ENB 8-K
Enbridge Inc (ENB)
8-K
2023-02-10
For: 2023-02-10
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April 05, 2026
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): February 10, 2023
(Exact Name of Registrant as Specified in Charter)
| (State or Other Jurisdiction of Incorporation) | (Commission File Number) | (IRS Employer Identification No.) | ||||||
(Address of Principal Executive Offices) (Zip Code)
1-403 -231-3900
(Registrant’s telephone number, including area code)
Not Applicable
(Former Name or Former Address, if Changed Since Last Report)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Item 2.02. Results of Operations and Financial Condition.
We issued a press release on February 10, 2023 announcing our financial results for the fourth quarter and full year ended December 31, 2022, which is attached hereto as Exhibit 99.1. This information is not deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any registration statements filed under the Securities Act of 1933, as amended.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits
Reference is made to the “Index of Exhibits” following the signature page, which is hereby incorporated into this Item.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| ENBRIDGE INC. (Registrant) | |||||||||||
| Date: | By: | /s/ Karen K.L. Uehara | |||||||||
| Karen K.L. Uehara | |||||||||||
| Vice President and Corporate Secretary (Duly Authorized Officer) | |||||||||||
Index of Exhibits
| Exhibit Number | Description | |||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document. | |||||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document. | |||||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document. | |||||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | |||||||
NEWS RELEASE
Enbridge Reports Strong 2022 Financial Results and Advances Strategic Priorities
CALGARY, AB, February 10, 2023 /CNW/ - Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported strong fourth quarter and full year 2022 financial results, reaffirmed its 2023 financial outlook and provided a quarterly business update.
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.)
•Full year GAAP earnings of $2.6 billion or $1.28 per common share, compared with GAAP earnings of $5.8 billion or $2.87 per common share in 2021
•Adjusted earnings* of $5.7 billion or $2.81 per common share*, compared with $5.6 billion or $2.74 per common share in 2021
•Adjusted earnings before interest, income taxes and depreciation and amortization (EBITDA)* of $15.5 billion, compared with $14.0 billion in 2021
•Cash provided by operating activities of $11.2 billion, compared with $9.3 billion in 2021
•Distributable cash flow (DCF)* of $11.0 billion or $5.42 per common share*, compared with $10.0 billion or $4.96 per common share in 2021
•Exited 2022 in a strong financial position with Debt to EBITDA of 4.7x
•Reaffirmed 2023 full year guidance range for EBITDA of $15.9 billion to $16.5 billion and DCF per share of $5.25 to $5.65
•Increased the 2023 quarterly dividend by 3.2% to $0.8875 ($3.55 annualized) per share reflecting the 28th consecutive annual increase
•Increased ownership in Gray Oak Pipeline by a further 10% bringing Enbridge's interest to 68.5%
•Toll Settlement reached with B.C. Pipeline shippers and approved by the CER for a five-year term ending in 2026
•Rate case settlement reached with Texas Eastern Transmission, LP (TETLP) shippers and approved by the Federal Energy Regulatory Commission (FERC)
•Completed the previously announced US$1.5 billion investment in Woodfibre LNG
•Successfully placed into service, $4B of conventional and renewable projects in 2022
•Advanced $18 billion portfolio of growth and expansion projects across the enterprise
•Advanced low-carbon strategy announcing a partnership with Oxy Low Carbon Ventures to transport and sequester carbon dioxide in the Corpus Christi area
•Filed rebasing and incentive rate-setting application at Enbridge Gas Inc. (EGI) for the next five years
•Announced the renewal of Enbridge's normal course issuer bid (NCIB) of up to $1.5 billion
•Issued a $900 million Sustainability-Linked Bond (SLB) in Canada, further strengthening Enbridge's commitment to its emissions reduction goals
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CEO COMMENT
Greg Ebel, President and CEO commented the following:
"We ended the year with strong utilization, operational and safety performance across our business. Despite the uncertainty and volatility of 2022, our full year results came in at the top half of our guidance range, reflecting the strength of our four core businesses and the resiliency of our low-risk business model.
"We made substantial progress delivering on our strategic priorities, which is a testament to the entire Enbridge team. We placed another $4 billion of capital into service and sanctioned $8 billion of new organic growth. We sold non-core assets, demonstrating our commitment to recycling capital at attractive valuations, and our balance sheet continues to be in great shape, with Debt to EBITDA in the bottom half of our range at 4.7x. These actions have set us up well for 2023 and beyond.
"As we look forward, it is clear the world needs all forms of energy to meet demand. At the same time, there is a global imperative to reduce emissions. Balancing these priorities is critical and remains foundational to our strategy.
"We will continue to expand, modernize and reduce emissions from our conventional business to meet our customers' needs, and increase investments in lower-carbon opportunities that complement our existing assets. Our balance sheet strength, disciplined approach to capital allocation, and proven execution capability will enable us to drive growth and create value for our shareholders. Our extensive footprint puts us in an enviable position to deliver safe, secure, affordable and sustainable energy to our customers.
"I'm excited and honored to be leading the Enbridge team in its next phase of growth. I'd like to thank Al Monaco and the entire leadership team for transforming Enbridge into a diversified energy delivery company. As a team, we will build on this legacy and continue to position Enbridge as the first choice energy provider for our customers, investors, employees and the communities we serve."
FINANCIAL RESULTS SUMMARY
Financial results for the three months and year ended December 31, 2022 and 2021 are summarized in the table below:
| Three months ended December 31, | Twelve months ended December 31, | |||||||||||||
| 2022 | 2021 | 2022 | 2021 | |||||||||||
| (unaudited; millions of Canadian dollars, except per share amounts; number of shares in millions) | ||||||||||||||
| GAAP Earnings attributable to common shareholders | (1,067) | 1,840 | 2,589 | 5,816 | ||||||||||
| GAAP Earnings per common share | (0.53) | 0.91 | 1.28 | 2.87 | ||||||||||
| Cash provided by operating activities | 3,613 | 1,890 | 11,230 | 9,256 | ||||||||||
Adjusted EBITDA1 | 3,911 | 3,687 | 15,531 | 14,001 | ||||||||||
Adjusted Earnings1 | 1,271 | 1,376 | 5,692 | 5,551 | ||||||||||
Adjusted Earnings per common share1 | 0.63 | 0.68 | 2.81 | 2.74 | ||||||||||
Distributable Cash Flow1 | 2,663 | 2,487 | 10,983 | 10,041 | ||||||||||
| Weighted average common shares outstanding | 2,025 | 2,024 | 2,025 | 2,023 | ||||||||||
1 Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.
GAAP Earnings attributable to common shareholders for the fourth quarter of 2022 decreased by $2.9 billion or $1.44 per share compared with the same period in 2021 and includes certain infrequent or other non-operating factors, primarily explained by a non-cash goodwill impairment of $2.5 billion relating to the Gas Transmission reporting unit as a result of the increased cost of capital, partially offset by the operating performance factors discussed in detail below.
2
On a full year basis for 2022, GAAP earnings attributable to common shareholders was negatively impacted by the goodwill impairment discussed above, as well as non-cash, net unrealized derivative fair value losses of $1.3 billion ($964 million after-tax) in 2022, compared with unrealized gains of $197 million ($150 million after-tax) in 2021, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks. These were partially offset by a non-cash gain of $1.1 billion ($732 million after-tax) on the closing of the joint venture merger transaction with Phillips 66 (P66) realigning our effective economic interests in Gray Oak and DCP Midstream LLC.
The period-over-period comparability of GAAP earnings attributable to common shareholders is impacted by certain other 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 annual Management's Discussion & Analysis for 2022 filed in conjunction with the year-end financial statements for a detailed discussion of GAAP financial results.
Adjusted EBITDA in the fourth quarter of 2022 increased by $224 million compared with the same period in 2021. This was primarily driven by higher contributions from new assets placed into service including the U.S. portion of the Line 3 Replacement Project, which came into service in the fourth quarter of 2021, the acquisition of Enbridge Ingleside Energy Center (EIEC), as well as the recognition of revenues from increased rates on TETLP as a result of its recent rate case settlement. The translation of U.S. denominated earnings also contributed to higher EBITDA in the period. The average CAD to USD exchange rate for the fourth quarter of 2022 was $1.36 compared with $1.26 for the same period in 2021.
Adjusted EBITDA for the year ended December 31, 2022 increased by $1.5 billion compared with 2021. This is primarily driven by the impact of the operating factors listed above, as well as translation of U.S dollar denominated earnings. The average CAD to USD exchange rate in 2022 was $1.30 compared with $1.25 in 2021.
Adjusted earnings in the fourth quarter of 2022 decreased by $105 million, or $0.05 per share, primarily due to higher financing costs from rising interest rates on floating-rate debt, and increased depreciation expense on new assets placed into service in the fourth quarter of 2021; partially offset by higher Adjusted EBITDA contributions.
Adjusted earnings for the year ended December 31, 2022 increased by $141 million compared with 2021. This is primarily driven by the impact of higher Adjusted EBITDA, partially offset by the higher financing costs discussed above.
DCF for the fourth quarter of 2022 increased by $176 million, or $0.08 per share, primarily due to higher Adjusted EBITDA contributions and higher equity distributions as a result of strong operating performance from joint venture investments including Alliance Pipeline, as well as increased economic interest in the Gray Oak and Cactus II pipelines, partially offset by higher maintenance capital spend, higher financing costs and higher cash taxes on higher taxable earnings.
DCF for the year ended December 31, 2022, increased by $942 million compared with 2021. This is primarily driven by the same operating factors as listed above.
Detailed financial information and analysis can be found below under Fourth Quarter and Year-End 2022 Financial Results.
FINANCIAL OUTLOOK
The Company reaffirmed its 2023 financial guidance, which includes adjusted EBITDA between $15.9 billion and $16.5 billion and DCF per share between $5.25 to $5.65.
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Growth in 2023 is anticipated to be driven by strong Mainline utilization, full-year contributions from the TETLP rate settlement, rate escalators and customer additions at EGI, full-year contributions from projects placed into service during 2022 and the impact of foreign exchange rates, partially offset by higher financing costs and distributions to non-controlling interests from the sale of an interest in certain Regional Oil Sands assets.
Enbridge increased its 2023 quarterly dividend by 3.2% to $0.8875 ($3.55 annualized) per share, commencing with the dividend payable on March 1, 2023 to shareholders of record on February 15, 2023.
FINANCING UPDATE
During the fourth quarter of 2022, Enbridge Inc. issued $2 billion of debt financings consisting of:
•$600 million of 5-year senior notes;
•$900 million of 10-year senior notes (SLB); and
•$500 million of 30-year senior notes.
These debt offerings were substantially hedged at favorable rates, with proceeds used to pay down existing indebtedness, fund capital projects, and for other general corporate purposes. The SLB terms are consistent with Enbridge's SLB framework announced in 2021, which incorporates emissions and diversity metrics into the financing terms. This approach to financing reinforces Enbridge's continuing commitment to achieving the ESG targets it set out in its November 2020 ESG Goals. The Company's sustainability-linked financings now total approximately CAD$4.3 billion.
During the fourth quarter, TETLP issued US$600 million of 10-year Senior Notes in the U.S. private debt market.
The Company is currently rated BBB+, or equivalent, by all four of its credit rating agencies, with stable outlooks, reflecting Enbridge’s sector leading financial strength and its low-risk commercial model. The Company's Debt to EBITDA metric at year-end 2022 was approximately 4.7x, within the lower-half of the Company’s target range of 4.5-5.0x. 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 utilizing internally generated cash flows, proceeds from recently completed capital recycling transactions and future debt financings.
SECURED GROWTH PROJECT EXECUTION UPDATE
In 2022, Enbridge placed approximately $4 billion of growth projects into service across each of its four business, which are expected to provide strong EBITDA and DCF contributions in 2023 including:
•Gas Distribution's $1.2 billion 2022 Utility Growth Capital;
•Gas Transmission's US$0.6 billion 2022 Modernization program;
•US$0.3 billion Vito Oil and Gas Pipelines, which provides for offshore production to the U.S. Gulf Coast, and is mechanically complete;
•$0.2 billion East-West Tie Line, which provides reliable, long-term electricity to Northwest Ontario;
•US$0.1 billion Gulfstream Phase VI, providing capacity into Florida; and
•$0.9 billion, 480-megawatt, St. Nazaire Project, France's first commercial-scale offshore wind project.
During the year, Enbridge sanctioned $8 billion of new organic growth capital and the Company's current secured growth program is now approximately $18 billion.
Funding of the secured growth program will be provided for entirely through the Company's $5-6 billion of annual investable capacity.
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OTHER BUSINESS UPDATES
Continuing to Advance U.S. Gulf Coast Crude Oil Strategy
In January 2023, Enbridge acquired an additional 10% ownership in the Gray Oak Pipeline from Rattler Midstream, a subsidiary of Diamondback Energy, bringing the Company's economic interest to 68.5%. This acquisition further expands Enbridge's presence in the Permian, aligns with the Company's export strategy, and simplifies the ownership structure. Gray Oak is competitively positioned to remain well-utilized as Permian Basin oil production grows. In combination with EIEC and Cactus II Pipeline, the Company is well-positioned to meet local U.S. Gulf Coast demand and access global export markets.
T- North Open Season Postponed
Westcoast Energy Inc. (Westcoast) has been asked by customers to postpone the open season to the second half of 2023 to give them an opportunity to further assess their long-term development plans and gas transportation requirements. Accordingly, Westcoast decided to terminate this open season in January 2023, and plans to initiate an open season in the second half of 2023.
EGI Successfully Files 2024 Rebasing and Incentive Rate-setting Mechanism Application
In October 2022, EGI filed its application to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application and framework seeks approval to establish 2024 base rates on a cost-of-service basis and to establish a price cap rate setting mechanism to be used for the remainder of the IR term (2025-2028). The Ontario Energy Board (OEB) has determined it will hear the application in two phases, with Phase 1 addressing items that affect rates effective January 1, 2024 and Phase 2 addressing items that will affect rates subsequent to January 1, 2024. An OEB decision is expected on Phase 1 of the application in the second half of 2023.
FERC Approves Texas Eastern Transmission Rate Case Settlement
On September 8, 2022, TETLP filed an uncontested Stipulation and Agreement with the FERC to resolve all issues from the rate proceeding. The comment and reply period ended October 11, 2022. The FERC approved the Stipulation and Agreement on November 30, 2022, and the Stipulation and Agreement became effective on January 1, 2023.
BC Pipeline Rate Case Settlement
In the fourth quarter, B.C. Pipeline reached a Toll Settlement (the Settlement) with shippers that was approved by the Canada Energy Regulator (CER) in December. The Settlement spans a 5-year term inclusive of 2022-2026, providing toll stability over a longer term than previous settlement agreements, and maintains the low-risk, cost-of-service structure that is characteristic of the B.C. Pipeline. The Settlement also includes new incentive mechanisms that provide opportunities to generate incremental earnings through volume optimization and emission reduction initiatives undertaken by B.C. Pipeline.
Completed Partnership Agreement in Woodfibre LNG
The Company completed its previously announced agreement with Pacific Energy Corporation Limited (Pacific Energy) to jointly invest in the construction and operation of the Woodfibre LNG project. Enbridge has a 30% ownership stake and Pacific Energy retains the remaining 70% stake in the project. Enbridge and Pacific Energy will make pro-rata contributions during construction, and in exchange for its capital contributions, Enbridge will receive a preferred equity interest that provides predictable future cash flows. Pacific Energy will manage daily operations, while both partners will jointly participate in the project's execution and governance.
Preliminary construction activities, including site preparation are underway. The project remains on track for its targeted in-service date of 2027.
5
Carbon Capture and Storage (CCS)
Enbridge and Oxy Low Carbon Ventures (OLCV) announced that they are jointly developing a carbon dioxide (CO2) sequestration hub in the Corpus Christi area of the Texas Gulf Coast. Enbridge and OLCV would leverage each company's strengths to advance the development of a sequestration hub and associated transportation infrastructure. Enbridge would develop, construct and operate the pipeline facilities and OLCV would develop, construct and operate the sequestration facilities. The hub is expected to provide CO2 solutions for Enbridge's proposed facilities as well as other point source emitters in the Corpus Christi area.
Mainline Commercial Framework
The Company is currently advancing two potential commercial frameworks for the Canadian Mainline in parallel: i) a new incentive rate-making agreement and ii) a Canadian Mainline cost-of-service application. Either framework is anticipated to provide attractive risk-adjusted returns and the range of financial outcomes is not expected to materially impact Enbridge's financial outlook.
Enbridge has consulted with industry participants regarding the Canadian Mainline and shared incentive rate making proposals, supported by detailed cost information, with an industry representative group comprised of a cross-section of participants, including producers, integrated producers and refiners.
Enbridge has already filed and is currently negotiating with shippers a cost-of-service application with the FERC in the U.S for the base toll component of the Lakehead System (U.S. portion of the Mainline).
Enbridge is collecting interim tolls, which are subject to refund, related to its July 1, 2021 Lakehead cost-of-service filing. On the Canadian Mainline, Enbridge is also collecting, per the terms of the Competitive Toll Settlement (CTS), interim tolls consistent with the tolls in effect on June 30, 2021 when the CTS agreement expired and which are also subject to refund. The Company's financial results and forward 2023 financial guidance reflects a provision in recognition of the uncertainty of future mainline tolls.
Normal Course Issuer Bid
On January 4, 2023, the TSX approved Enbridge's NCIB to purchase, for cancellation, up to 27,938,163 of its outstanding common shares for an aggregate amount of up to $1.5 billion. The NCIB commenced on January 6, 2023, and expires on the earlier date of January 5, 2024, when the bid expires, or when the Company reaches its share repurchase limit.
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FOURTH QUARTER AND YEAR-END 2022 FINANCIAL RESULTS
GAAP Segment EBITDA and Cash Flow from Operations
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
| Liquids Pipelines | 2,271 | 2,141 | 8,364 | 7,897 | |||||||||||||
| Gas Transmission | (1,258) | 946 | 3,126 | 3,671 | |||||||||||||
| Gas Distribution & Storage | 459 | 743 | 1,827 | 2,117 | |||||||||||||
| Renewable Power Generation | (127) | 146 | 262 | 508 | |||||||||||||
| Energy Services | (69) | 66 | (417) | (313) | |||||||||||||
| Eliminations and Other | 160 | 165 | (1,124) | 356 | |||||||||||||
EBITDA1 | 1,436 | 4,207 | 12,038 | 14,236 | |||||||||||||
| Earnings attributable to common shareholders | (1,067) | 1,840 | 2,589 | 5,816 | |||||||||||||
| Cash provided by operating activities | 3,613 | 1,890 | 11,230 | 9,256 | |||||||||||||
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$1.36/US$) in the fourth quarter of 2022 when compared with the fourth quarter in 2021 (C$1.26/US$). On a full year basis, adjusted EBITDA generated from U.S. dollar denominated business was translated at C$1.30/US$, compared with C$1.25/US$ in 2021. A portion of U.S. dollar earnings is hedged under the Company's enterprise-wide financial risk management program. The offsetting hedge settlements are reported within Eliminations and Other.
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Liquids Pipelines
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
| Mainline System | 1,343 | 1,202 | 5,121 | 4,466 | |||||||||||||
| Regional Oil Sands System | 224 | 234 | 918 | 927 | |||||||||||||
| Gulf Coast and Mid-Continent System | 405 | 317 | 1,411 | 1,019 | |||||||||||||
Other Systems1 | 355 | 355 | 1,458 | 1,319 | |||||||||||||
Adjusted EBITDA2 | 2,327 | 2,108 | 8,908 | 7,731 | |||||||||||||
Operating Data (average deliveries – thousands of bpd) | |||||||||||||||||
Mainline System - ex-Gretna volume3 | 3,077 | 3,014 | 2,957 | 2,764 | |||||||||||||
International Joint Tariff (IJT)4 | $4.27 | $4.27 | $4.27 | $4.27 | |||||||||||||
Competitive Tolling Settlement (CTS) Surcharges4 | $0.26 | $0.26 | $0.26 | $0.26 | |||||||||||||
Line 3 Replacement Surcharge4,5,6 | $0.87 | $0.94 | $0.90 | $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 on the Canadian portion of the Mainline is hedged. The Canadian portion of the Mainline represents approximately 55% of total Mainline System revenue and the average effective FX rate realized for the Canadian portion of the Mainline during the fourth quarter of 2022 was C$1.24/US$ (Q4 2021: C$1.27/US$) and for the full year 2022 C$1.24/US$ (2021: C$1.25/$US). The U.S. portion of the Mainline System is subject to FX translation similar to the Company’s other U.S. based businesses, which are translated at the average spot rate for a given period. A portion of this U.S. dollar translation exposure is hedged under the Company's enterprise-wide financial risk management program 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 The interim surcharge of US$0.20 for the Canadian portion of the Line 3 Replacement Project, which was placed into service on December 1, 2019, was collected until October 1, 2021. With the completion of the U.S. portion of the Line 3 Replacement Project on October 1, 2021, the interim surcharge was replaced by the full Line 3 Replacement surcharge.
6 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 50kbpd volume ratchet above 2,835 kbpd (up to 3,085 kbpd) applies a US$0.035/bbl discount whereas each 50kbpd 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 $219 million compared with the fourth quarter of 2021, primarily related to:
•higher Mainline System ex-Gretna throughput driven by a full quarter of operations of the U.S. portion of the Line 3 Replacement Project (L3R), and the timing of the recognition of the provision against the interim Mainline IJT toll, which in the fourth quarter of 2021 included six months of provision; partially offset by higher power costs as a result of increased volumes and higher power prices;
•higher contributions from the Gulf Coast and Mid-Continent System due to higher volumes on the Flanagan South Pipeline and Spearhead Pipeline, increased economic interest in the Gray Oak Pipeline as a result of the joint venture merger transaction with P66, and increased economic interest in the Cactus II Pipeline; partially offset by higher power costs and lower contributions from the Seaway Crude Pipeline System;
•the positive effect of translating U.S. dollar denominated EBITDA at a higher Canadian to U.S. dollar average exchange rate, which is partially offset in the Eliminations and Other segment as part of the Company's enterprise-wide financial risk management program.
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Full year 2022 Liquids Pipelines adjusted EBITDA increased $1.2 billion compared with 2021 and was primarily impacted by the same factors discussed above as well as full year contributions from incremental L3R capacity, a full year of the L3R surcharge, full year contributions from EIEC and higher contributions from the Bakken System due to higher volumes.
Gas Transmission And Midstream
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
| U.S. Gas Transmission | 844 | 670 | 3,216 | 2,905 | |||||||||||||
| Canadian Gas Transmission | 181 | 125 | 666 | 537 | |||||||||||||
| U.S. Midstream | 44 | 91 | 378 | 260 | |||||||||||||
| Other | 48 | 36 | 157 | 148 | |||||||||||||
Adjusted EBITDA1 | 1,117 | 922 | 4,417 | 3,850 | |||||||||||||
1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
•
Gas Transmission and Midstream adjusted EBITDA increased $195 million compared with the fourth quarter of 2021, primarily related to:
•recognition of revenues attributable to the Texas Eastern rate case resulting from a FERC-approved Stipulation and Agreement;
•recognition of revenues attributable to the B.C. Pipeline rate settlement, higher Canadian Gas Transmission contributions from the T-South Expansion and Spruce Ridge projects placed fully into service in the fourth quarter of 2021 and higher contributions from Enbridge's investment in the Alliance Pipeline due to wider AECO-Chicago basis differential; and
•the positive effect of translating U.S. dollar denominated EBITDA at a higher Canadian to U.S. dollar average exchange rate within U.S. Gas Transmission and U.S. Midstream, which is partially offset in the Eliminations and Other segment as part of the Company's enterprise-wide financial risk management program; partially offset by
•lower U.S. midstream contributions resulting from reduced economic interest in DCP, as a result of the joint venture merger transaction with P66 that closed during the third quarter of 2022 and lower fractionation margins impacting Aux Sable
Full year 2022 Gas Transmission and Midstream adjusted EBITDA increased $567 million compared with 2021, due to the factors discussed above as well as:
•higher commodity prices benefiting DCP and Aux Sable joint ventures, and full year contributions from the T-South Expansion and Spruce Ridge projects;
•the Cameron and Middlesex Extension projects and the Appalachia to Market project which were placed into service during the fourth quarter of 2021; partially offset by
•higher operating costs.
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Gas Distribution And Storage
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
| EGI | 452 | 427 | 1,810 | 1,744 | |||||||||||||
| Other | 15 | 23 | 46 | 109 | |||||||||||||
Adjusted EBITDA1 | 467 | 450 | 1,856 | 1,853 | |||||||||||||
| Operating Data | |||||||||||||||||
| EGI | |||||||||||||||||
Volumes (billions of cubic feet) | 606 | 560 | 2,162 | 1,943 | |||||||||||||
Number of active customers2 (millions) | 3.9 | 3.8 | |||||||||||||||
Heating degree days3 | |||||||||||||||||
Actual | 1,239 | 1,144 | 3,841 | 3,494 | |||||||||||||
Forecast based on normal weather4 | 1,306 | 1,317 | 3,841 | 3,855 | |||||||||||||
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.
Gas Distribution & Storage adjusted EBITDA increased $17 million compared with the fourth quarter of 2021 primarily related to:
•the positive impact of colder weather than for the same period of 2021;
•higher distribution rates and customer growth; partially offset by
•higher operating expenses from higher employee costs and maintenance and integrity spend; and
•the absence of earnings from Noverco Inc due to the sale of the minority investment in December 2021
Full year 2022 Gas Distribution and Storage adjusted EBITDA increased $3 million compared with 2021, due to the same factors discussed above. On a full year basis, when compared with the normal weather forecast embedded in rates, colder than normal weather in 2022 positively impacted EGI's 2022 EBITDA by approximately $17 million while warmer than normal weather in 2021 negatively impacted 2021 EBITDA by approximately $55 million.
10
Renewable Power Generation
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
Adjusted EBITDA1 | 122 | 140 | 522 | 496 | |||||||||||||
1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
Renewable Power Generation adjusted EBITDA decreased $18 million compared with the fourth quarter of 2021 primarily related to lower North American wind production and higher operating expenses.
Full year 2022 Renewable Power Generation adjusted EBITDA increased $26 million due to the factors discussed above, as well as:
•higher energy pricing and production at European offshore wind facilities;
•stronger full year wind resources at Canadian and US onshore wind facilities;
•the absence in 2022 of the adverse effects from the major winter storm in Texas during February 2021; partially offset by
•the absence in 2022 of a promote fee received in the first quarter of 2021 associated with the closing of the sale of 49% of interest in three European offshore wind projects to Canada Pension Plan Investment Board.
Energy Services
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
Adjusted EBITDA1 | (62) | (83) | (364) | (360) | |||||||||||||
1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
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 $21 million compared with the fourth quarter of 2021. The increase is the result of significant compression of differentials and limited storage opportunities in the fourth quarter of 2021 which were less pronounced in the same period of 2022.
Full year 2022 Energy Services adjusted EBITDA decreased $4 million. In both 2022 and 2021 there was pronounced market structure backwardation and significant compression of location differentials in certain markets. Results in 2021 include adverse impacts from the major winter storm experienced across the US Midwest during February 2021.
11
Eliminations and Other
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
| Operating and administrative recoveries | 8 | 103 | 115 | 256 | |||||||||||||
| Realized foreign exchange hedge settlement gains/(losses) | (68) | 47 | 77 | 175 | |||||||||||||
Adjusted EBITDA1 | (60) | 150 | 192 | 431 | |||||||||||||
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 offsetting 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 $210 million compared with the fourth quarter of 2021 due to:
•realized foreign exchange losses on hedge settlements compared with gains in the same quarter of 2021 with the average foreign exchange rate for the fourth quarter of 2022 was $1.36 (Q4 2021: $1.26) compared with the average hedge rate of $1.32 for the fourth quarter of 2022 (Q4 2021: $1.30); and
•the timing of recovery of operating and administrative costs from the business segments and higher compensation costs
Full year 2022 Eliminations and Other adjusted EBITDA decreased $239 million compared with 2021 due to lower realized foreign exchange gains on hedge settlements and an increase in employee costs. On a full year basis, the average exchange rate for 2022 was $1.30 (2021: $1.25) compared with the full-year 2022 hedge rate of $1.32 (2021: $1.30).
12
Distributable Cash Flow
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars; number of shares in millions) | |||||||||||||||||
Liquids Pipelines | 2,327 | 2,108 | 8,908 | 7,731 | |||||||||||||
Gas Transmission and Midstream | 1,117 | 922 | 4,417 | 3,850 | |||||||||||||
Gas Distribution and Storage | 467 | 450 | 1,856 | 1,853 | |||||||||||||
Renewable Power Generation | 122 | 140 | 522 | 496 | |||||||||||||
Energy Services | (62) | (83) | (364) | (360) | |||||||||||||
Eliminations and Other | (60) | 150 | 192 | 431 | |||||||||||||
Adjusted EBITDA1,3 | 3,911 | 3,687 | 15,531 | 14,001 | |||||||||||||
| Maintenance capital | (354) | (274) | (820) | (686) | |||||||||||||
Interest expense1 | (885) | (747) | (3,242) | (2,724) | |||||||||||||
Current income tax1 | (204) | (142) | (595) | (352) | |||||||||||||
Distributions to noncontrolling interests1 | (75) | (64) | (259) | (271) | |||||||||||||
Cash distributions in excess of equity earnings1 | 254 | 65 | 407 | 313 | |||||||||||||
| Preference share dividends | (84) | (93) | (338) | (367) | |||||||||||||
Other receipts of cash not recognized in revenue2 | 65 | 53 | 238 | 127 | |||||||||||||
Other non-cash adjustments | 35 | 2 | 61 | — | |||||||||||||
DCF3 | 2,663 | 2,487 | 10,983 | 10,041 | |||||||||||||
Weighted average common shares outstanding | 2,025 | 2,024 | 2,025 | 2,023 | |||||||||||||
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.
Fourth quarter 2022 DCF increased $176 million compared with the same period of 2021 primarily due to operational factors discussed above contributing to higher Adjusted EBITDA and higher cash distributions in excess of equity earnings as a result of the joint venture merger transaction with P66 which increased Enbridge's economic interest in the Gray Oak and Cactus II pipelines, Alliance and International Wind; partially offset by lower distributions from DCP as a result of the transaction with P66; partially offset by:
•higher maintenance capital spend across the organization;
•higher interest expense due to higher interest rates impacting floating-rate debt and higher debt balances associated with advancing the Company's secured growth program in 2022; and
•higher current income tax due to higher taxable earnings and an increase in U.S. minimum taxes.
Full year 2022 DCF increased $942 million compared with the same period of 2021 primarily due to operational factors discussed above as well as higher receipts of cash not recognized in revenue related to unshipped contracted volumes at the EIEC that have a contractual right to ship at a later date offset by lower capitalized interest associated with the U.S. portion of the L3R Project placed into service in the fourth quarter of 2021.
13
Adjusted Earnings
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
(unaudited; millions of Canadian dollars, except per share amounts) | |||||||||||||||||
Adjusted EBITDA1,2 | 3,911 | 3,687 | 15,531 | 14,001 | |||||||||||||
Depreciation and amortization | (1,155) | (1,047) | (4,427) | (3,852) | |||||||||||||
Interest expense2 | (872) | (734) | (3,196) | (2,675) | |||||||||||||
Income taxes2 | (493) | (406) | (1,767) | (1,429) | |||||||||||||
Noncontrolling interests2 | (35) | (31) | (93) | (121) | |||||||||||||
Preference share dividends | (85) | (93) | (356) | (373) | |||||||||||||
Adjusted earnings1 | 1,271 | 1,376 | 5,692 | 5,551 | |||||||||||||
Adjusted earnings per common share1 | 0.63 | 0.68 | 2.81 | 2.74 | |||||||||||||
1Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.
2Presented net of adjusting items.
Adjusted earnings for the fourth quarter decreased $105 million and adjusted earnings per share decreased $0.05 when compared with the fourth quarter in 2021 primarily due to operational factors discussed above contributing to higher Adjusted EBITDA, offset by:
•higher depreciation expense on new assets placed into service throughout 2021, including the U.S. portion of the L3R Project, which was placed into service in the fourth quarter and EIEC acquired in October 2021;
•higher interest expense due to higher interest rates impacting floating-rate debt and higher debt balances associated with advancing the Company's secured growth program in 2021; and
•higher income taxes from higher taxable earnings and an increase in U.S. minimum taxes.
Full year adjusted earnings increased $141 million and adjusted earnings per share increased $0.07 compared with 2021 due to the same operational factors discussed previously in Adjusted EBITDA by Segments, partially offset by the higher depreciation discussed above and by lower capitalized interest associated with the U.S. portion of the L3R Project placed into service in the fourth quarter of 2021.
14
CONFERENCE CALL
Enbridge will host a conference call and webcast on February 10, 2023 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide an enterprise-wide business update and review 2022 fourth and full-year 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/914273160. 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 1-800-770-2030 (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 November 29, 2022, our Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2023 to shareholders of record on February 15, 2023.
| Dividend per share | |||||
Common Shares1 | $0.88750 | ||||
| Preference Shares, Series A | $0.34375 | ||||
Preference Shares, Series B2 | $0.32513 | ||||
| Preference Shares, Series D | $0.27875 | ||||
| Preference Shares, Series F | $0.29306 | ||||
| Preference Shares, Series H | $0.27350 | ||||
Preference Shares, Series L3 | 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 19 | $0.30625 | ||||
1 The quarterly dividend per common share was increased 3.2% to $0.8875 from $0.860, effective March 1, 2023.
2 The quarterly dividend per share paid on Preference Shares Series B was increased to $0.32513 from $0.21340 on June 1, 2022, due to reset of the annual dividend on June 1, 2022 and every five years thereafter. Following the date of conversion of Preference Shares Series C, on June 1, 2022 all outstanding Preference Shares Series C were converted to Preference Shares Series B.
3 The quarterly dividend per share paid on Series L was increased to US$0.36612 from US$0.30993 on September 1, 2022, due to reset of the annual dividend on September 1, 2022, and every five years thereafter.
15
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 U.S. Gulf Coast crude oil strategy, T-North expansion, Woodfibre LNG project, and carbon capture and storage projects; expected acquisitions, dispositions and other transactions, and the timing and benefits thereof; 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, 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; the COVID-19 pandemic and the duration and impact thereof; 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, interest rates and the COVID-19 pandemic 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. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected EBITDA, expected adjusted EBITDA, expected earnings/(loss), expected adjusted earnings/(loss), expected DCF and associated per share amounts and estimated
16
future dividends. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and construction materials; the 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; customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes; and the COVID-19 pandemic and the duration and impact thereof.
Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the 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; supply of and demand for commodities; and the COVID-19 pandemic, 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.
17
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: [email protected] | Email: [email protected] | |||||||
18
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.
19
APPENDIX A
NON-GAAP RECONCILIATIONS – ADJUSTED EBITDA AND ADJUSTED EARNINGS
CONSOLIDATED EARNINGS
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
Liquids Pipelines | 2,271 | 2,141 | 8,364 | 7,897 | |||||||||||||
Gas Transmission and Midstream | (1,258) | 946 | 3,126 | 3,671 | |||||||||||||
Gas Distribution and Storage | 459 | 743 | 1,827 | 2,117 | |||||||||||||
Renewable Power Generation | (127) | 146 | 262 | 508 | |||||||||||||
Energy Services | (69) | 66 | (417) | (313) | |||||||||||||
Eliminations and Other | 160 | 165 | (1,124) | 356 | |||||||||||||
EBITDA | 1,436 | 4,207 | 12,038 | 14,236 | |||||||||||||
| Depreciation and amortization | (1,122) | (1,047) | (4,317) | (3,852) | |||||||||||||
| Interest expense | (863) | (732) | (3,179) | (2,655) | |||||||||||||
| Income tax expense | (560) | (463) | (1,604) | (1,415) | |||||||||||||
(Earnings)/loss attributable to noncontrolling interests | 126 | (32) | 65 | (125) | |||||||||||||
| Preference share dividends | (84) | (93) | (414) | (373) | |||||||||||||
| Earnings attributable to common shareholders | (1,067) | 1,840 | 2,589 | 5,816 | |||||||||||||
ADJUSTED EBITDA TO ADJUSTED EARNINGS
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars, except per share amounts) | |||||||||||||||||
Liquids Pipelines | 2,327 | 2,108 | 8,908 | 7,731 | |||||||||||||
Gas Transmission and Midstream | 1,117 | 922 | 4,417 | 3,850 | |||||||||||||
Gas Distribution and Storage | 467 | 450 | 1,856 | 1,853 | |||||||||||||
Renewable Power Generation | 122 | 140 | 522 | 496 | |||||||||||||
Energy Services | (62) | (83) | (364) | (360) | |||||||||||||
Eliminations and Other | (60) | 150 | 192 | 431 | |||||||||||||
Adjusted EBITDA | 3,911 | 3,687 | 15,531 | 14,001 | |||||||||||||
| Depreciation and amortization | (1,155) | (1,047) | (4,427) | (3,852) | |||||||||||||
| Interest expense | (872) | (734) | (3,196) | (2,675) | |||||||||||||
| Income tax expense | (493) | (406) | (1,767) | (1,429) | |||||||||||||
| Earnings attributable to noncontrolling interests | (35) | (31) | (93) | (121) | |||||||||||||
| Preference share dividends | (85) | (93) | (356) | (373) | |||||||||||||
| Adjusted earnings | 1,271 | 1,376 | 5,692 | 5,551 | |||||||||||||
| Adjusted earnings per common share | 0.63 | 0.68 | 2.81 | 2.74 | |||||||||||||
20
EBITDA TO ADJUSTED EARNINGS
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars, except per share amounts) | |||||||||||||||||
EBITDA | 1,436 | 4,207 | 12,038 | 14,236 | |||||||||||||
| Adjusting items: | |||||||||||||||||
| Change in unrealized derivative fair value (gain)/loss - Foreign exchange | (486) | (112) | 1,265 | (197) | |||||||||||||
| Change in unrealized derivative fair value (gain)/loss - Commodity prices | 49 | (155) | 27 | (53) | |||||||||||||
| Gain on joint venture merger transaction | — | — | (1,076) | — | |||||||||||||
| Goodwill impairment | 2,475 | — | 2,475 | — | |||||||||||||
| Equity investment impairment | — | — | — | 111 | |||||||||||||
Equity earnings adjustment - DCP Midstream, LLC | (16) | (60) | 10 | 44 | |||||||||||||
| Assets impairment | 436 | 7 | 542 | 7 | |||||||||||||
| Woodfibre LNG transaction costs | 114 | — | 114 | — | |||||||||||||
| Other | (97) | (200) | 136 | (147) | |||||||||||||
| Total adjusting items | 2,475 | (520) | 3,493 | (235) | |||||||||||||
| Adjusted EBITDA | 3,911 | 3,687 | 15,531 | 14,001 | |||||||||||||
| Depreciation and amortization | (1,122) | (1,047) | (4,317) | (3,852) | |||||||||||||
| Interest expense | (863) | (732) | (3,179) | (2,655) | |||||||||||||
| Income tax expense | (560) | (463) | (1,604) | (1,415) | |||||||||||||
| Earnings attributable to noncontrolling interests | 126 | (32) | 65 | (125) | |||||||||||||
| Preference share dividends | (84) | (93) | (414) | (373) | |||||||||||||
| Adjusting items in respect of: | |||||||||||||||||
| Depreciation and amortization | (33) | — | (110) | — | |||||||||||||
| Interest expense | (9) | (2) | (17) | (20) | |||||||||||||
| Income tax expense | 67 | 57 | (163) | (14) | |||||||||||||
| Earnings attributable to noncontrolling interests | (161) | 1 | (158) | 4 | |||||||||||||
| Preference share dividends | (1) | — | 58 | — | |||||||||||||
| Adjusted earnings | 1,271 | 1,376 | 5,692 | 5,551 | |||||||||||||
| Adjusted earnings per common share | 0.63 | 0.68 | 2.81 | 2.74 | |||||||||||||
21
APPENDIX B
NON-GAAP RECONCILIATION – ADJUSTED EBITDA TO SEGMENTED EBITDA
LIQUIDS PIPELINES
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
Adjusted EBITDA | 2,327 | 2,108 | 8,908 | 7,731 | |||||||||||||
| Change in unrealized derivative fair value gain/(loss) - Foreign exchange | 181 | 36 | (183) | 120 | |||||||||||||
| Assets impairment | (197) | — | (252) | — | |||||||||||||
| Property tax settlement | — | — | — | 57 | |||||||||||||
| Other | (40) | (3) | (109) | (11) | |||||||||||||
Total adjustments | (56) | 33 | (544) | 166 | |||||||||||||
EBITDA | 2,271 | 2,141 | 8,364 | 7,897 | |||||||||||||
GAS TRANSMISSION AND MIDSTREAM
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
(unaudited; millions of Canadian dollars) | |||||||||||||||||
Adjusted EBITDA | 1,117 | 922 | 4,417 | 3,850 | |||||||||||||
Equity investment impairment | — | — | — | (111) | |||||||||||||
| Goodwill impairment | (2,475) | — | (2,475) | — | |||||||||||||
Gain from joint venture merger transaction | — | — | 1,076 | — | |||||||||||||
| Customer settlement | 118 | — | 118 | — | |||||||||||||
Equity earnings adjustment - DCP Midstream, LLC | 16 | 60 | (10) | (44) | |||||||||||||
Other | (34) | (36) | — | (24) | |||||||||||||
Total adjustments | (2,375) | 24 | (1,291) | (179) | |||||||||||||
EBITDA | (1,258) | 946 | 3,126 | 3,671 | |||||||||||||
GAS DISTRIBUTION AND STORAGE
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
(unaudited; millions of Canadian dollars) | |||||||||||||||||
Adjusted EBITDA | 467 | 450 | 1,856 | 1,853 | |||||||||||||
| Change in unrealized derivative fair value gain/(loss) - Foreign exchange | — | 2 | — | 14 | |||||||||||||
| Gain on sale of equity investment | — | 303 | — | 303 | |||||||||||||
Other | (8) | (12) | (29) | (53) | |||||||||||||
Total adjustments | (8) | 293 | (29) | 264 | |||||||||||||
EBITDA | 459 | 743 | 1,827 | 2,117 | |||||||||||||
22
RENEWABLE POWER GENERATION
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
Adjusted EBITDA | 122 | 140 | 522 | 496 | |||||||||||||
| Change in unrealized derivative fair value gain/(loss) - Foreign exchange | 2 | 2 | 8 | 8 | |||||||||||||
| Assets impairment | (238) | — | (238) | — | |||||||||||||
Other | (13) | 4 | (30) | 4 | |||||||||||||
Total adjustments | (249) | 6 | (260) | 12 | |||||||||||||
EBITDA | (127) | 146 | 262 | 508 | |||||||||||||
ENERGY SERVICES
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
| Adjusted EBITDA | (62) | (83) | (364) | (360) | |||||||||||||
| Change in unrealized derivative fair value gain/(loss) - Commodity prices | (49) | 155 | (27) | 53 | |||||||||||||
| Net inventory adjustment | 55 | (6) | (13) | (6) | |||||||||||||
Asset impairment | (13) | — | (13) | — | |||||||||||||
| Total adjustments | (7) | 149 | (53) | 47 | |||||||||||||
EBITDA | (69) | 66 | (417) | (313) | |||||||||||||
ELIMINATIONS AND OTHER
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
| (unaudited; millions of Canadian dollars) | |||||||||||||||||
| Adjusted EBITDA | (60) | 150 | 192 | 431 | |||||||||||||
| Change in unrealized derivative fair value gain/(loss) - Foreign exchange | 303 | 72 | (1,090) | 55 | |||||||||||||
| Enterprise insurance strategy restructuring | — | — | (15) | — | |||||||||||||
| Woodfibre LNG transaction costs | (114) | — | (114) | — | |||||||||||||
| Impairment of lease assets | 12 | (7) | (39) | (7) | |||||||||||||
Other | 19 | (50) | (58) | (123) | |||||||||||||
Total adjustments | 220 | 15 | (1,316) | (75) | |||||||||||||
| EBITDA | 160 | 165 | (1,124) | 356 | |||||||||||||
23
APPENDIX C
NON-GAAP RECONCILIATION – CASH PROVIDED BY OPERATING ACTIVITIES TO DCF
| Three months ended December 31, | Twelve months ended December 31, | ||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||
(unaudited; millions of Canadian dollars) | |||||||||||||||||
Cash provided by operating activities | 3,613 | 1,890 | 11,230 | 9,256 | |||||||||||||
Adjusted for changes in operating assets and liabilities1 | (590) | 810 | 12 | 1,466 | |||||||||||||
| 3,023 | 2,700 | 11,242 | 10,722 | ||||||||||||||
| Distributions to noncontrolling interests | (75) | (64) | (259) | (271) | |||||||||||||
Preference share dividends | (84) | (93) | (338) | (367) | |||||||||||||
Maintenance capital expenditures2 | (354) | (274) | (820) | (686) | |||||||||||||
Significant adjusting items: | |||||||||||||||||
Other receipts of cash not recognized in revenue3 | 65 | 53 | 238 | 127 | |||||||||||||
Distributions from equity investments in excess of cumulative earnings4 | 259 | 121 | 733 | 418 | |||||||||||||
| Enterprise insurance strategy restructuring expenses | — | — | 100 | — | |||||||||||||
Other items | (171) | 44 | 87 | 98 | |||||||||||||
DCF | 2,663 | 2,487 | 10,983 | 10,041 | |||||||||||||
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.
4Presented net of adjusting items.
24