Enbridge Reports Strong First Quarter 2023 Financial Results and Reaffirms Financial Guidance and Outlook
CALGARY, AB, May 5, 2023 /CNW/ - 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
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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."
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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.
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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.
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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.
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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.
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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
1Non-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.
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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.
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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.
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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.
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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
1Presented net of adjusting items.
2Consists of cash received, net of revenue recognized, for contracts under make-up rights and similar deferred revenue arrangements.
3Non-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;
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•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
1Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.
2Presented 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.
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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.
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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
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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.
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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
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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.
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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
18
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
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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
20
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
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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
1Changes in operating assets and liabilities, net of recoveries.
2Maintenance 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.
3Consists of cash received, net of revenue recognized, for contracts under make-up rights and similar deferred revenue arrangements.
