CALGARY,
AB, May 5, 2023 /PRNewswire/ - Enbridge Inc.
(Enbridge or the Company) (TSX: ENB) (NYSE: ENB) today reported
first quarter 2023 financial results, announced $0.3 billion of newly secured growth projects,
and reaffirmed its 2023 financial outlook.
Highlights
(All financial figures are
unaudited and in Canadian dollars unless otherwise noted. *
identifies non-GAAP financial measures. Please refer to
Non-GAAP Reconciliations Appendices.)
- First quarter GAAP earnings of $1.7
billion or $0.86 per common
share, compared with GAAP earnings of $1.9
billion or $0.95 per common
share in 2022
- Adjusted earnings* of $1.7
billion or $0.85 per common
share*, compared with $1.7 billion or
$0.84 per common share in 2022
- Adjusted earnings before interest, income taxes and
depreciation and amortization (EBITDA)* of $4.5 billion, compared with $4.1 billion in 2022
- Cash provided by operating activities of $3.9 billion, compared with $2.9 billion in 2022
- Distributable cash flow (DCF)* of $3.2
billion, compared with $3.1
billion in 2022
- Reaffirmed 2023 full year financial guidance for EBITDA and DCF
and medium-term outlook
- Reached an agreement in principle with shippers on the Mainline
pipeline system reinforcing the Mainline as a common carrier system
providing stable and competitive tolls
- Sanctioned previously announced Enbridge Houston Oil Terminal
(EHOT) for US$229 million which is
expected to add 2.7 million barrels of oil storage capacity which
further strengthens the system's value
- Launching the binding open season, discussed at Enbridge day,
on the Flanagan South Pipeline (FSP), highlighting the value of
Liquids Pipelines' existing downstream infrastructure and advancing
the Company's U.S. Gulf Coast strategy
- Announced the signing of a letter of intent with Yara
International to jointly construct a blue ammonia export production
facility at Enbridge Ingleside Energy Centre (EIEC)
- Signed a definitive agreement to acquire a 93.8% interest in
Aitken Creek Gas Storage facility and a 100% interest in Aitken
Creek North Gas Storage facility (collectively, Aitken Creek) for
$400 million adding 77 billion cubic
feet (Bcf) of gas storage capacity in British Columbia, Canada
- Closed the previously announced US$335
million acquisition of Tres
Palacios on April 3
- Concluded a successful open season on Texas Eastern
Transmission, LP (Texas Eastern) in the Appalachia region with
strong shipper interest
- Enbridge and its partners, EDF Renewables and CPP Investments,
awarded the right to develop the future Normandy offshore wind
farm, with an expected installed capacity of 1 GW
- Issued US$2.3 billion aggregate
amount of sustainability-linked bonds (SLB) in the U.S., further
strengthening Enbridge's commitment to its emissions reduction
goals
- On track to achieve Debt-to-EBITDA in the lower half of the
target range by year end, providing significant financial
flexibility and demonstrating commitment to our equity-self funding
model
CEO COMMENT
Greg Ebel, President and CEO
commented on the following:
"We are very pleased with a strong start to 2023 and how our
low-risk business model continues to deliver in all market cycles.
Our first quarter results were right in line with our expectations
despite extreme volatility in both financial and commodity markets.
Operationally, we continue to be a first-choice service provider to
our customers and during the quarter, this resulted in high
utilization across our systems and record volumes on the Mainline.
Enbridge is very proud of its long history of predictable financial
and operational performance. For 17 consecutive years, shareholders
have benefited from our ability to consistently meet financial
guidance and we have delivered 28 consecutive annual dividend
increases.
"The agreement in principle on a negotiated settlement on the
Mainline is a win-win-win for us, our customers and the markets we
serve. The new settlement builds on 27 years of incentive tolling
arrangements and keeps us aligned with our customers to maximize
throughput and maintain first-choice service standards, while
continuing to grow the system as needed. Under the agreement in
principle, it is expected that Enbridge will earn attractive
risk-adjusted within a Return-On-Equity (ROE) performance collar
which provides downside protection in the event of supply or demand
disruptions or unforeseen cost exposure, a feature that did not
exist in the previous Competitive Tolling Settlement. The new toll
also provides inflationary adjustments based on the U.S. consumer
price index and power indices.
"We continue to grow both our conventional and lower-carbon
businesses. We are pleased to have started the year by adding
to our secured growth backlog, which sits at $17 billion and securing a number of high-quality
acquisitions at attractive multiples.
"On the conventional side, we executed a strategic tuck-in
acquisition of the Aitken Creek natural gas storage facility
expanding our LNG-related footprint in B.C. We also received strong
customer interest from our open season to support transporting
much-needed natural gas out of the Appalachia region. On the Gulf
Coast, we sanctioned the Enbridge Houston Oil Terminal which will
strengthen our full-path service offering and furthers our
world-class export platform.
"On the lower-carbon front, we enhanced our renewable power
portfolio with the announcement of the successful award to design
and construct the Normandy offshore wind farm and announced a joint
venture with Yara International to construct a blue ammonia project
on the U.S. Gulf Coast.
"The joint venture with Yara to construct a uniquely positioned
blue ammonia project demonstrates how our existing conventional
asset base is leading to significant lower-carbon infrastructure
opportunities. The project will be ideally situated next to our
Texas Eastern pipeline system providing access to low-cost natural
gas feedstock and the deep-water docks at the Enbridge Ingleside
Energy Center (EIEC) which provide export access to global markets.
Our joint venture with OXY to develop a nearby CO2
sequestration hub will be used to sequester the project's captured
CO2 and the U.S. tax incentives provided by the
Inflation Reduction Act are expected to enhance project economics.
This project further positions EIEC to become one of the most
sustainable terminals in North
America producing globally competitive and decarbonized
ammonia.
"Our Debt-to-EBITDA remains in the bottom half of our range at
4.6x this quarter, providing us the financial flexibility to
continue adding to our organic growth backlog and to execute
selective tuck-in M&A. We opportunistically repurchased a small
amount of shares in April demonstrating our commitment to
increasing capital returns for shareholders. This focus on
financial discipline and maintaining a strong balance sheet ensures
excess investment capacity is available to continue delivering
growth and creating value for our shareholders."
FINANCIAL RESULTS SUMMARY
Financial results for the three months ended March 31, 2023 and 2022 are summarized in the
table below:
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars, except per share amounts; number of shares in
millions)
|
|
|
GAAP Earnings
attributable to common shareholders
|
1,733
|
1,927
|
GAAP Earnings per
common share
|
0.86
|
0.95
|
Cash provided by
operating activities
|
3,866
|
2,939
|
Adjusted
EBITDA1
|
4,468
|
4,147
|
Adjusted
Earnings1
|
1,726
|
1,705
|
Adjusted Earnings per
common share1
|
0.85
|
0.84
|
Distributable Cash
Flow1
|
3,180
|
3,072
|
Weighted average common
shares outstanding
|
2,025
|
2,026
|
1 Non-GAAP
financial measures. Please refer to Non-GAAP Reconciliations
Appendices.
|
GAAP earnings attributable to common shareholders for the first
quarter of 2023 decreased by $194 million or $0.09 per share compared with the same period in
2022, primarily due to a realized loss of $638 million ($479
million after-tax) due to termination of foreign exchange
hedges. This was partially offset by operating performance factors
discussed in detail below and a non-cash, unrealized derivative
fair value gain of $532 million
($399 million after-tax) in 2023,
compared to a gain of $433 million ($331 million after-tax) in 2022, reflecting
changes in the mark-to-market value of derivative financial
instruments used to manage foreign exchange risks.
The period-over-period comparability of GAAP earnings
attributable to common shareholders is 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. Refer to the Company's Management's
Discussion & Analysis for the first quarter of 2023 filed
in conjunction with the first quarter financial statements for a
detailed discussion of GAAP financial results.
Adjusted EBITDA in the first quarter of 2023 increased by
$321 million compared with the same period in 2022. This was
primarily driven by contributions from increased economic interests
in the Gray Oak Pipeline and the Cactus II Pipeline during the
second half of 2022 and early 2023, higher ex-Gretna volumes on the Mainline, recognition of
revenues attributable to the Texas Eastern rate case settlement and
the favorable effect of translating US dollar EBITDA at a higher
average exchange rate in 2023 compared to the same period of 2022.
These factors were partially offset by a decrease in earnings from
our reduced interest in DCP Midstream, LLC (DCP) and lower
commodity prices impacting DCP and Aux
Sable.
Adjusted earnings in the first quarter of 2023 increased by
$21 million, or $0.01 per share,
primarily due to higher Adjusted EBITDA contributions discussed
above, offset by higher financing costs primarily due to higher
interest rates and higher depreciation expense from assets placed
into service in last year.
DCF for the first quarter of 2023 increased by
$108 million, primarily due to higher Adjusted EBITDA
contributions partially offset by the timing of maintenance capital
spend, higher cash taxes on higher taxable earnings and higher
financing costs noted above.
Detailed financial information and analysis can be found below
under First Quarter 2023 Financial Results.
FINANCIAL OUTLOOK
The Company reaffirms its 2023 financial guidance for EBITDA and
DCF. Results for the first three months of 2023 are in line with
the Company's expectations and the Company anticipates that its
businesses will continue to experience strong capacity utilization
and operating performance through the balance of the year with
normal course seasonality. Forward financial guidance continues to
reflect projections within the settlement in principle on the
Mainline.
Strong operational performance is expected to be offset by
higher financing costs, due to increased interest rates, on
unhedged floating rate debt.
FINANCING UPDATE
In March of 2023, Enbridge issued a two-tranche U.S. debt
offering consisting of US$700 million
of 3-year callable notes and US$2.3
billion of 10-year sustainability-linked bonds for an
aggregate principal amount of US$3.0
billion. The SLB incorporates Enbridge's 35% emissions
intensity reduction target by 2030 and represents the largest
single SLB offering globally, demonstrating Enbridge's continuing
commitment to achieving its ESG targets. These debt offerings were
substantially hedged at favorable rates.
In April of 2023, the Company redeemed the US$600 million 6.375% Fixed-to-Floating Rate
Subordinated notes Series 2018-B.
The Company is rated BBB+, or equivalent, by all four of its
credit rating agencies, with stable outlooks, reflecting Enbridge's
financial strength and low-risk commercial model. Enbridge
anticipates exiting 2023 with its Debt-to-EBITDA metric again
within the lower half of the target range while continuing to fund
its secured capital growth program within its equity self-funding
model.
SECURED GROWTH PROJECT EXECUTION UPDATE
The Company added approximately $0.3
billion of capital to its secured capital program, including
the construction of the Enbridge Houston Oil Terminal, a storage
facility that is expected to have 2.7 million barrels of oil
storage capacity. The facility is planned to include connectivity
to the Seaway Jones Creek terminal with expansion optionality.
The Company's current secured growth program is now
approximately $17 billion with the
Company expecting to place $3.5
billion into service in 2023 inclusive of the Gas
Transmission's Modernization and Gas Distribution's Utility Growth
Capital programs. The secured growth program is supported by
commercial models consistent with Enbridge's low-risk model.
BUSINESS UPDATES
Mainline Tolling Agreement in Principle with Shippers on
Mainline Pipeline System
Enbridge has reached an agreement in principle on a negotiated
settlement (the settlement) with shippers for tolls on its Mainline
pipeline system. The settlement covers both the Canadian and US
portions of the Mainline and would see the Mainline continuing to
operate as a common carrier system available to all shippers on a
monthly nomination basis. The settlement is subject to regulatory
and other approvals and the term is seven and a half years through
the end of 2028, with new interim tolls to take effect on
July 1, 2023.
The settlement will include:
- an International Joint Toll (IJT), for heavy crude oil
movements from Hardisty to
Chicago, comprised of a Canadian
Mainline Toll of $1.65 per barrel
plus a Lakehead System Toll of US$2.57 per barrel, plus the applicable Line 3
Replacement surcharge;
- toll escalation for operation, administration, and power costs
tied to U.S. consumer price and power indices;
- tolls will continue to be distance and commodity adjusted, and
will utilize a dual currency IJT; and a financial performance
collar providing incentives for Enbridge to optimize throughput and
cost, but also providing downside protection in the event of
extreme supply or demand disruptions or unforeseen operating cost
exposure. This performance collar is intended to ensure the
Mainline will earn 11% to 14.5% returns, on a deemed 50% equity
capitalization, which is similar to the returns earned on average
during the previous tolling agreement.
Approximately 70% of Mainline deliveries are tolled under this
settlement, while approximately 30% of deliveries are tolled on a
full path basis to markets downstream of the Mainline. The other
continuing feature is that the Mainline toll will flex up or down
US$0.035 per barrel for 50,000 barrel
per day changes in throughput.
The expected financial outcome from this settlement is in line
with previously reported financial results after taking into
consideration the previously recognized provision, inflationary
cost adjustments and increased volumes.
As part of the settlement, Enbridge will be settling its
previously filed Lakehead cost of service application, currently
before the US' Federal Energy Regulatory Commission (FERC).
Expanding U.S. Gulf Coast service with previously announced
Enbridge Houston Oil Terminal
The Company has reached Final Investment Decision on the
Enbridge Houston Oil Terminal project which consists of four 680
kbbl tanks with a total capacity of 2.7 million barrels and
provides U.S. Gulf Coast storage to Enbridge Mainline customers.
EHOT is planned to include connectivity to the Seaway Jones Creek
terminal with expansion optionality to include Sea Port Oil
Terminal (SPOT) export deliveries and receipts from Gray Oak pipelines in Texas. Future phases could add up to 21
additional tanks bringing the total terminal capacity up to
approximately 15 million barrels. EHOT is expected to begin
operations in 2025.
Enbridge launching Flanagan South Open Season
Enbridge plans to launch a binding open season to leverage
available capacity on FSP to secure up to 95 kbpd of commitments.
In addition to increasing secured throughput on FSP, the volumes
would also secure long-haul demand on the entire Enbridge network,
upstream and downstream of FSP.
Enbridge and Yara International Partnering to Construct Blue
Ammonia Production Facility
On March 31, Enbridge signed a
letter of intent to jointly develop a world scale low-carbon blue
ammonia production facility with Yara International. The facility
is expected to have production capacity of 1.2 - 1.4 million tonnes
per annum and approximately 95% of the carbon dioxide generated
from production is anticipated to be captured and transported to
nearby permanent geological storage.
Based on early engineering and design, the investment is
expected to be in the range of US$2.6
billion to US$2.9 billion with
production starting in 2027/2028. Enbridge and Yara will be equal
partners in the project and Yara is expected to contract full
offtake from the facility, which further enhances the strategic
value and commercial viability of the project for Enbridge.
The construction of any facilities will be subject to receipt of
all necessary regulatory approvals.
Enbridge Acquires Aitken Creek Gas Storage Enhancing
Integrated Value Chain
Enbridge announced on May 1, 2023
that the Company has entered into a definitive agreement with
FortisBC to acquire a 93.8% interest in Aitken Creek for
$400 million, plus payment for
derivative contracts and gas inventory, subject to other customary
closing adjustments.
Aitken Creek is strategically located in British Columbia and is connected to BC
Pipelines, Alliance Pipeline and, North Montney Mainline Pipeline
and will be connected to LNG Canada via Coastal GasLink. Aitken
Creek currently has working gas capacity of approximately 77
Bcf.
The transaction is expected to close later in 2023, subject to
receipt of customary regulatory approvals and closing
conditions.
Texas Eastern Open Season
In April, the Company concluded a successful open season on
Texas Eastern in the Appalachia region. The Company is pleased with
shipper interest and is currently evaluating the results.
Tres Palacios Closing
On April 3, 2023, Enbridge
acquired Tres Palacios Holdings LLC (Tres
Palacios) for US$335 million
of cash, subject to customary closing adjustments. Tres Palacios is a natural gas storage facility
located in the US Gulf Coast and its infrastructure serves
Texas gas-fired power generation
and liquefied natural gas exports, as well as Mexico pipeline exports. Tres Palacios is comprised of three natural gas
storage salt caverns with a total FERC-certificated working gas
capacity of approximately 35 Bcf and an integrated 62-mile natural
gas header pipeline system, with eleven inter- and intrastate
natural gas pipeline connections.
Normandy Offshore Wind Farm
Following the fourth offshore wind tender launched in
January 2021, the French Ministry of
Energy Transition chose Eoliennes en Mer Manche Normandie SAS, the
project company owned by the EDF Renewables and Maple Power consortium (a joint venture of
Enbridge and CPP Investments), to design, build, operate and
decommission the Normandy offshore wind project.
The planned Normandy offshore wind farm will be located more
than 32 km off the north coast and is expected to be commissioned
around 2030. Over the next few years, planning and permitting will
be finalized, which will require minimal development expenditure
leading to construction later this decade. The fixed-bottom project
is expected to supply the equivalent of the annual consumption of
approximately 1.5 million people, more than half of the electricity
needs of the population of Normandy.
Normal Course Issuer Bid (NCIB) Execution
In April 2023, Enbridge
repurchased and cancelled approximately 0.5 million of its common
shares equating to approximately $25
million as part of its 2023 NCIB program.
Enbridge's NCIB program commenced on January 6, 2023 and expires on the earlier of
January 5, 2024 or when the Company
reaches the approved share repurchase limit of 27,938,163 common
shares to an aggregate amount of up to $1.5
billion.
Enbridge will continue to evaluate opportunities to repurchase
shares pursuant to the Company's NCIB program predicated upon
maintaining a strong balance sheet, strong business performance,
and evaluated against the availability and attractiveness of
alternative capital investment opportunities.
FIRST QUARTER 2023 FINANCIAL RESULTS
GAAP Segment EBITDA and Cash Flow from Operations
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Liquids
Pipelines
|
2,363
|
2,329
|
Gas Transmission and
Midstream
|
1,205
|
1,014
|
Gas Distribution and
Storage
|
716
|
665
|
Renewable Power
Generation
|
136
|
162
|
Energy
Services
|
1
|
(101)
|
Eliminations and
Other
|
6
|
355
|
EBITDA1
|
4,427
|
4,424
|
|
|
|
Earnings
attributable to common shareholders
|
1,733
|
1,927
|
|
|
|
Cash provided by
operating activities
|
3,866
|
2,939
|
1
Non-GAAP financial measure. Please refer to Non-GAAP
Reconciliations Appendices.
|
For purposes of evaluating performance, the Company makes
adjustments to GAAP reported earnings, segment EBITDA and cash flow
provided by operating activities for unusual, infrequent or other
non-operating factors, 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.
Adjusted EBITDA By Segment
Adjusted EBITDA generated from U.S. dollar denominated
businesses was translated to Canadian dollars at a higher average
exchange rate (C$1.35/US$) in the
first quarter of 2023 when compared with the same quarter in 2022
(C$1.27/US$). A significant portion
of U.S. dollar earnings is hedged under the Company's
enterprise-wide financial risk management program. The hedge
settlements are reported within Eliminations and Other.
Liquids Pipelines
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Mainline
System
|
1,337
|
1,284
|
Regional Oil Sands
System
|
231
|
245
|
Gulf Coast and
Mid-Continent System
|
419
|
347
|
Other
Systems1
|
367
|
341
|
Adjusted
EBITDA2
|
2,354
|
2,217
|
|
|
|
Operating Data
(average deliveries – thousands of bpd)
|
|
|
Mainline System -
ex-Gretna volume3
|
3,120
|
3,004
|
International Joint
Tariff (IJT)4
|
$4.27
|
$4.27
|
Competitive Tolling
Settlement (CTS) Surcharges4
|
$0.26
|
$0.26
|
Line 3 Replacement
Surcharge4,5
|
$0.83
|
$0.94
|
1
|
Other consists of
Southern Lights Pipeline, Express-Platte System, Bakken System, and
Feeder Pipelines and Other.
|
2
|
Non-GAAP financial
measure. Please refer to Non-GAAP Reconciliations
Appendices.
|
3
|
Mainline System
throughput volume represents Mainline System deliveries ex-Gretna,
Manitoba which is made up of U.S. and Eastern Canada deliveries
originating from Western Canada.
|
4
|
The IJT benchmark toll
and its components are set in U.S. dollars and the majority of the
Company's foreign exchange risk (FX) on the Canadian portion of the
Mainline was hedged for the first quarter of 2023. 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 with offsetting hedge settlements
reported within Eliminations and Other. The Company is currently
recording a provision against the IJT in recognition of the
uncertainty of the final Mainline tolls upon the completion of the
Mainline commercial framework negotiations.
|
5
|
Effective July 1, 2022,
the Line 3 Replacement Surcharge, exclusive of the receipt
terminalling surcharge, will be determined on a monthly basis by a
volume ratchet based on the 9-month rolling average of ex-Gretna
volumes. Each 50 kbpd volume ratchet above 2,835 kbpd (up to 3,085
kbpd) applies a US$0.035/bbl discount whereas each 50 kbpd volume
ratchet below 2,350 kbpd (down to 2,050 kbpd) adds a US$0.04/bbl
charge. Refer to Enbridge's Application for a Toll Order respecting
the implementation of the Line 3 Replacement Surcharges and CER
Order TO-003-2021 for further details.
|
Liquids Pipelines adjusted EBITDA increased $137 million
compared with the first quarter of 2022, primarily related to:
- higher contributions from increased economic interest in the
Gray Oak Pipeline and Cactus II Pipeline in the second half of 2022
and early 2023;
- higher contributions from the Mainline System which averaged
throughput of 3.1 million barrels per day (mmbpd) in 2023 as
compared to 3.0 mmbpd in 2022, net of the recognition of a higher
provision against the interim Mainline IJT; and
- favorable effect of translating US dollar EBITDA at a higher
average exchange rate in 2023 compared to the same period in 2022;
partially offset by
- a lower Line 3 Replacement surcharge with the implementation of
the volume discount ratchet in July
2022; and
- higher power costs as a result of increased volumes and power
prices.
Gas Transmission And Midstream
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
U.S. Gas
Transmission
|
925
|
759
|
Canadian Gas
Transmission
|
182
|
177
|
U.S.
Midstream
|
34
|
89
|
Other
|
48
|
33
|
Adjusted
EBITDA1
|
1,189
|
1,058
|
1 Non-GAAP
financial measure. Please refer to Non-GAAP Reconciliations
Appendices.
|
- Gas Transmission and Midstream adjusted EBITDA increased
$131 million compared with the first
quarter of 2022, primarily related to:
- recognition of revenues attributable to the Texas Eastern rate
case settlement; and
- the favorable effect of translating US dollar EBITDA at a
higher average exchange rate in 2023 compared to the same period in
2022; partially offset by
- a reduction in earnings from our investment in DCP as a result
of our decreased interest due to the joint venture merger
transaction with Phillips 66 that closed during the third quarter
in 2022; and
- lower commodity prices impacting our DCP and Aux Sable joint ventures.
Gas Distribution And Storage
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Enbridge Gas Inc.
(EGI)
|
699
|
656
|
Other
|
17
|
18
|
Adjusted
EBITDA1
|
716
|
674
|
|
|
|
Operating
Data
|
|
|
EGI
|
|
|
Volumes
(billions of cubic feet)
|
767
|
816
|
Number of active
customers2 (millions)
|
3.9
|
3.8
|
Heating degree
days3
|
|
|
Actual
|
1,728
|
2,028
|
Forecast based on
normal weather4
|
1,892
|
1,921
|
1
|
Non-GAAP financial
measure. Please refer to Non-GAAP Reconciliations
Appendices.
|
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.
Adjusted EBITDA was positively impacted by $42 million
primarily explained by the following significant business
factors:
- higher distribution charges resulting from increases in rates
and customer base; and
- favorable recognition timing of storage demand and
transportation costs of $63 million,
which will be reversed over the remainder of 2023; partially offset
by
- the impact of warmer than normal weather in the first quarter
of 2023 and colder than normal weather in the first quarter of
2022, resulting in a negative EBITDA impact of approximately
$63 million year-over-year.
When compared with the normal weather forecast embedded in
rates, the weather in the first quarter of 2023 negatively impacted
EBITDA by $36 million compared to a
positive impact of $27 million for
the same period in 2022.
Renewable Power Generation
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Adjusted
EBITDA1
|
139
|
160
|
1 Non-GAAP
financial measure. Please refer to Non-GAAP Reconciliations
Appendices.
|
Renewable Power Generation adjusted EBITDA decreased
$21 million compared with the first quarter of 2022 primarily
related to:
- weaker wind resources at Canadian wind facilities; and
- lower energy pricing at European offshore wind facilities.
Energy Services
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Adjusted
EBITDA1
|
(6)
|
(71)
|
1 Non-GAAP
financial measure. Please refer to Non-GAAP Reconciliations
Appendices.
|
Adjusted EBITDA from Energy Services is dependent on market
conditions and results achieved in one period may not be indicative
of results to be achieved in future periods.
Energy Services adjusted EBITDA increased $65 million
compared with the first quarter of 2022 primarily related to:
- expiration of transportation commitments;
- less pronounced market structure backwardation as compared to
the same period of 2022; and
- favorable margins realized on facilities where Enbridge holds
capacity obligations and storage opportunities.
Eliminations and Other
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Operating and
administrative recoveries
|
47
|
68
|
Realized foreign
exchange hedge settlement gains
|
29
|
41
|
Adjusted
EBITDA1
|
76
|
109
|
1 Non-GAAP
financial measure. Please refer to Non-GAAP Reconciliations
Appendices.
|
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. U.S.
dollar denominated earnings within operating segment results are
translated at average foreign exchange rates during the quarter,
and the impact of settlements made under the Company's enterprise
foreign exchange hedging program are captured in this corporate
segment.
Eliminations and Other adjusted EBITDA decreased
$33 million compared with the first quarter of 2022 due
to:
- lower realized foreign exchange gains on hedge
settlements.
Distributable Cash Flow
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars; number of shares in millions)
|
|
|
Liquids
Pipelines
|
2,354
|
2,217
|
Gas Transmission and
Midstream
|
1,189
|
1,058
|
Gas Distribution and
Storage
|
716
|
674
|
Renewable Power
Generation
|
139
|
160
|
Energy
Services
|
(6)
|
(71)
|
Eliminations and
Other
|
76
|
109
|
Adjusted
EBITDA1,3
|
4,468
|
4,147
|
Maintenance
capital
|
(173)
|
(104)
|
Interest
expense1
|
(926)
|
(733)
|
Current income
tax1
|
(180)
|
(173)
|
Distributions to
noncontrolling interests
|
(92)
|
(60)
|
Cash distributions in
excess of equity earnings1
|
65
|
33
|
Preference share
dividends
|
(84)
|
(91)
|
Other receipts of cash
not recognized in revenue2
|
83
|
41
|
Other non-cash
adjustments
|
19
|
12
|
DCF3
|
3,180
|
3,072
|
Weighted average
common shares outstanding
|
2,025
|
2,026
|
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
Non-GAAP financial measures. Please refer to Non-GAAP
Reconciliations Appendices.
|
First quarter 2023 DCF increased $108 million compared with
the same period of 2022 primarily due to operational factors
discussed above contributing to higher Adjusted EBITDA, as well
as:
- higher receipts of cash not recognized in revenue related to
unshipped contracted volumes at EIEC and FSP that have a
contractual right to ship at a later day; partially offset by
- higher interest expense due to higher interest rates impacting
floating-rate debt;
- the timing of maintenance capital spend; and
- higher distributions to noncontrolling interests from the sale
of 11.57% non-operating interest in seven Enbridge-operated
pipelines to Athabasca Indigenous Investments in Q3, 2022.
Adjusted Earnings
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars, except per share amounts)
|
|
|
Adjusted
EBITDA1,2
|
4,468
|
4,147
|
Depreciation and
amortization
|
(1,182)
|
(1,065)
|
Interest
expense2
|
(915)
|
(722)
|
Income
taxes2
|
(513)
|
(526)
|
Noncontrolling
interests2
|
(48)
|
(27)
|
Preference share
dividends
|
(84)
|
(102)
|
Adjusted
earnings1
|
1,726
|
1,705
|
Adjusted earnings
per common share1
|
0.85
|
0.84
|
1
Non-GAAP financial measures. Please refer to Non-GAAP
Reconciliations Appendices.
|
2
Presented net of adjusting items.
|
Adjusted earnings increased $21 million and adjusted earnings
per share increased by $0.01 when
compared with the first quarter in 2022 primarily due to
operational factors discussed above contributing to higher Adjusted
EBITDA, offset by:
- higher interest expense due to higher interest rates impacting
floating-rate debt; and
- higher depreciation from assets place into service in
2022.
CONFERENCE CALL
Enbridge will host a conference call and webcast on May 5,
2023 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time)
to provide a business update and review 2023 first quarter results.
Analysts, members of the media and other interested parties can
access the call toll free at 1-800-606-3040. The call will be audio
webcast live at https://events.q4inc.com/attendee/641243612. It is
recommended that participants dial in or join the audio webcast
fifteen minutes prior to the scheduled start time. A webcast replay
will be available soon after the conclusion of the event and a
transcript will be posted to the website. The replay will be
available for seven days after the call toll-free 1-(800)-606-3040
(conference ID: 9581867).
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 May 2, 2023, our Board of
Directors declared the following quarterly dividends. All dividends
are payable on June 1, 2023 to
shareholders of record on May 15,
2023.
|
Dividend per
share
|
Common
Shares1
|
$0.88750
|
Preference Shares,
Series A
|
$0.34375
|
Preference Shares,
Series B
|
$0.32513
|
Preference Shares,
Series D2
|
$0.33825
|
Preference Shares,
Series F
|
$0.29306
|
Preference Shares,
Series H
|
$0.27350
|
Preference Shares,
Series L
|
US$0.36612
|
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 11
|
$0.24613
|
Preference Shares,
Series 13
|
$0.19019
|
Preference Shares,
Series 15
|
$0.18644
|
Preference Shares,
Series 193
|
$0.38825
|
1
|
The quarterly dividend
per common share was increased 3.2% to $0.8875 from $0.86,
effective March 1, 2023.
|
2
|
The quarterly dividend
per share paid on Preference Shares, Series D was increased to
$0.33825 from $0.27875 on March 1, 2023, due to reset of the annual
dividend on March 1, 2023.
|
3
|
The quarterly dividend
per share paid on Preference Shares, Series 19 was increased to
$0.38825 from $0.30625 on March 1, 2023, due to reset of the annual
dividend on March 1, 2023.
|
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 our
strategic priorities and outlook; 2023 financial guidance,
including projected DCF per share and adjusted EBITDA and expected
growth thereof; expected dividends, dividend growth and dividend
policy; expected supply of, demand for, exports of and prices of
crude oil, natural gas, natural gas liquids (NGL), liquified
natural gas (LNG) and renewable energy; energy transition and low
carbon energy and our approach thereto; environmental, social and
governance (ESG) goals, practices and performance; anticipated
utilization of our assets; expected EBITDA and expected adjusted
EBITDA; expected earnings/(loss) and adjusted earnings/(loss);
expected DCF and DCF per share; expected future cash flows;
expected shareholder returns and asset returns; expected
performance of the Company's businesses; financial strength and
flexibility; financing costs; expectations on leverage, including
debt-to EBITDA ratio; sources of liquidity and sufficiency of
financial resources; expected in-service dates and costs related to
announced projects and projects under construction; investable
capacity, and capital allocation framework and priorities; share
repurchases under our normal course issuer bid; impact of weather
and seasonality; expected future growth and expansion
opportunities, including secured growth program, development
opportunities, customer growth and low carbon opportunities and
strategy, including with respect to our Enbridge Houston Oil
Terminal, Normandy offshore wind farm, and joint venture projects
with Yara and OXY; expectations about our joint venture partners'
ability to complete and finance projects; expected acquisitions,
dispositions and other transactions, and the timing and benefits
thereof, including Aitken Creek Gas Storage and Tres Palacios; expected future actions and
decisions of regulators and courts and the timing and impact
thereof; and toll and rate case discussions and filings, including
with respect to the Mainline settlement in principle, Texas Eastern
and Flanagan South Pipeline, and anticipated timing and impact
therefrom.
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, NGL, LNG and renewable energy;
prices of crude oil, natural gas, NGL, LNG and renewable energy;
anticipated utilization of our assets; exchange rates; inflation;
interest rates; availability and price of labour and construction
materials; the stability of our supply chain; operational
reliability and performance; maintenance of support and regulatory
approvals for our projects; anticipated in-service dates; weather;
announced and potential acquisition, disposition and other
corporate transactions and projects and the timing and benefits
thereof; governmental legislation; litigation; credit ratings;
hedging program; expected EBITDA and expected adjusted EBITDA;
expected earnings/(loss) and adjusted earnings/(loss); expected
earnings/(loss) or adjusted earnings/(loss) per share; expected
future cash flows; expected future DCF and DCF per share; estimated
future dividends; financial strength and flexibility; debt and
equity market conditions; and general economic and competitive
conditions. Assumptions regarding the expected supply of and demand
for crude oil, natural gas, NGL, LNG 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 our services. Similarly, exchange rates,
inflation and interest rates impact the economies and business
environments in which we operate and may impact levels of demand
for our services and cost of inputs and are therefore inherent in
all forward-looking statements. 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 stability of our supply chain; 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; the timing and closing of acquisitions, dispositions and
other transactions and the realization of anticipated benefits
therefrom; and customer, government, court and regulatory approvals
on construction and in-service schedules.
Enbridge's forward-looking statements are subject to risks
and uncertainties pertaining to the successful execution of our
strategic priorities; operating performance; regulatory parameters;
litigation; acquisitions and dispositions and other transactions,
and the realization of anticipated benefits therefrom; project
approval and support; renewals of rights-of-way; weather; economic
and competitive conditions; global geopolitical conditions;
political decisions; public opinion; dividend policy; changes in
tax laws and tax rates; exchange rates; interest rates; inflation;
commodity prices; and supply of and demand for commodities,
including but not limited to those risks and uncertainties
discussed in this news release and in Enbridge's other filings with
Canadian and U.S. securities regulators. The impact of any one
assumption, risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty, as
these are interdependent and our 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 statement 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 us or persons acting on our behalf, are expressly
qualified in their entirety by these cautionary statements.
ABOUT ENBRIDGE INC.
At Enbridge, we safely connect
millions of people to the energy they rely on every day, fueling
quality of life through our North American natural gas, oil or
renewable power networks and our growing European offshore wind
portfolio. We're investing in modern energy delivery infrastructure
to sustain access to secure, affordable energy and building on two
decades of experience in renewable energy to advance new
technologies including wind and solar power, hydrogen, renewable
natural gas and carbon capture and storage. We're committed to
reducing the carbon footprint of the energy we deliver, and to
achieving net zero greenhouse gas emissions by 2050. Headquartered
in Calgary, Alberta, Enbridge's
common shares trade under the symbol ENB on the Toronto (TSX) and New York (NYSE) stock exchanges. To learn
more, visit us at enbridge.com
None of the information contained in, or connected to,
Enbridge's website is incorporated in or otherwise forms part of
this news release.
FOR FURTHER
INFORMATION PLEASE CONTACT:
|
|
|
Enbridge Inc. –
Media
|
|
Enbridge Inc. –
Investment Community
|
Jesse Semko
|
|
Rebecca
Morley
|
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 EBITDA, 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.
EBITDA represents earnings before interest, tax,
depreciation and amortization.
Adjusted EBITDA represents EBITDA adjusted for unusual,
infrequent or other non-operating factors on both a consolidated
and segmented basis. Management uses EBITDA and 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.
This news release also contains references to Debt-to-EBITDA, a
non-GAAP ratio which utilizes adjusted EBITDA as one of its
components. Debt-to-EBITDA is used as a liquidity measure to
indicate the amount of adjusted earnings to pay debt, as calculated
on the basis of generally accepted accounting principles in
the United States of America (U.S.
GAAP), before covering interest, tax, depreciation and
amortization.
Reconciliations of forward-looking non-GAAP financial measures
and non-GAAP ratios to comparable
GAAP measures are not available due to the challenges and
impracticability of estimating certain items, particularly certain
contingent liabilities and non-cash unrealized derivative fair
value losses and gains subject to market variability. Because of
those challenges, a reconciliation of forward-looking non-GAAP
financial measures and non-GAAP ratios is not available without
unreasonable effort.
Our non-GAAP financial measures and non-GAAP ratios described
above are not measures that have standardized meaning prescribed by
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
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Liquids
Pipelines
|
2,363
|
2,329
|
Gas Transmission and
Midstream
|
1,205
|
1,014
|
Gas Distribution and
Storage
|
716
|
665
|
Renewable Power
Generation
|
136
|
162
|
Energy
Services
|
1
|
(101)
|
Eliminations and
Other
|
6
|
355
|
EBITDA
|
4,427
|
4,424
|
Depreciation and
amortization
|
(1,146)
|
(1,055)
|
Interest
expense
|
(905)
|
(719)
|
Income tax
expense
|
(510)
|
(593)
|
Earnings attributable
to noncontrolling interests
|
(49)
|
(28)
|
Preference share
dividends
|
(84)
|
(102)
|
Earnings
attributable to common shareholders
|
1,733
|
1,927
|
ADJUSTED EBITDA TO ADJUSTED EARNINGS
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars, except per share amounts)
|
|
|
Liquids
Pipelines
|
2,354
|
2,217
|
Gas Transmission and
Midstream
|
1,189
|
1,058
|
Gas Distribution and
Storage
|
716
|
674
|
Renewable Power
Generation
|
139
|
160
|
Energy
Services
|
(6)
|
(71)
|
Eliminations and
Other
|
76
|
109
|
Adjusted
EBITDA
|
4,468
|
4,147
|
Depreciation and
amortization
|
(1,182)
|
(1,065)
|
Interest
expense
|
(915)
|
(722)
|
Income tax
expense
|
(513)
|
(526)
|
Earnings attributable
to noncontrolling interests
|
(48)
|
(27)
|
Preference share
dividends
|
(84)
|
(102)
|
Adjusted
earnings
|
1,726
|
1,705
|
Adjusted earnings
per common share
|
0.85
|
0.84
|
EBITDA TO ADJUSTED EARNINGS
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars, except per share amounts)
|
|
|
EBITDA
|
4,427
|
4,424
|
Adjusting
items:
|
|
|
Change in unrealized
derivative fair value (gain)/loss - Foreign exchange
|
(532)
|
(433)
|
Change in unrealized
derivative fair value (gain)/loss - Commodity prices
|
(8)
|
21
|
CTS Realized hedge
loss
|
638
|
—
|
Litigation claim
settlement
|
(68)
|
—
|
Equity earnings
adjustment - DCP Midstream, LLC
|
(8)
|
63
|
Net inventory
adjustment
|
1
|
9
|
Impairment of lease
assets
|
—
|
44
|
Transition and
transformation costs
|
—
|
18
|
Other
|
18
|
1
|
Total adjusting
items
|
41
|
(277)
|
Adjusted
EBITDA
|
4,468
|
4,147
|
Depreciation and
amortization
|
(1,146)
|
(1,055)
|
Interest
expense
|
(905)
|
(719)
|
Income tax
expense
|
(510)
|
(593)
|
Earnings attributable
to noncontrolling interests
|
(49)
|
(28)
|
Preference share
dividends
|
(84)
|
(102)
|
Adjusting items in
respect of:
|
|
|
Depreciation and
amortization
|
(36)
|
(10)
|
Interest
expense
|
(10)
|
(3)
|
Income tax
expense
|
(3)
|
67
|
Earnings attributable
to noncontrolling interests
|
1
|
1
|
Adjusted
earnings
|
1,726
|
1,705
|
Adjusted earnings
per common share
|
0.85
|
0.84
|
APPENDIX B
NON-GAAP RECONCILIATION – ADJUSTED EBITDA TO
SEGMENTED EBITDA
LIQUIDS PIPELINES
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Adjusted
EBITDA
|
2,354
|
2,217
|
Change in unrealized
derivative fair value gain - Foreign exchange
|
613
|
122
|
CTS Realized hedge
loss
|
(638)
|
—
|
Litigation claim
settlement
|
68
|
—
|
Other
|
(34)
|
(10)
|
Total
adjustments
|
9
|
112
|
EBITDA
|
2,363
|
2,329
|
GAS TRANSMISSION AND MIDSTREAM
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Adjusted
EBITDA
|
1,189
|
1,058
|
Equity earnings
adjustment - DCP Midstream, LLC
|
8
|
(63)
|
Other
|
8
|
19
|
Total
adjustments
|
16
|
(44)
|
EBITDA
|
1,205
|
1,014
|
GAS DISTRIBUTION AND STORAGE
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Adjusted
EBITDA
|
716
|
674
|
Transition and
transformation costs
|
—
|
(9)
|
Total
adjustments
|
—
|
(9)
|
EBITDA
|
716
|
665
|
RENEWABLE POWER GENERATION
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Adjusted
EBITDA
|
139
|
160
|
Change in unrealized
derivative fair value gain - Foreign exchange
|
2
|
2
|
Other
|
(5)
|
—
|
Total
adjustments
|
(3)
|
2
|
EBITDA
|
136
|
162
|
ENERGY SERVICES
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Adjusted
EBITDA
|
(6)
|
(71)
|
Change in unrealized
derivative fair value gain/(loss) - Commodity prices
|
8
|
(21)
|
Net inventory
adjustment
|
(1)
|
(9)
|
Total
adjustments
|
7
|
(30)
|
EBITDA
|
1
|
(101)
|
ELIMINATIONS AND OTHER
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Adjusted
EBITDA
|
76
|
109
|
Change in unrealized
derivative fair value gain/(loss) - Foreign exchange
|
(83)
|
309
|
Impairment of lease
assets
|
—
|
(44)
|
Transition and
transformation costs
|
—
|
(18)
|
Captive insurance
investments mark-to-market
|
13
|
—
|
Other
|
—
|
(1)
|
Total
adjustments
|
(70)
|
246
|
EBITDA
|
6
|
355
|
APPENDIX C
NON-GAAP RECONCILIATION – CASH PROVIDED BY
OPERATING ACTIVITIES TO DCF
|
Three months ended
March 31,
|
|
2023
|
2022
|
(unaudited; millions
of Canadian dollars)
|
|
|
Cash provided by
operating activities
|
3,866
|
2,939
|
Adjusted for changes in
operating assets and liabilities1
|
(914)
|
177
|
|
2,952
|
3,116
|
Distributions to
noncontrolling interests
|
(92)
|
(60)
|
Preference share
dividends
|
(84)
|
(91)
|
Maintenance capital
expenditures2
|
(173)
|
(104)
|
Significant adjusting
items:
|
|
|
Other receipts of cash
not recognized in revenue3
|
83
|
41
|
Distributions from
equity investments in excess of cumulative
earnings4
|
155
|
183
|
CTS Realized hedge
loss
|
638
|
—
|
Litigation claim
settlement
|
(68)
|
—
|
Other items
|
(231)
|
(13)
|
DCF
|
3,180
|
3,072
|
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:https://www.prnewswire.com/news-releases/enbridge-reports-strong-first-quarter-2023-financial-results-and-reaffirms-financial-guidance-and-outlook-301816658.html
SOURCE Enbridge Inc.