders of record on August 14, 2020.
|
Dividend per
share
|
Common
Shares1
|
$0.81000
|
Preference Shares,
Series A
|
$0.34375
|
Preference Shares,
Series B
|
$0.21340
|
Preference Shares,
Series C2
|
$0.16779
|
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 P
|
$0.27369
|
Preference Shares,
Series R
|
$0.25456
|
Preference Shares,
Series 1
|
US$0.37182
|
Preference Shares,
Series 3
|
$0.23356
|
Preference Shares,
Series 5
|
US$0.33596
|
Preference Shares,
Series 7
|
$0.27806
|
Preference Shares,
Series 9
|
$0.25606
|
Preference Shares,
Series 113
|
$0.24613
|
Preference Shares,
Series 134
|
$0.19019
|
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 $0.81 from $0.738,
effective March 1, 2020.
|
2
|
The quarterly
dividend per share paid on Series C was decreased to $0.16779 from
$0.25458 on June 1, 2020 and was increased to $0.25458 from
$0.25305 on March 1, 2020, 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 11 was decreased to $0.24613 from
$0.275 on March 1, 2020, due to the reset of the annual dividend on
March 1, 2020, and every five years thereafter.
|
4
|
The quarterly
dividend per share paid on Series 13 was decreased to $0.19019 from
$0.275 on June 1, 2020, due to the reset of the annual dividend on
June 1, 2020, 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 Enbridge 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: Enbridge's corporate vision and strategy, including
strategic priorities and enablers; 2020 financial guidance; the
COVID-19 pandemic and the duration and impact thereof; anticipated
reductions in operating costs and deferrals of secured growth
capital spend; the expected supply of, demand for and prices of
crude oil, natural gas, natural gas liquids, liquified natural gas
and renewable energy; anticipated utilization of our existing
assets, including throughput on the Mainline; 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; expected debt-to-EBITDA ratio; financial strength and
flexibility; expectations on sources of liquidity and sufficiency
of financial resources; expected costs related to announced
projects and projects under construction and for maintenance;
expected in-service dates for announced projects and projects under
construction; expected capital expenditures; expected future growth
and expansion opportunities; 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 benefits of transactions, including the realization of
efficiencies and synergies; expected future actions of regulators
and courts; toll and rate case discussions and filings, including
Mainline Contracting and the anticipated benefits thereof; United
States Line 3 Replacement Program; Line 5 dual pipelines and
related matters; Line 10 of the Texas Eastern system; interest
rates; and exchange rates.
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 COVID-19 pandemic and
the duration and impact thereof; anticipated reductions in
operating costs and deferrals of secured growth; 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, including the current weakness and
volatility of such prices; anticipated utilization of our existing
assets; 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; impact of the Company's dividend policy on its future
cash flows; credit ratings; capital project funding; hedging
program; 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, interest rates and the COVID-19 pandemic
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 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; and the COVID-19 pandemic and the duration
and impact thereof.
Enbridge's forward-looking statements are subject to risks
and uncertainties pertaining to the realization of anticipated
benefits and synergies of projects and transactions; successful
execution of our strategic priorities, operating performance, the
Company's dividend policy, regulatory parameters, changes in
regulations applicable to the Company's business, litigation,
acquisitions and dispositions and other transactions, 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, political decisions,
exchange rates, interest rates, commodity prices, supply of and
demand for commodities and the COVID-19 pandemic, including but not
limited to those risks and uncertainties discussed in this 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:
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Enbridge Inc. –
Media
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Enbridge Inc. –
Investment Community
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Jesse
Semko
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Jonathan
Morgan
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Toll Free: (888)
992-0997
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Toll Free: (800)
481-2804
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Email:
media@enbridge.com
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Email:
investor.relations@enbridge.com
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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, and 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, 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
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Liquids
Pipelines
|
2,340
|
1,992
|
3,190
|
4,064
|
Gas Transmission and
Midstream
|
950
|
941
|
(104)
|
1,961
|
Gas Distribution and
Storage
|
383
|
390
|
987
|
1,052
|
Renewable Power
Generation
|
163
|
94
|
283
|
218
|
Energy
Services
|
(99)
|
221
|
22
|
227
|
Eliminations and
Other
|
261
|
107
|
(705)
|
355
|
EBITDA
|
3,998
|
3,745
|
3,673
|
7,877
|
Depreciation and
amortization
|
(949)
|
(842)
|
(1,831)
|
(1,682)
|
Interest
expense
|
(681)
|
(637)
|
(1,387)
|
(1,322)
|
Income tax
expense
|
(591)
|
(436)
|
(42)
|
(1,020)
|
(Earnings)/loss
attributable to noncontrolling interests
|
(36)
|
2
|
(5)
|
(35)
|
Preference share
dividends
|
(94)
|
(96)
|
(190)
|
(191)
|
Earnings
attributable to common shareholders
|
1,647
|
1,736
|
218
|
3,627
|
ADJUSTED EBITDA TO ADJUSTED EARNINGS
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
Liquids
Pipelines
|
1,744
|
1,766
|
3,663
|
3,495
|
Gas Transmission and
Midstream
|
975
|
936
|
2,072
|
1,976
|
Gas Distribution and
Storage
|
406
|
390
|
1,015
|
1,083
|
Renewable Power
Generation
|
150
|
100
|
268
|
223
|
Energy
Services
|
86
|
88
|
73
|
264
|
Eliminations and
Other
|
(49)
|
(72)
|
(16)
|
(64)
|
Adjusted
EBITDA
|
3,312
|
3,208
|
7,075
|
6,977
|
Depreciation and
amortization
|
(949)
|
(842)
|
(1,831)
|
(1,682)
|
Interest
expense
|
(695)
|
(643)
|
(1,391)
|
(1,311)
|
Income tax
expense
|
(404)
|
(279)
|
(855)
|
(767)
|
(Earnings)/loss
attributable to noncontrolling interests
|
(37)
|
1
|
(7)
|
(37)
|
Preference share
dividends
|
(94)
|
(96)
|
(190)
|
(191)
|
Adjusted
earnings
|
1,133
|
1,349
|
2,801
|
2,989
|
Adjusted earnings
per common share
|
0.56
|
0.67
|
1.39
|
1.48
|
EBITDA TO ADJUSTED EARNINGS
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars, except per share
amounts)
|
|
|
|
|
EBITDA
|
3,998
|
3,745
|
3,673
|
7,877
|
Adjusting
items:
|
|
|
|
|
Change in unrealized
derivative fair value (gain)/loss - Foreign exchange
|
(1,186)
|
(424)
|
770
|
(1,024)
|
Change in unrealized
derivative fair value (gain)/loss - Commodity prices
|
525
|
(139)
|
49
|
122
|
Equity investment
impairment - DCP Midstream
|
—
|
—
|
1,736
|
—
|
Equity investment
asset and goodwill impairment - DCP Midstream
|
—
|
—
|
324
|
—
|
Net inventory
adjustment - Energy Services
|
(340)
|
6
|
2
|
(85)
|
Employee severance,
transition and transformation costs
|
268
|
21
|
279
|
65
|
Texas Eastern
re-establishment of EDIT regulated liability
|
—
|
—
|
159
|
—
|
Other
|
47
|
(1)
|
83
|
22
|
Total adjusting
items
|
(686)
|
(537)
|
3,402
|
(900)
|
Adjusted
EBITDA
|
3,312
|
3,208
|
7,075
|
6,977
|
Depreciation and
amortization
|
(949)
|
(842)
|
(1,831)
|
(1,682)
|
Interest
expense
|
(681)
|
(637)
|
(1,387)
|
(1,322)
|
Income tax
expense
|
(591)
|
(436)
|
(42)
|
(1,020)
|
(Earnings)/loss
attributable to noncontrolling interests
|
(36)
|
2
|
(5)
|
(35)
|
Preference share
dividends
|
(94)
|
(96)
|
(190)
|
(191)
|
Adjusting items in
respect of:
|
|
|
Interest
expense
|
(14)
|
(6)
|
(4)
|
11
|
Income tax
expense
|
187
|
157
|
(813)
|
253
|
(Earnings)/loss
attributable to noncontrolling interests
|
(1)
|
(1)
|
(2)
|
(2)
|
Adjusted
earnings
|
1,133
|
1,349
|
2,801
|
2,989
|
Adjusted earnings
per common share
|
0.56
|
0.67
|
1.39
|
1.48
|
APPENDIX B
NON-GAAP RECONCILIATION – SEGMENTED EBITDA TO ADJUSTED
EBITDA
LIQUIDS PIPELINES
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
1,744
|
1,766
|
3,663
|
3,495
|
Change in unrealized
derivative fair value gain/(loss)
|
616
|
227
|
(450)
|
570
|
Asset write-down
loss
|
(13)
|
(1)
|
(13)
|
(1)
|
Employee severance,
transition and transformation costs
|
(7)
|
—
|
(7)
|
—
|
Other
|
—
|
—
|
(3)
|
—
|
Total
adjustments
|
596
|
226
|
(473)
|
569
|
EBITDA
|
2,340
|
1,992
|
3,190
|
4,064
|
GAS TRANSMISSION AND MIDSTREAM
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
975
|
936
|
2,072
|
1,976
|
Equity investment
impairment - DCP Midstream
|
—
|
—
|
(1,736)
|
—
|
Equity investment
asset and goodwill impairment - DCP Midstream
|
—
|
—
|
(324)
|
—
|
Equity earnings
adjustment - DCP Midstream
|
(22)
|
9
|
31
|
(4)
|
Texas Eastern
re-establishment of EDIT regulated liability
|
—
|
—
|
(159)
|
—
|
Other
|
(3)
|
(4)
|
12
|
(11)
|
Total
adjustments
|
(25)
|
5
|
(2,176)
|
(15)
|
Earnings/(loss)
before interest, income taxes and depreciation and
amortization
|
950
|
941
|
(104)
|
1,961
|
GAS DISTRIBUTION AND STORAGE
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited;
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
406
|
390
|
1,015
|
1,083
|
Change in unrealized
derivative fair value gain/(loss)
|
(15)
|
4
|
(9)
|
8
|
Employee severance,
transition and transformation costs
|
(8)
|
(4)
|
(15)
|
(39)
|
Other
|
—
|
—
|
(4)
|
—
|
Total
adjustments
|
(23)
|
—
|
(28)
|
(31)
|
EBITDA
|
383
|
390
|
987
|
1,052
|
RENEWABLE POWER GENERATION
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
150
|
100
|
268
|
223
|
Change in unrealized
derivative fair value gain
|
—
|
1
|
2
|
2
|
Disposition - MATL
transmission assets
|
13
|
—
|
13
|
—
|
Other
|
—
|
(7)
|
—
|
(7)
|
Total
adjustments
|
13
|
(6)
|
15
|
(5)
|
EBITDA
|
163
|
94
|
283
|
218
|
ENERGY SERVICES
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted
EBITDA
|
86
|
88
|
73
|
264
|
Change in unrealized
derivative fair value gain/(loss)
|
(525)
|
139
|
(49)
|
(122)
|
Net inventory
adjustment
|
340
|
(6)
|
(2)
|
85
|
Total
adjustments
|
(185)
|
133
|
(51)
|
(37)
|
Earnings/(loss)
before interest, income taxes and depreciation and
amortization
|
(99)
|
221
|
22
|
227
|
ELIMINATIONS AND OTHER
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Adjusted loss before
interest, income taxes, and depreciation and
amortization
|
(49)
|
(72)
|
(16)
|
(64)
|
Change in unrealized
derivative fair value gain/(loss)
|
585
|
192
|
(313)
|
444
|
Change in corporate
guarantee obligation
|
—
|
—
|
(74)
|
—
|
Investment write-down
loss
|
—
|
—
|
(43)
|
—
|
Employee severance,
transition and transformation costs
|
(253)
|
(17)
|
(257)
|
(26)
|
Other
|
(22)
|
4
|
(2)
|
1
|
Total
adjustments
|
310
|
179
|
(689)
|
419
|
Earnings/(loss)
before interest, income taxes and depreciation and
amortization
|
261
|
107
|
(705)
|
355
|
APPENDIX C
NON-GAAP RECONCILIATION – CASH PROVIDED BY OPERATING ACTIVITIES TO
DCF
|
Three months
ended
June 30,
|
Six months ended
June 30,
|
|
2020
|
2019
|
2020
|
2019
|
(unaudited,
millions of Canadian dollars)
|
|
|
|
|
Cash provided by
operating activities
|
2,416
|
2,494
|
5,225
|
4,670
|
Adjusted for changes
in operating assets and liabilities1
|
91
|
12
|
(103)
|
679
|
|
2,507
|
2,506
|
5,122
|
5,349
|
Distributions to
noncontrolling interests4
|
(88)
|
(54)
|
(164)
|
(100)
|
Preference share
dividends
|
(94)
|
(96)
|
(190)
|
(191)
|
Maintenance capital
expenditures2
|
(135)
|
(269)
|
(339)
|
(448)
|
Significant adjusting
items:
|
|
|
|
|
Other receipts of
cash not recognized in revenue3
|
81
|
33
|
132
|
86
|
Employee severance,
transition and transformation costs
|
268
|
27
|
279
|
71
|
Distributions from
equity investments in excess of cumulative
earnings4
|
176
|
129
|
253
|
190
|
Other
items
|
(278)
|
34
|
50
|
111
|
DCF
|
2,437
|
2,310
|
5,143
|
5,068
|
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-reports-strong-second-quarter-301101740.html
SOURCE Enbridge Inc.