EX-99.1 2 ei123120218-knr991.htm EX-99.1
NEWS RELEASE
Enbridge Reports Strong 2021 Financial Results and Advances Strategic Priorities
CALGARY, February 11, 2022 /CNW/ - Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported strong full year 2021 financial results, reaffirmed its 2022 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” section of this news release.)
•Full year GAAP earnings of $5.8 billion or $2.87 per common share, compared with GAAP earnings of $3.0 billion or $1.48 per common share in 2020
•Adjusted earnings* of $5.6 billion or $2.74 per common share*, compared with $4.9 billion or $2.42 per common share* in 2020
•Adjusted earnings before interest, income taxes and depreciation and amortization (EBITDA)* of $14.0 billion, compared with $13.3 billion in 2020
•Cash provided by operating activities of $9.3 billion, compared with $9.8 billion in 2020
•Distributable cash flow (DCF)* of $10.0 billion or $4.96 per common share*, compared with $9.4 billion or $4.67 per common share* in 2020
•Reaffirmed 2022 full year guidance range for EBITDA of $15.0 billion to $15.6 billion and DCF per share of $5.20 to $5.50
•Increased the 2022 quarterly dividend by 3% to $0.86 ($3.44 annually) per share reflecting the 27th consecutive annual increase
•Placed approximately $10 billion of capital projects into service in 2021, which is expected to generate significant EBITDA growth in 2022
•Advanced the current $10 billion secured growth program, which supports the Company's 5 to 7% DCF per share growth through 2024
•Successfully closed the previously announced US$3.0 billion acquisition of Moda Midstream Operating LLC including the Ingleside Energy Center
•Announced US$0.4 billion Texas Eastern Phase II Modernization program to upgrade and electrify aging compressors increasing safety and reliability and lowering emissions
•Announced US$0.1 billion Appalachia to Market Phase II system expansion, expanding natural gas supply into the U.S. Northeast to meet growing local demand
•Executed pipeline transportation precedent agreement with Texas LNG Brownsville LLC for a US$0.4 billion expansion of the Valley Crossing Pipeline to supply its LNG export terminal
•Entered into a Memorandum of Understanding with Lehigh Cement and announced Letters of Intent with local Indigenous Nations to develop the Open Access Wabamun Carbon Hub
•Advanced ESG priorities by executing on emissions reduction pathways and increasing the diversity of Enbridge's leadership and Board of Directors
1

•Announced additional measures to further align the business with our net-zero emissions goals
•Completed the previously announced $1.1 billion sale of Enbridge's interest in Noverco Inc. (Noverco), providing for additional financial flexibility
•Announced the approval by the Toronto Stock Exchange (TSX) of Enbridge's normal course issuer bid (NCIB) of up to $1.5 billion
•Issued $750 million of 60-year hybrid debt in the Canadian debt markets with proceeds to be used to redeem the $750 million Enbridge Inc. Preferred Shares - Series 17
CEO COMMENT
Al Monaco, President and CEO commented on the following:
"The last year has once again demonstrated the importance of reliable and affordable energy to the world's social and economic well-being. While it's clear we need to reduce global emissions to achieve our climate objectives, it's also important that we transition our energy systems prudently by ensuring adequate supply of conventional energy, while increasing lower-carbon forms of energy. That approach is driving our strategies at Enbridge, including investment in renewables and new low-carbon energy infrastructure, and setting near-term emissions reduction targets and net zero by 2050.
"2021 was a pivotal year for Enbridge; we delivered strong safety, operating and financial performance, advanced our strategic priorities, and strengthened the competitive positioning of our conventional and low-carbon businesses.
"Operationally, each of our businesses performed well, driven by a rebound in the global economy, customer demand, and the critical role our assets play in delivering essential energy supply. We placed $10 billion of growth capital into service, including the Line 3 Replacement Project, which will generate significant cash flow growth in 2022 and provide a foundation for future growth.
"Financially, we achieved solid results, near the top of our DCF per share guidance range for the year. And, we sold $1.2 billion of non-core assets at attractive valuations, including Noverco, which will provide additional financial flexibility. Along with the cash flows from new projects placed into service, we expect our leverage to be at the low end of our target range in 2022.
"We also advanced our strategic priorities and added $2 billion of new conventional and low-carbon growth capital to our commercially secured backlog and executed on our natural gas and crude oil export strategies.
"In Liquids Pipelines, we closed the acquisition of the Ingleside Energy Center, North America's premier light crude oil export platform, with over $1 billion in embedded conventional and low-carbon organic growth potential. As we enter 2022, we're progressing plans to expand Ingleside's export capacity while adding up to 60 MWs of solar power to the site, which will enable net negative facility emissions.
2

"We're also executing on our carbon capture strategy. For example, our recently announced partnerships and collaboration with Capital Power, Lehigh Cement and local indigenous communities on a carbon capture and storage hub in central Alberta has the potential to sequester nearly 4 million tonnes of CO 2 emissions annually. Carbon capture and storage will be critical to meeting society's emissions reductions goals and we're excited to be leveraging our expertise and footprint with great partners.
"In Gas Transmission, we placed our Cameron Extension project into service supplying the Calcasieu Pass LNG facility, and our agreement to serve Texas LNG further extends our U.S. Gulf Coast export opportunity set. In Western Canada, our B.C. Pipeline is advancing a $2.5 billion expansion to serve west coast LNG and local market demand growth. And, we're expanding our multi-billion Texas Eastern modernization program to upgrade and electrify additional compressors, which will improve system safety and performance and drive emissions lower.
"At our Utility, we added more than 40 thousand natural gas customers last year, and continued to develop new low-carbon projects that fit well within our low-risk commercial model and lower emissions for our customers. We now have seven renewable natural gas projects operating or under construction with a healthy backlog of new projects in development. Our new hydrogen blending facility in Markham, the first of its kind in North America, just began operations.
"In Renewables, construction of four offshore wind projects off the coast of France, including our first floating facility, are progressing on schedule with the first expected to enter service by the end of this year. In North America, we have ten solar self-power projects under construction across our liquids and gas transmission systems, which will generate about 100 MW of renewable power, and further lower our emissions.
"Throughout 2021, we accelerated our leadership in all aspects of environmental, social and governance performance. We've embedded our goals into our business and capital allocation framework, and aligned those plans with enterprise-wide compensation. On our diversity and inclusion goals, we've added diversity at all levels of the organization, including the Board of Directors. We're also making good progress towards our medium and long-term emissions goals across our operations. And, we've added new Scope 3 metrics to track the emissions intensity of the energy we deliver and our contribution to reducing global emissions through demand-side management programs and our growing renewable and low-carbon investments. Our demand-side management programs at the utility, for example, have helped our customers avoid 55 million tonnes of greenhouse gas emissions over the last 26 years.
"As our shareholders and other stakeholders know, we are committed to leadership in sustainably delivering affordable, reliable and secure energy to millions of people in North America and globally. We recognize that leading our industry also comes with the responsibility of continuous improvement, which is why we are committing to new measures that further align our business with the emissions reductions targets we established in late 2020.
"These measures include ensuring that investment decision making reflects our interim and long-term targets, working with our supply chain to lower Scope 3 emissions, and developing lower carbon partnerships to drive innovation across our businesses. We will also continue to work proactively with the organizations developing science-based guidelines for emissions
3

targets in the midstream sector, and in May, our 21 st annual sustainability report will include scenario analysis based on a net-zero emissions pathway.
"In 2022, we're positioned to grow EBITDA and DCF per share by over 8%. Execution of our secured growth program and embedded growth supports our 5-7% distributable cash flow per share compound annual growth from 2021 to 2024. This visible cash flow growth outlook and a healthy balance sheet supports our 27th consecutive annual dividend increase, reinforcing the importance we place on returning capital as part of our shareholder value proposition.
"Looking forward to our 3-year planning horizon, we expect to have $5-6 billion of annual investment capacity, of which $3-4 billion is prioritized to core utility-like investments. The remaining $2 billion will be deployed to the next best alternatives including share repurchases. Our recent implementation of a normal course issuer bid provides flexibility to repurchase up to $1.5 billion of our common shares and creates an additional avenue to supplement the return of capital to shareholders, while increasing per share earnings and distributable cash flow.
"The strong demand for our system capacity and execution on our secured capital continues to drive stable and growing cash flows. As we look to the future, embedded conventional and low-carbon organic growth opportunities across our assets, along with our disciplined approach to investment, provides a compelling growth outlook and value proposition for our shareholders."
FINANCIAL RESULTS SUMMARY
Financial results for the three months and year ended December 31, 2021 and 2020 are summarized in the table below:

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts; number of shares in millions) |  |  |  |  |
GAAP Earnings attributable to common shareholders | 1,840 |  | 1,775 |  |  | 5,816 |  | 2,983 |
GAAP Earnings per common share | 0.91 |  | 0.88 |  |  | 2.87 |  | 1.48 |
Cash provided by operating activities | 2,302 |  | 2,254 |  |  | 9,256 |  | 9,781 |
Adjusted EBITDA 1 | 3,687 |  | 3,201 |  |  | 14,001 |  | 13,273 |
Adjusted Earnings 1 | 1,376 |  | 1,132 |  |  | 5,551 |  | 4,894 |
Adjusted Earnings per common share 1 | 0.68 |  | 0.56 |  |  | 2.74 |  | 2.42 |
Distributable Cash Flow 1 | 2,487 |  | 2,209 |  |  | 10,041 |  | 9,440 |
Weighted average common shares outstanding | 2,024 |  | 2,022 |  |  | 2,023 |  | 2,020 |

1 Non-GAAP financial measures. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
GAAP earnings attributable to common shareholders for the fourth quarter of 2021 increased by $65 million or $0.03 per share compared with the same period in 2020.
On a full year basis, GAAP earnings attributable to common shareholders for 2021 increased by $2.8 billion or $1.39 per share compared with the same period in 2020.
4

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 annual Management Discussion & Analysis for 2021 filed in conjunction with the year-end financial statements for a detailed discussion of GAAP financial results.
Adjusted earnings in the fourth quarter of 2021 increased by $244 million, or $0.12 per share and was driven largely by the net impact of the operating factors discussed below, offset by increased depreciation expense on new assets placed into service throughout 2021, including the U.S. portion of the Line 3 Replacement Project, which was placed into service early in the fourth quarter, and the Enbridge Ingleside Energy Center, which was acquired in mid-October.
Full year adjusted earnings for 2021 increased by $657 million, or $0.32 per share, primarily due to the net impact of the operating factors discussed below, along with lower interest rates on short-term borrowings and the positive impact of a weaker USD on the translation of USD denominated interest expense. This was partially offset by increased depreciation expense on new assets placed into service throughout 2021.
Adjusted EBITDA in the fourth quarter of 2021 increased by $486 million compared with the same period in 2020. This is primarily driven by contributions from the U.S. portion of the Line 3 Replacement Project and the acquisition of the Enbridge Ingleside Energy Center. Additionally, results were negatively impacted by a weaker USD which negatively impacts the translation of the Company's USD denominated EBITDA. The average CAD to USD exchange rate in the fourth quarter fell approximately 3% in 2021 to $1.26, compared with $1.30 in the fourth quarter of 2020. Enbridge's enterprise-wide financial risk management program has partially mitigated the impact of a weaker USD currency through its foreign exchange hedging program.
Full year adjusted EBITDA for 2021 increased by $728 million compared with the same period in 2020. This is primarily driven by the same factors discussed above and partially offset by weaker contributions from Energy Services. The average CAD to USD exchange rate in 2021 fell approximately 7% to $1.25, compared with $1.34 in 2020.
DCF for the fourth quarter was $2.5 billion, an increase of $278 million over the fourth quarter of 2020, driven primarily by the impact of the operating factors discussed above and partially offset by higher cash taxes in the quarter and lower cash distributions in excess of equity earnings.
DCF for the year ended December 31, 2021 was $10.0 billion, an increase of $601 million over 2020, primarily due to the same operating factors discussed above as well as lower maintenance capital expenditures, primarily at the Utility, lower interest expense and lower cash distributions in excess of equity earnings.
In addition to the items discussed above, adjusted EBITDA, adjusted earnings and DCF were each impacted by the recognition of a provision in the fourth quarter against the interim Mainline International Joint Toll (IJT) for barrels shipped between July 1 and December 31, 2021.
These factors are discussed in detail under Distributable Cash Flow. Detailed segmented financial information and analysis can be found below under Adjusted EBITDA by Segments.
5

FINANCIAL POSITION
The Company is currently rated BBB+, or equivalent, by all four of its credit rating agencies, reflecting Enbridge's sector leading financial strength and cash flow resiliency. Enbridge's financial position is expected to strengthen in 2022 towards the low end of the targeted Debt to EBITDA range of 4.5x to 5.0x as annualized EBITDA contributions from the approximately $14 billion of capital projects and asset acquisitions executed in 2021 are realized.
In January 2022, Enbridge issued $750 million of hybrid securities in the Canadian debt market. Net proceeds from the offering will be used to redeem the outstanding Cumulative Redeemable Minimum Rate Reset Preference Shares, Series 17 (TSX: ENB.PF.I) on March 1, 2022. These hybrid securities will receive partial equity treatment from rating agencies, while lowering the Company's overall financing costs due to a lower realized coupon rate.
FINANCIAL OUTLOOK
The Company reaffirms its 2022 financial guidance, announced in December, which included adjusted EBITDA between $15.0 and $15.6 billion and DCF per share between $5.20 to $5.50.
Growth in 2022 is anticipated to be driven by an increase in Mainline volumes, which are expected to average 2.95 million barrels per day (mmbpd), full year contributions from projects placed into service during 2021, including the Line 3 Replacement Project and the acquisition of the Ingleside Energy Center and execution of our 2022 growth program, offset by ongoing weakness in Energy Services due to continued market backwardation and narrow basis.
Enbridge increased its 2022 quarterly dividend by 3% to $0.86 ($3.44 annually) per share, commencing with the dividend payable on March 1, 2022 to shareholders of record on February 15, 2022.
SECURED GROWTH PROJECT EXECUTION UPDATE
In 2021, Enbridge placed approximately $10 billion of growth projects into service across each of its four businesses, which are expected to provide significant EBITDA and DCF contributions in 2022 including:
•the US$4.0 billion U.S. segment of the Line 3 Replacement Project and associated US$0.5 billion Southern Access Expansion to 1.2 mmbpd;
•the US$0.1 billion 90 thousand barrel per day (kbpd) expansion of Flanagan South;
•the $1.0 billion T-South Reliability and Expansion Program and the $0.4 billion Spruce Ridge Project, which increased capacity on the B.C. Pipeline;
•Gas Transmission's US$1.0 billion 2021 Modernization Program;
•the US$0.1 billion Cameron Extension along the U.S. Gulf Coast providing natural gas to service Calcasieu Pass LNG;
•the combined US$0.1 billion Appalachia to Market and Middlesex Extension projects, which support reliable natural gas supply into the U.S. Northeast; and
•Gas Distribution's $0.9 billion 2021 Utility Growth capital.
In the fourth quarter, Enbridge closed the previously announced acquisition of Moda Midstream Operating LLC for US$3.0 billion, which included the Ingleside Energy Center and related
6

pipeline and logistics assets. The Company is developing approximately two million barrels of additional permitted storage and a solar facility of up to 60 MW to be located on site.
Today, Enbridge announced it is proceeding with Texas Eastern Modernization Phase II with a total capital cost of approximately US$0.4 billion to modernize aging compressor equipment across Texas Eastern resulting in increased safety and reliability of the system and a reduction in associated greenhouse gas emissions. This phase of work will be staged with in-service dates beginning in 2024. The Company expects to earn an appropriate return on these investments in the system through periodic rate filings on Texas Eastern.
The Company also announced the US$0.1 billion Appalachia to Market Phase II expansion of the Texas Eastern system providing additional capacity to meet U.S. northeast demand for natural gas which is expected to be in service in 2025.
Inclusive of newly sanctioned capital, the Company's current secured growth program is approximately $10 billion and is supported by commercial models entirely consistent with Enbridge's low-risk model. The program includes ratable capital requirements for both Gas Transmission's modernization and Gas Distribution's utility growth programs, as well as 4 offshore wind projects in France providing a combined 1.5 GW (0.3 GW net) of generation capacity, and a number of other smaller projects across each of Enbridge's businesses.
OTHER BUSINESS UPDATES
Mainline Contracting
On November 26, 2021, the Canada Energy Regulator (CER) denied Enbridge's application to implement firm service contracting on the Canadian Mainline system. Subsequent to the CER decision, Enbridge has initiated a process to negotiate a go-forward Canadian Mainline tolling framework with customers and other stakeholders.
The Company is currently advancing two potential commercial frameworks for the Mainline in parallel: i) a new incentive rate-making agreement that may be similar to the Competitive Toll Settlement (CTS) agreement that expired on June 30, 2021, and ii) a Canadian Mainline cost-of-service application. The Company anticipates that its consultation and negotiation with industry will progress through the first half of 2022, with the potential to file a proposed incentive tolling settlement or cost-of-service application with the CER for review later this year.
Either framework is anticipated to provide attractive risk-adjusted returns for operating the Canadian Mainline and the range of financial outcomes is not expected to materially impact Enbridge's financial outlook.
As per the terms of the CTS, Enbridge is collecting interim tolls which are consistent with the tolls in effect on June 30, 2021 when the CTS agreement expired and which are subject to refund. The Company has included provisions in its 2021 Mainline results from July 31 to December 31, along with its 2022 and 3-year guidance, in recognition of the uncertainty of future tolls.
7

Carbon Capture and Storage (CCS)
Enbridge has announced multiple collaborative efforts to develop the proposed Open Access Wabamun Carbon Hub in central Alberta (Wabamun Carbon Hub) including a Memorandum of Understanding (MoU) on January 26, 2022, to collaborate with Lehigh Cement, part of HeidelbergCement Group (Lehigh), on a carbon storage solution for Lehigh's cement manufacturing facility in Edmonton, Alberta. Lehigh is developing North America's first full-scale CCS solution for the cement industry at its Edmonton facility with the goal of capturing approximately 780,000 tonnes of CO2 annually. Captured emissions would be transported via pipeline and permanently sequestered by Enbridge and, subject to the award of carbon sequestration rights and regulatory approvals, could be in service as early as 2025.
The MoU with Lehigh combined with the previously announced MoU with Capital Power Corporation (Capital Power) announced on November 29, 2021, represents an opportunity to capture approximately 4 million tonnes of CO 2 emissions annually from their facilities at the proposed Wabamun Carbon Hub.
Additionally, on February 3, 2022, Enbridge and the First Nation Capital Investment Partnership consisting of four central Alberta Indigenous Nations announced the signing of a Letter of Intent (LoI) to work collaboratively to advance the Wabamun Carbon Hub. The four Treaty 6 First Nations represent collectively more than 10,000 on- and off-reserve members and include the Alexander First Nation, the Alexis Nakota Sioux Nation, the Enoch Cree Nation, and the Paul First Nation. A separate LoI with the Lac Ste. Anne Métis Community Association has also been signed. This collaboration and partnership reflects Enbridge's commitment to Indigenous Reconciliation and, specifically, meaningful involvement of Indigenous Nations, communities and groups in the development of energy projects.
Enbridge is participating in the Government of Alberta's Request for Full Project Proposals process for carbon storage hubs.
Normal Course Issuer Bid
On December 31, 2021, the TSX approved Enbridge's NCIB to purchase, for cancellation, up to 31,062,331 of its outstanding common shares to an aggregate amount of up to $1.5 billion. The NCIB commenced on January 5, 2022 and expires on the earlier date of January 4, 2023, or when the Company reaches its share repurchase limit.
Share repurchases made pursuant to the Company's NCIB will be predicated upon maintaining a strong balance sheet, strong business performance, and the availability and attractiveness of alternative capital investment opportunities.
The NCIB implementation provides flexibility to repurchase our common shares and creates an additional avenue to supplement the return of capital to shareholders, while increasing per share earnings and distributable cash flow.
ESG LEADERSHIP UPDATE
Enbridge is committed to leading ESG practices and performance which has long been core to
how it does business. To this end, the Company set ambitious ESG goals in 2020, which include net zero on Scope 1 and 2 emissions by 2050 with an interim target to reduce the intensity of its greenhouse gas (GHG) emissions 35% by 2030. These goals were developed to align with the
8

objectives of the Paris Agreement, and the Company is committed to continuing to take action to achieve these climate goals.
The Company has integrated its ESG goals into enterprise-wide incentive compensation and $3 billion of sustainability-linked financings. Each of the Company’s business units also developed multi-year emissions reduction plans which are being implemented and will be closely monitored.
Through 2021, the Company estimates that GHG emissions intensity is approximately 21% lower than its 2018 baseline and progressing towards its 2030 goal. Additionally, in 2021 the Company expanded emissions reporting to include new metrics designed to measure the emissions intensity of the energy delivered and the emissions avoided through over two decades of investment in renewables, low-carbon fuels and demand side management programs.
Enbridge aims to continuously strengthen its approach to emissions reporting and reduction. In 2021, Enbridge set a solid foundation, and the Company is now expanding its approach to include the following additional actions:
•ensure that investment decisions align with Enbridge’s interim and long-term emissions reduction goals;
•continue to work proactively with the organizations developing science-based guidelines for emissions targets in the midstream sector;
•work with key suppliers to support the further reduction of Scope 3 emissions;
•update TCFD disclosures in the Company's 21 st annual sustainability report to include scenario analysis based on a net-zero emissions pathway; and
•further develop low-carbon energy partnerships to drive innovation across our business, with a focus on renewable power, renewable natural gas, hydrogen and carbon capture.
9

FOURTH QUARTER AND YEAR-END 2021 FINANCIAL RESULTS
The following table summarizes the Company's GAAP reported results for segment EBITDA, earnings attributable to common shareholders and cash provided by operating activities for the fourth quarter and full year of 2021.
GAAP SEGMENT EBITDA AND CASH FLOW FROM OPERATIONS

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Liquids Pipelines | 2,141 |  | 2,403 |  |  | 7,897 |  | 7,683 |
Gas Transmission and Midstream | 946 |  | 857 |  |  | 3,671 |  | 1,087 |
Gas Distribution and Storage | 743 |  | 463 |  |  | 2,117 |  | 1,748 |
Renewable Power Generation | 146 |  | 147 |  |  | 508 |  | 523 |
Energy Services | 66 |  | (224) |  |  | (313) |  | (236) |
Eliminations and Other | 165 |  | 385 |  |  | 356 |  | (113) |
EBITDA 1 | 4,207 |  | 4,031 |  |  | 14,236 |  | 10,692 |
Earnings attributable to common shareholders | 1,840 |  | 1,775 |  |  | 5,816 |  | 2,983 |
Cash provided by operating activities | 2,302 |  | 2,254 |  |  | 9,256 |  | 9,781 |

1 Non-GAAP financial measure. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
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.
10

DISTRIBUTABLE CASH FLOW

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Liquids Pipelines | 2,108 |  | 1,787 |  |  | 7,731 |  | 7,182 |
Gas Transmission and Midstream | 922 |  | 878 |  |  | 3,850 |  | 3,895 |
Gas Distribution and Storage | 450 |  | 492 |  |  | 1,853 |  | 1,822 |
Renewable Power Generation | 140 |  | 146 |  |  | 496 |  | 507 |
Energy Services | (83) |  | (82) |  |  | (360) |  | (119) |
Eliminations and Other | 150 |  | (20) |  |  | 431 |  | (14) |
Adjusted EBITDA 1,3 | 3,687 |  | 3,201 |  |  | 14,001 |  | 13,273 |
Maintenance capital | (274) |  | (320) |  |  | (686) |  | (915) |
Interest expense 1 | (747) |  | (705) |  |  | (2,724) |  | (2,846) |
Current income tax 1 | (142) |  | (17) |  |  | (352) |  | (342) |
Distributions to noncontrolling interests | (64) |  | (68) |  |  | (271) |  | (300) |
Cash distributions in excess of equity earnings 1 | 65 |  | 170 |  |  | 313 |  | 649 |
Preference share dividends | (93) |  | (96) |  |  | (367) |  | (380) |
Other receipts of cash not recognized in revenue 2 | 53 |  | 42 |  |  | 127 |  | 292 |
Other non-cash adjustments | 2 |  | 2 |  |  | — |  | 9 |
DCF 3 | 2,487 |  | 2,209 |  |  | 10,041 |  | 9,440 |
Weighted average common shares outstanding | 2,024 |  | 2,022 |  |  | 2,023 |  | 2,020 |

1 Presented net of adjusting items.
2 Consists of cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements.
3 Non-GAAP financial measures. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
Fourth quarter 2021 DCF increased $278 million compared with the same period of 2020 primarily due to operational factors discussed below in Adjusted EBITDA by Segments as well as:
•lower Gas Distribution and Storage maintenance capital related to timing of spend; partially offset by,
•higher current income tax due to higher earnings and the timing of recognition of U.S. minimum taxes;
•higher interest expense due to lower capitalized interest associated with the U.S. portion of the Line 3 Replacement Project placed into service in the fourth quarter of 2021; and,
•lower cash distributions in excess of equity earnings primarily as a result of higher equity earnings (reflected in Adjusted EBITDA) at certain equity investments that have not experienced higher corresponding cash distributions in the quarter.
Full year 2021 DCF increased $601 million compared with 2020 primarily related to the factors discussed above as well as lower interest expense for the first nine months of 2021 due to favourable interest rates on short-term borrowings, and the impact of a weaker USD currency that positively impacted the translation of interest payments on USD denominated debt. In addition, full year DCF was impacted by the operational factors discussed below in Adjusted EBITDA by Segments.
11

ADJUSTED EARNINGS

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Adjusted EBITDA 1 | 3,687 |  | 3,201 |  |  | 14,001 |  | 13,273 |
Depreciation and amortization | (1,047) |  | (946) |  |  | (3,852) |  | (3,712) |
Interest expense 2 | (734) |  | (694) |  |  | (2,675) |  | (2,793) |
Income taxes 2 | (406) |  | (304) |  |  | (1,429) |  | (1,437) |
Noncontrolling interests 2 | (31) |  | (29) |  |  | (121) |  | (57) |
Preference share dividends | (93) |  | (96) |  |  | (373) |  | (380) |
Adjusted earnings 1 | 1,376 |  | 1,132 |  |  | 5,551 |  | 4,894 |
Adjusted earnings per common share | 0.68 |  | 0.56 |  |  | 2.74 |  | 2.42 |

1 Non-GAAP financial measures. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
2 Presented net of adjusting items.
Adjusted earnings increased $244 million and adjusted earnings per share increased $0.12 compared with the fourth quarter in 2020 primarily due to the operational factors discussed below in Adjusted EBITDA by Segments, as well as:
•higher depreciation expense on new assets placed into service throughout 2021, including the U.S. portion of the Line 3 Replacement Project, which was placed into service in the fourth quarter, and the Ingleside Energy Center, acquired in October; and
•higher interest expense due to lower capitalized interest associated with the U.S. portion of the Line 3 Replacement Project.
Full year adjusted earnings increased $657 million and adjusted earnings per share increased $0.32 compared with 2020 due to the same operational factors discussed below in Adjusted EBITDA by Segments and the higher depreciation discussed above. The impacts of higher interest expense in the fourth quarter related to reduced capitalized interest was offset on a full year basis by the the impact of lower rates on short-term borrowings, as well as the positive impact of a weaker USD currency on the translation of interest payments on USD denominated debt.
ADJUSTED EBITDA BY SEGMENTS
Fourth quarter adjusted EBITDA generated from U.S. dollar denominated businesses was translated to Canadian dollars at a lower average exchange rate of C$1.26/US$ when compared with C$1.30/US$ in the corresponding 2020 period. On a full year basis, adjusted EBITDA generated from U.S dollar denominated businesses was translated at C$1.25/US$ in 2021, compared with C$1.34/US$ in 2020. 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.
12

LIQUIDS PIPELINES

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Mainline System | 1,202 |  | 1,032 |  |  | 4,466 |  | 4,102 |
Regional Oil Sands System | 234 |  | 234 |  |  | 927 |  | 839 |
Gulf Coast and Mid-Continent System | 317 |  | 206 |  |  | 1,019 |  | 920 |
Other Systems 1 | 355 |  | 315 |  |  | 1,319 |  | 1,321 |
Adjusted EBITDA 2 | 2,108 |  | 1,787 |  |  | 7,731 |  | 7,182 |
Operating Data (average deliveries – thousands of bpd) |  |  |  |  |
Mainline System - ex-Gretna volume 3 | 3,014 | 2,651 |  | 2,765 | 2,622
Regional Oil Sands System 4 | 1,983 | 1,919 |  | 1,929 | 1,641
International Joint Tariff (IJT)5 | $4.27 |  | $4.27 |  |  | $4.27 |  | $4.24 |
Competitive Tolling Settlement (CTS) Surcharges 5 | $0.26 |  | $0.26 |  |  | $0.26 |  | $0.19 |
Line 3 Replacement Surcharge 5,6 | $0.94 |  | $0.20 |  |  | $0.94 |  | $0.20 |

1 Other consists of Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines & Other.
2 Non-GAAP measure. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
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 Volumes are for the Athabasca Pipeline, Waupisoo Pipeline, Woodland Pipeline and Wood Buffalo system and exclude laterals on the Regional Oil Sands System.
5 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 for the Canadian portion of the Mainline during the fourth quarter of 2021 was C$1.27/US$ (Q4 2020: C$1.21/US$) and for the full year 2021 C$1.25/US$ (2020: C$1.19/US$). The U.S. portion of the Mainline System is subject to FX translation similar to the Company’s other U.S. based businesses, which are translated at the average spot rate for a given period. A portion of this U.S. dollar translation exposure is hedged under the Company's enterprise-wide financial risk management program with offsetting hedge settlements reported within Eliminations and Other.
6 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.
Liquids Pipelines adjusted EBITDA increased $321 million compared with the fourth quarter of 2020, primarily related to:
•higher Mainline System throughput enabled by incremental Line 3 capacity placed into service October 1, higher tolls due to the implementation of the full Line 3 Replacement surcharge of US$0.935 per barrel beginning October 2021 compared with the surcharge on the Canadian portion of the project of US$0.20 per barrel and a higher effective foreign exchange hedge rate (C$1.27 in 2021 vs. C$1.21 in 2020) on hedges used to manage foreign exchange risk of the U.S. dollar denominated Canadian Mainline revenue, partially offset by the recognition of a provision against the interim Mainline IJT for barrels shipped between July 1 and December 31, 2021; and
•higher contributions from the Gulf Coast and Mid-Continent System due primarily to the acquisition of the Ingleside Energy Center in the fourth quarter of 2021 and higher contributions from the Seaway Crude Pipeline System; partially offset by
•the negative effect of translating U.S. dollar denominated EBITDA at a lower Canadian to U.S. dollar average exchange rate, which is partially offset by realized hedge gains in the Eliminations and Other segment as part of the Company's enterprise-wide financial risk management program.
13

Full year 2021 Liquids Pipeline adjusted EBITDA increased $549 million compared with 2020 and was primarily impacted by the same factors discussed above as well as higher throughput within on the Mainline System and the Regional Oil Sands System due to recovery from the impacts of the COVID-19 pandemic on crude oil demand and completion of the Woodland Pipeline expansion in June 2021.
GAS TRANSMISSION AND MIDSTREAM

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
U.S. Gas Transmission | 670 | 673 |  |  | 2,905 |  | 3,090 |
Canadian Gas Transmission | 125 | 140 |  |  | 537 | 494 |
U.S. Midstream | 91 | 40 |  |  | 260 | 156 |
Other | 36 | 25 |  |  | 148 | 155 |
Adjusted EBITDA 1 | 922 |  | 878 |  |  | 3,850 |  | 3,895 |

1 Non-GAAP financial measure. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
•
Gas Transmission and Midstream adjusted EBITDA increased $44 million compared with the fourth quarter of 2020, primarily related to:
•higher U.S. Gas Transmission contributions from the Atlantic Bridge Phase III project, placed into service in January 2021, and increased revenue due to the absence of pressure restrictions that existed on the Texas Eastern system in 2020;
•higher U.S. midstream contributions resulting from higher commodity prices at Enbridge's Aux Sable and DCP joint ventures; partially offset by
•lower Canadian Gas Transmission contributions due to the timing of operating and administrative expenses, realized in the fourth quarter of 2021, partially offset by higher contributions from the final phases of the T-South Expansion and Spruce Ridge projects placed into service in the quarter; and
•the negative effect of translating U.S. dollar denominated EBITDA at a weaker U.S dollar average exchange rate, primarily impacting U.S. Gas Transmission and U.S. Midstream results, partially offset by realized gains in the Eliminations and Other segment related to the Company's enterprise-wide financial risk management program.
Full year 2021 Gas Transmission and Midstream adjusted EBITDA decreased $45 million
compared with 2020, due to the factors discussed above as well, as the absence of the recognition of retroactive revenues in 2020 related to the settlement of interim rates collected from shippers on Texas Eastern in U.S. Gas Transmission.
14

GAS DISTRIBUTION AND STORAGE

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Enbridge Gas Inc. (EGI) | 427 |  | 455 |  |  | 1,744 |  | 1,741 |
Other | 23 |  | 37 |  |  | 109 |  | 81 |
Adjusted EBITDA 1 | 450 |  | 492 |  |  | 1,853 |  | 1,822 |
Operating Data |  |  |  |  |
EGI |  |  |  |  |
Volumes (billions of cubic feet) | 560 |  | 507 |  |  | 1,943 |  | 1,793 |
Number of active customers 2 (millions) |  |  |  | 3.8 |  | 3.8 |
Heating degree days 3 |  |  |  |  |
Actual | 1,144 |  | 1,234 |  |  | 3,494 |  | 3,657 |
Forecast based on normal weather 4 | 1,317 |  | 1,310 |  |  | 3,855 |  | 3,843 |

1 Non-GAAP financial measure. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
2 Number of active customers is the number of natural gas consuming customers at the end of the reported period.
3 Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in EGI's distribution franchise areas.
4 Normal weather is the weather forecast by EGI in its legacy rate zones, using the forecasting methodologies approved by the Ontario Energy Board.
Gas Distribution and Storage adjusted EBITDA will typically follow a seasonal profile. It is generally highest in the first and fourth quarters of the year reflecting greater volumetric demand during the heating season. The magnitude of the seasonal EBITDA fluctuations will vary from year-to-year reflecting the impact of colder or warmer than normal weather on distribution volumes. Results include contributions from Noverco within Other. The divestiture of Noverco closed on December 30, 2021.
Gas Distribution and Storage adjusted EBITDA decreased $42 million compared with the fourth quarter of 2020 primarily related to:
•the negative impact of warmer weather in 2021 of approximately $16 million; and
•higher operating and administrative costs largely related to timing of operational, pipeline integrity and safety costs between quarters; partially offset by
•higher distribution charges resulting from increases in rates and customer base.
When compared with the normal weather forecast embedded in rates, the warmer weather in the fourth quarter of 2021 negatively impacted EBITDA by approximately $31 million, compared to a negative impact of approximately $15 million in the fourth quarter of 2020.
Full year 2021 Gas Distribution and Storage adjusted EBITDA increased $31 million compared
with 2020 due to the same factors discussed above. On a full year basis, when compared with the normal weather forecast embedded in rates, warmer weather negatively impacted EBITDA by approximately $55 million and negatively impacted 2020 by approximately $33 million.
15

RENEWABLE POWER GENERATION

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA 1 | 140 |  | 146 |  |  | 496 |  | 507 |

1 Non-GAAP financial measure. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
Renewable Power Generation adjusted EBITDA decreased $6 million compared with the fourth quarter of 2020 primarily related to lower wind resources at the Canadian wind facilities.
Full year 2021 Renewable Power Generation adjusted EBITDA decreased $11 million compared
with 2020 due to the factors discussed above, as well as:
•weaker wind resources at U.S. wind facilities, including effects from the winter storm in Texas during February 2021; and
•the absence of reimbursements received in 2020 at certain Canadian wind facilities from a change in operator; partially offset by
•the promote fee received associated with the closing of the sale of 49% of Enbridge's interest in three French offshore wind projects in construction to CPP Investments, which closed in the first quarter of 2021.
ENERGY SERVICES

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA 1 | (83) |  | (82) |  |  | (360) |  | (119) |

1 Non-GAAP financial measure. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
Energy Services adjusted EBITDA decreased $1 million compared with the fourth quarter of 2020 and $241 million with compared with full year 2020. The decrease is the result of:
•significant compression of location and quality differentials in certain markets along with limited storage opportunities due to market price backwardation; and
•adverse impacts from the major winter storm experienced across the U.S. Midwest during February 2021.
These conditions lead to fewer opportunities to achieve profitable transportation margins on facilities in which Energy Services holds capacity obligations.
16

ELIMINATIONS AND OTHER

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Operating and administrative recoveries | 103 |  | (8) |  |  | 256 |  | 158 |
Realized foreign exchange hedge settlement gains/(losses) | 47 |  | (12) |  |  | 175 |  | (172) |
Adjusted EBITDA 1 | 150 |  | (20) |  |  | 431 |  | (14) |

1 Non-GAAP financial measure. Please refer to “Non-GAAP Reconciliations Appendices” section of this news release.
Operating and administrative recoveries captured in this segment reflect the cost of centrally delivered services (including depreciation of corporate assets) inclusive of amounts recovered from business units for the provision of those services. 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 increased $170 million compared with the fourth quarter of 2020 due to:
•higher realized foreign exchange gains compared with realized foreign exchange losses in 2020 as a result of a weakening U.S. dollar average exchange rate of $1.26 for the fourth quarter of 2021 (Q4 2020:$1.30) compared with a hedge rate of $1.30 for the fourth quarter of 2021 (Q4 2020:$1.29); and
•the annualized benefit of cost containment initiatives executed in 2020.
Full year 2021 Eliminations and Other adjusted EBITDA increased $445 million compared with
2020 due to the same factors discussed above. On a full year basis, the average exchange rate
for 2021 was $1.25 (2020:$1.34) compared with the full-year 2021 hedge rate of $1.30 (2020:
$1.29).
17

CONFERENCE CALL
Enbridge will host a conference call and webcast on February 11, 2022 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide an enterprise wide business update and review 2021 fourth quarter results. Analysts, members of the media and other interested parties can access the call toll free at (833) 233-4460 or within and outside North America at (647) 689-4543 using the conference ID of 6486063. The call will be audio webcast live at https://event.on24.com/wcc/r/3574327/A306812D7E85261DFF8D8810CF6EC1E4. 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 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 (800) 585-8367 or within and outside North America at (416) 621-4642 (conference ID: 6486063).
The conference call format will include prepared remarks from the executive team followed by a question and answer session for the analyst and investor community only. Enbridge’s media and investor relations teams will be available after the call for any additional questions.
DIVIDEND DECLARATION
On December 6, 2021, the Company's Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2022 to shareholders of record on February 15, 2022.

| Dividend per share
Common Shares 1 | $0.86000 |
Preference Shares, Series A | $0.34375 |
Preference Shares, Series B | $0.21340 |
Preference Shares, Series C 2 | $0.15719 |
Preference Shares, Series D | $0.27875 |
Preference Shares, Series F | $0.29306 |
Preference Shares, Series H | $0.27350 |
Preference Shares, Series J | US$0.30540 |
Preference Shares, Series L | US$0.30993 |
Preference Shares, Series N | $0.31788 |
Preference Shares, Series P | $0.27369 |
Preference Shares, Series R | $0.25456 |
Preference Shares, Series 1 | US$0.37182 |
Preference Shares, Series 3 | $0.23356 |
Preference Shares, Series 5 | US$0.33596 |
Preference Shares, Series 7 | $0.27806 |
Preference Shares, Series 9 | $0.25606 |
Preference Shares, Series 11 | $0.24613 |
Preference Shares, Series 13 | $0.19019 |
Preference Shares, Series 15 | $0.18644 |
Preference Shares, Series 17 | $0.32188 |
Preference Shares, Series 19 | $0.30625 |

1 The quarterly dividend per common share was increased 3% to $0.86 from $0.835, effective March 1, 2022.
2 The quarterly dividend per share paid on Series C was increased to $0.15501 from $0.15349 on March 1, 2021, was increased to $0.15753 from $0.15501 on June 1, 2021, was increased to $0.16081 from $0.15753 on September 1, 2021 and was decreased to $0.15719 from $0.16081 on December 1, 2021, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.
18

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 strategic plan, priorities and outlook; 2022 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, targets and plans, including greenhouse gas (GHG) emissions intensity and reduction targets, ESG engagement and disclosure, and diversity and inclusion goals; 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 debt-to EBITDA range; expected shareholder returns, asset returns and returns on equity; expected performance of the Company’s businesses, including customer growth and organic growth opportunities; financial strength, capacity and flexibility; financial priorities; expectations on leverage, sources of liquidity and sufficiency of financial resources; expected in-service dates and costs related to announced projects and projects under construction and system expansion, optimization and modernization; capital allocation framework and priorities including ESG factors; share repurchases under normal course issuer bid; investment capacity; expected future growth and expansion opportunities, including secured growth program, development opportunities and low carbon and new energies opportunities and strategy; 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: energy transition, including the drivers and pace thereof; the COVID-19 pandemic and the duration and impact thereof; global economic growth and trade; 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; anticipated cost savings; exchange rates; inflation; interest rates; availability and price of labour and construction materials; operational reliability and performance; customer, regulatory and stakeholder support and approvals; anticipated construction and in-service dates; weather; announced and potential acquisition, disposition and other corporate transactions and projects and the timing and impact 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 and expected future DCF and DCF per share; estimated future
19

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 the Company’s services. Similarly, exchange rates, inflation, interest rates and the COVID-19 pandemic impact the economies and business environments in which the Company operates and may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected EBITDA, expected adjusted EBITDA, expected earnings/(loss), expected adjusted earnings/(loss), expected DCF and associated per share amounts, and estimated future dividends. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather; customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes; and the COVID-19 pandemic and the duration and impact thereof.
Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the realization of anticipated benefits and synergies of projects and transactions, successful execution of our strategic priorities, operating performance, the Company's dividend policy, regulatory parameters, changes in regulations applicable to the Company's business, litigation, acquisitions and dispositions and other transactions, project approval and support, renewals of rights-of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, political decisions, exchange rates, interest rates, commodity prices, supply of and demand for commodities and the COVID-19 pandemic, including but not limited to those risks and uncertainties discussed in this and in the Company’s other filings with Canadian and U.S. securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this news release or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.
20

ABOUT ENBRIDGE INC.
Enbridge Inc. is a leading North American energy infrastructure company. We safely and reliably deliver the energy people need and want to fuel quality of life. Our core businesses include Liquids Pipelines, which transports approximately 30 percent of the crude oil produced in North America; Gas Transmission and Midstream, which transports approximately 20 percent of the natural gas consumed in the U.S.; Gas Distribution and Storage, which serves approximately 3.9 million retail customers in Ontario and Quebec; and Renewable Power Generation, which owns approximately 1,766 MW (net) in renewable power generation capacity in North America and Europe. The Company's common shares trade on the Toronto and New York stock exchanges under the symbol ENB. For more information, visit www.enbridge.com.
None of the information contained in, or connected to, Enbridge’s website is incorporated in or otherwise forms part of this news release.

FOR FURTHER INFORMATION PLEASE CONTACT: |  |
Enbridge Inc. – Media |  | Enbridge Inc. – Investment Community
Jesse Semko |  | Jonathan Morgan
Toll Free: (888) 992-0997 |  | Toll Free: (800) 481-2804
Email: media@enbridge.com |  | Email: investor.relations@enbridge.com

21

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 a GAAP basis) 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 which are 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 generally accepted accounting principles in the United States of America (U.S. GAAP) and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers.
The tables below provide a reconciliation of the non-GAAP measures to comparable GAAP measures.
22

APPENDIX A
NON-GAAP RECONCILIATIONS – ADJUSTED EBITDA AND ADJUSTED EARNINGS
CONSOLIDATED EARNINGS

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Liquids Pipelines | 2,141 |  | 2,403 |  |  | 7,897 |  | 7,683 |
Gas Transmission and Midstream | 946 |  | 857 |  |  | 3,671 |  | 1,087 |
Gas Distribution and Storage | 743 |  | 463 |  |  | 2,117 |  | 1,748 |
Renewable Power Generation | 146 |  | 147 |  |  | 508 |  | 523 |
Energy Services | 66 |  | (224) |  |  | (313) |  | (236) |
Eliminations and Other | 165 |  | 385 |  |  | 356 |  | (113) |
EBITDA | 4,207 |  | 4,031 |  |  | 14,236 |  | 10,692 |
Depreciation and amortization | (1,047) |  | (946) |  |  | (3,852) |  | (3,712) |
Interest expense | (732) |  | (685) |  |  | (2,655) |  | (2,790) |
Income tax expense | (463) |  | (501) |  |  | (1,415) |  | (774) |
Earnings attributable to noncontrolling interests | (32) |  | (28) |  |  | (125) |  | (53) |
Preference share dividends | (93) |  | (96) |  |  | (373) |  | (380) |
Earnings attributable to common shareholders | 1,840 |  | 1,775 |  |  | 5,816 |  | 2,983 |

ADJUSTED EBITDA TO ADJUSTED EARNINGS

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Liquids Pipelines | 2,108 |  | 1,787 |  |  | 7,731 |  | 7,182 |
Gas Transmission and Midstream | 922 |  | 878 |  |  | 3,850 |  | 3,895 |
Gas Distribution and Storage | 450 |  | 492 |  |  | 1,853 |  | 1,822 |
Renewable Power Generation | 140 |  | 146 |  |  | 496 |  | 507 |
Energy Services | (83) |  | (82) |  |  | (360) |  | (119) |
Eliminations and Other | 150 |  | (20) |  |  | 431 |  | (14) |
Adjusted EBITDA | 3,687 |  | 3,201 |  |  | 14,001 |  | 13,273 |
Depreciation and amortization | (1,047) |  | (946) |  |  | (3,852) |  | (3,712) |
Interest expense | (734) |  | (694) |  |  | (2,675) |  | (2,793) |
Income tax expense | (406) |  | (304) |  |  | (1,429) |  | (1,437) |
Earnings attributable to noncontrolling interests | (31) |  | (29) |  |  | (121) |  | (57) |
Preference share dividends | (93) |  | (96) |  |  | (373) |  | (380) |
Adjusted earnings | 1,376 |  | 1,132 |  |  | 5,551 |  | 4,894 |
Adjusted earnings per common share | 0.68 |  | 0.56 |  |  | 2.74 |  | 2.42 |

23

EBITDA TO ADJUSTED EARNINGS

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
EBITDA | 4,207 |  | 4,031 |  |  | 14,236 |  | 10,692 |
Adjusting items: |  |  |  |  |
Change in unrealized derivative fair value gain - Foreign exchange | (112) |  | (1,057) |  |  | (197) |  | (856) |
Change in unrealized derivative fair value (gain)/loss - Commodity prices | (155) |  | 146 |  |  | (53) |  | 122 |
Equity investment impairment | — |  | — |  |  | 111 |  | 2,351 |
Equity investment asset and goodwill impairment | — |  | — |  |  | — |  | 324 |
Gain on sale of Noverco | (303) |  | — |  |  | (303) |  | — |
Texas Eastern re-establishment of EDIT regulated liability | — |  | — |  |  | — |  | 159 |
Employee severance, transition and transformation costs | 41 |  | 34 |  |  | 147 |  | 339 |
Other | 9 |  | 47 |  |  | 60 |  | 142 |
Total adjusting items | (520) |  | (830) |  |  | (235) |  | 2,581 |
Adjusted EBITDA | 3,687 |  | 3,201 |  |  | 14,001 |  | 13,273 |
Depreciation and amortization | (1,047) |  | (946) |  |  | (3,852) |  | (3,712) |
Interest expense | (732) |  | (685) |  |  | (2,655) |  | (2,790) |
Income tax expense | (463) |  | (501) |  |  | (1,415) |  | (774) |
Earnings attributable to noncontrolling interests | (32) |  | (28) |  |  | (125) |  | (53) |
Preference share dividends | (93) |  | (96) |  |  | (373) |  | (380) |
Adjusting items in respect of: |  |  |  |  |
Interest expense | (2) |  | (9) |  |  | (20) |  | (3) |
Income tax expense | 57 |  | 197 |  |  | (14) |  | (663) |
Earnings attributable to noncontrolling interests | 1 |  | (1) |  |  | 4 |  | (4) |
Adjusted earnings | 1,376 |  | 1,132 |  |  | 5,551 |  | 4,894 |
Adjusted earnings per common share | 0.68 |  | 0.56 |  |  | 2.74 |  | 2.42 |

24

APPENDIX B
NON-GAAP RECONCILIATION – ADJUSTED EBITDA TO SEGMENTED EBITDA
LIQUIDS PIPELINES

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 2,108 |  | 1,787 |  |  | 7,731 |  | 7,182 |
Change in unrealized derivative fair value gain | 36 |  | 635 |  |  | 120 |  | 545 |
Property tax settlement | — |  | — |  |  | 57 |  | — |
Asset write-down loss | — |  | (17) |  |  | — |  | (30) |
Other | (3) |  | (2) |  |  | (11) |  | (14) |
Total adjustments | 33 |  | 616 |  |  | 166 |  | 501 |
EBITDA | 2,141 |  | 2,403 |  |  | 7,897 |  | 7,683 |

GAS TRANSMISSION AND MIDSTREAM

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 922 |  | 878 |  |  | 3,850 |  | 3,895 |
Equity investment impairment | — |  | — |  |  | (111) |  | (2,351) |
Equity investment asset and goodwill impairment | — |  | — |  |  | — |  | (324) |
Texas Eastern re-establishment of EDIT regulated liability | — |  | — |  |  | — |  | (159) |
Equity earnings adjustment - DCP Midstream, LLC | 60 |  | (4) |  |  | (44) |  | 22 |
Other | (36) |  | (17) |  |  | (24) |  | 4 |
Total adjustments | 24 |  | (21) |  |  | (179) |  | (2,808) |
EBITDA | 946 |  | 857 |  |  | 3,671 |  | 1,087 |

GAS DISTRIBUTION AND STORAGE

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 450 |  | 492 |  |  | 1,853 |  | 1,822 |
Change in unrealized derivative fair value gain/(loss) | 2 |  | (12) |  |  | 14 |  | (10) |
Gain on sale of Noverco | 303 |  | — |  |  | 303 | — |
Employee severance, transition and transformation costs | (11) |  | (16) |  |  | (49) |  | (51) |
Other | (1) |  | (1) |  |  | (4) |  | (13) |
Total adjustments | 293 |  | (29) |  |  | 264 |  | (74) |
EBITDA | 743 |  | 463 |  |  | 2,117 |  | 1,748 |

25

RENEWABLE POWER GENERATION

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 140 |  | 146 |  |  | 496 |  | 507 |
Change in unrealized derivative fair value gain | 2 |  | 1 |  |  | 8 |  | 3 |
Realized hedges | 13 |  | — |  |  | 13 |  | — |
Equity earnings adjustment | (8) |  | — |  |  | (8) |  | — |
Disposition - MATL transmission assets | — |  | — |  |  | — |  | 13 |
Other | (1) |  | — |  |  | (1) |  | — |
Total adjustments | 6 |  | 1 |  |  | 12 |  | 16 |
EBITDA | 146 |  | 147 |  |  | 508 |  | 523 |

ENERGY SERVICES

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | (83) |  | (82) |  |  | (360) |  | (119) |
Change in unrealized derivative fair value gain/(loss) | 155 |  | (146) |  |  | 53 |  | (122) |
Net inventory adjustment | (6) |  | 4 |  |  | (6) |  | 5 |
Total adjustments | 149 |  | (142) |  |  | 47 |  | (117) |
EBITDA | 66 |  | (224) |  |  | (313) |  | (236) |

ELIMINATIONS AND OTHER

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 150 |  | (20) |  |  | 431 |  | (14) |
Change in unrealized derivative fair value gain | 72 |  | 433 |  |  | 55 |  | 318 |
Change in corporate guarantee obligation | — |  | — |  |  | — |  | (74) |
Investment write-down loss | — |  | — |  |  | — |  | (43) |
Employee severance, transition and transformation costs | (27) |  | (17) |  |  | (87) |  | (279) |
Other | (30) |  | (11) |  |  | (43) |  | (21) |
Total adjustments | 15 |  | 405 |  |  | (75) |  | (99) |
EBITDA | 165 |  | 385 |  |  | 356 |  | (113) |

26

APPENDIX C
NON-GAAP RECONCILIATION – CASH PROVIDED BY OPERATING ACTIVITIES TO DCF

| Three months ended December 31, |  | Year ended December 31,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Cash provided by operating activities | 2,302 |  | 2,254 |  |  | 9,256 |  | 9,781 |
Adjusted for changes in operating assets and liabilities 1 | 548 |  | 120 |  |  | 1,616 |  | (93) |
| 2,850 |  | 2,374 |  |  | 10,872 |  | 9,688 |
Distributions to noncontrolling interests | (64) |  | (68) |  |  | (271) |  | (300) |
Preference share dividends | (93) |  | (96) |  |  | (367) |  | (380) |
Maintenance capital expenditures 2 | (274) |  | (320) |  |  | (686) |  | (915) |
Significant adjusting items: |  |  |  |  |
Other receipts of cash not recognized in revenue 3 | 53 |  | 42 |  |  | 127 |  | 292 |
Employee severance, transition and transformation costs | 39 |  | 31 |  |  | 147 |  | 335 |
Distributions from equity investments in excess of cumulative earnings 4 | 121 |  | 263 |  |  | 418 |  | 675 |
Other items | (145) |  | (17) |  |  | (199) |  | 45 |
DCF | 2,487 |  | 2,209 |  |  | 10,041 |  | 9,440 |
DCF per common share | 1.23 |  | 1.09 |  |  | 4.96 |  | 4.67 |

1 Changes in operating assets and liabilities, net of recoveries.
2 Maintenance capital expenditures are expenditures that are required for the ongoing support and maintenance of the existing pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete or completing their useful lives). For the purpose of DCF, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets.
3 Consists of cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements.
4 Presented net of adjusting items.
27