EX-99.1 2 ei093020218-knr991.htm EX-99.1
NEWS RELEASE
Enbridge Reports Strong Third Quarter 2021 Results, Executing on Business Priorities
CALGARY, November 5, 2021 /CNW/ - Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported third quarter 2021 financial results, reaffirmed its 2021 financial outlook, and provided a quarterly business update.
Highlights
(all financial figures are unaudited and in Canadian dollars unless otherwise noted)
•Third quarter GAAP earnings of $682 million or $0.34 per common share, compared with GAAP earnings of $990 million or $0.49 per common share in 2020
•Adjusted earnings of $1.2 billion or $0.59 per common share, compared with $1.0 billion or $0.48 per common share in 2020
•Adjusted earnings before interest, income taxes and depreciation and amortization (EBITDA) of $3.3 billion, compared with $3.0 billion in 2020
•Cash Provided by Operating Activities of $2.2 billion, compared with $2.3 billion in 2020
•Distributable Cash Flow (DCF) of $2.3 billion or $1.13 per common share, compared with $2.1 billion or $1.03 per common share in 2020
•Reaffirmed 2021 full year guidance range for EBITDA of $13.9 billion to $14.3 billion and DCF per share of $4.70 to $5.00
•Completed and placed into service the U.S. Line 3 Replacement Project ensuring safe, reliable supply of Western Canadian crude
•Placed into service the expansion of Southern Access (Line 61) increasing capacity to 1.2 million barrels per day
•Acquired North America's premier crude export facility located near Corpus Christi, Texas, significantly advancing Enbridge's U.S. Gulf Coast export strategy
•Placed the final phases of the T-South Expansion and Spruce Ridge projects into operation, facilitating the essential supply of natural gas to meet West Coast demand
•Completed the Appalachia to Market and Middlesex Extension projects, which expand the U.S. Northeast's access to reliable natural gas supply
•Established a dedicated New Energies Team to advance low-carbon energy infrastructure opportunities across Enbridge's four energy delivery platforms
•Commissioned industrial scale green hydrogen blending facility to inject hydrogen into the natural gas stream for Enbridge Gas utility customers
•Construction of three French offshore wind projects, representing approximately 1.4 GW of gross renewable power generation, progressing on schedule
•Announced a partnership with Vanguard Renewables to build up to eight renewable natural gas (RNG) facilities in the U.S. along Enbridge's gas transmission systems
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•Entered into a memorandum of understanding (MoU) with Shell to develop North American low-carbon energy solutions, focused on hydrogen, renewables, and carbon capture
•Completed 2021 financing requirements through issuances of $4.8 billion in the U.S. and Canadian debt markets, including $1.1 billion Canadian sustainability-linked bonds
CEO COMMENT
Al Monaco, President and CEO commented on the following:
"The return of energy demand growth to its pre-pandemic trend, coupled with underinvestment in conventional energy and the recent rise in global energy prices, underscores the criticality of affordable, reliable and secure energy supply for consumers and our social well-being. We believe sustainable development of North America's significant energy resources is essential to meeting both global energy needs and societal emissions reduction objectives. The energy we deliver is critical to fueling quality of life in North America and globally and this will continue for decades to come.
"At Enbridge, we're strengthening our connections to global markets and transitioning our energy mix towards lower-carbon solutions. Over the last two decades, we've significantly expanded our natural gas business and connections to LNG markets, extended our crude oil platform to the U.S. Gulf Coast and waterborne exports, and built a world-class renewables business. Today, we're leveraging these platforms to make disciplined investments in hydrogen, RNG and carbon capture opportunities, and to extend long-term growth and further strengthen our resilience.
"Our objective is to be a differentiated energy infrastructure service provider for our customers by leading our industry on environmental, social and governance performance. In September, we held our inaugural ESG Forum, outlining how we're committed to safely delivering energy, lowering our emissions, and diversifying our workforce. Since 2018, we've reduced our Scope 1 emissions by 32% and Scope 2 by 14%, along with continued improvements in diversity at all levels of our organization. And, to ensure we continue to deliver on our commitments, we've tied our goals to enterprise-wide compensation and over $3 billion in sustainability-linked financings so far.
"In the third quarter, the business delivered strong operational performance and financial results across our four franchises. Our low-risk business model continues to generate predictable results and execution on our strategic priorities is driving solid cash flow growth and per share results.
"In Liquids Pipelines, we completed the Minnesota leg of the Line 3 Replacement Project, allowing us to commence operations of this state-of-the-art pipeline providing a safe and reliable supply of energy. We're very proud of the relationship of trust we've built through this project with communities and Indigenous nations and groups along the right-of-way in both Canada and the United States.
"During the quarter, we acquired the Ingleside Energy Center, North America's premier crude oil export terminal. With the lowest basin-to-water cost structure and proximity to world-class Permian reserves, this terminal will be critical to North America capitalizing on its energy
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advantage. The transaction is expected to be immediately accretive to cash flow per share while maintaining our strong balance sheet and financial flexibility.
"This investment is a prime example of how we're focused on being a differentiated service provider to our customers. By committing to invest in co-located solar power, we will achieve net-zero scope 1 and 2 emissions at the facility and contribute to scope 3 emission reductions.
"In Gas Transmission, we've continued to advance the execution of our North American-wide secured capital program. Our multi-year modernization program is on track, and we've placed the Appalachia to Market and Middlesex Extension projects into service, which will provide much needed access to natural gas supplies in New England for the upcoming heating season. In B.C., our expansions are progressing well, with the $1 billion T-South project and the $0.5 billion Spruce Ridge project commencing operations.
"The Utility is on track to add another 45 thousand customers in 2021 and advancing community expansion programs across the system. This business also continues to provide us with a unique opportunity to develop low-carbon solutions within our low-risk commercial model. We've now commissioned our first hydrogen blending pilot facility serving the Utility's customers and commenced construction of our seventh RNG project. These projects demonstrate the importance of our conventional assets to the transition to a lower-carbon economy.
"Our renewables business is making good progress on the construction of the three offshore wind projects off the coast of France, which will generate enough renewable energy to power over 1 million homes. And, in North America, four more solar self-power projects are in construction along our liquids pipelines, further lowering our emissions.
"In September, we announced that we're building on our track record of success in renewables and low-carbon investments with the formation of our New Energies Team. This team will be dedicated to advancing our low-carbon strategies and differentiated energy delivery capabilities across each of our businesses. And, we're partnering with leading low-carbon energy companies to combine their technologies with our existing energy infrastructure capabilities.
"We're on track to deliver more than $10 billion of capital into service in 2021. This capital, along with embedded growth in each of our businesses, will drive significant free cash flow growth and approximately $5-6 billion of annual investable capacity to redeploy into our business. Each of our blue chip platforms has a strong opportunity set of conventional and low-carbon organic growth, and we will continue to prioritize disciplined capital allocation where new growth projects will compete against capital allocation opportunities.
"At our upcoming annual investor day on December 7 th, we'll outline our 3-year plan priorities, including 2022 financial guidance. And, our business leaders will walk through how each of our businesses are positioned to benefit from conventional and low-carbon organic growth, along with how our disciplined approach to investment will continue to maximize shareholder value.
"2021 continues to be a strong catalyst year for Enbridge. We've reaffirmed our full year 2021 EBITDA and DCF per share guidance and executed on our strategic priorities. We're excited about how we're positioned for energy transition and the opportunities that lay ahead in 2022 and beyond."
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FINANCIAL RESULTS SUMMARY
Financial results for the three and nine months ended September 30, 2021 and 2020 are summarized in the table below:

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts; number of shares in millions) |  |  |  |  |
GAAP Earnings attributable to common shareholders | 682 |  | 990 |  |  | 3,976 |  | 1,208 |
GAAP Earnings per common share | 0.34 |  | 0.49 |  |  | 1.97 |  | 0.60 |
Cash provided by operating activities | 2,163 |  | 2,302 |  |  | 6,954 |  | 7,527 |
Adjusted EBITDA 1 | 3,269 |  | 2,997 |  |  | 10,314 |  | 10,072 |
Adjusted Earnings 1 | 1,184 |  | 961 |  |  | 4,175 |  | 3,762 |
Adjusted Earnings per common share 1 | 0.59 |  | 0.48 |  |  | 2.06 |  | 1.86 |
Distributable Cash Flow 1 | 2,290 |  | 2,088 |  |  | 7,554 |  | 7,231 |
Weighted average common shares outstanding | 2,024 |  | 2,021 |  |  | 2,023 |  | 2,020 |

1 Non-GAAP financial measures. Schedules reconciling adjusted EBITDA, adjusted earnings, adjusted earnings per common share and distributable cash flow are available as Appendices to this news release.
GAAP earnings attributable to common shareholders for the third quarter of 2021 decreased by $308 million or $0.15 per share compared with the same period in 2020.
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 third quarter Management Discussion & Analysis filed as part of the third quarter financial statements for a detailed discussion of GAAP financial results.
Adjusted earnings in the third quarter of 2021 increased by $223 million, or $0.11 per share and was driven largely by 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.
Adjusted EBITDA in the third quarter of 2021 increased by $272 million compared with the same period in 2020. This is primarily driven by rebounding demand for energy as economies continue to recover from the impacts of the COVID-19 pandemic offset by the impacts of a weaker USD which negatively impacts the translation of the Company's USD denominated EBITDA. The average CAD to USD exchange rate in the third quarter fell approximately 5% in 2021 to $1.26, compared with $1.33 in the third 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.
DCF for the third quarter was $2.3 billion, an increase of $202 million over the third quarter of 2020, driven primarily by the impact of the operating factors discussed above, along with lower utility maintenance capital expenditures in 2021 and lower interest expense as discussed above.
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.
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FINANCIAL POSITION
The Company expects to maintain a strong financial position for the remainder of 2021, consistent with its target Debt/EBITDA range of 4.5x to 5.0x. Further strengthening is anticipated in 2022 as annualized EBITDA contributions from the approximately $14 billion of capital projects and asset acquisitions executed in 2021 are realized, along with the closing of the $1.1 billion sale of Noverco expected in late 2021 or early 2022.
As of today, Enbridge has completed its financing plan issuing approximately $4.8 billion at attractive rates in the U.S. and Canadian debt markets since July 1, 2021. These issuances complete the Company's 2021 financing plan requirements, which includes funding for the Moda Midstream Operating LLC acquisition consisting of the Ingleside Energy Center and related pipeline and logistics assets, which closed subsequent to the quarter.
Included in the third quarter financings was a $1.1 billion Canadian market issuance of 12-year Sustainability-Linked senior notes which links directly to the Company's ESG goals. Together with the US$1.0 billion of senior notes and $1.0 billion credit facility issued earlier in 2021, this brings Enbridge's total sustainability-linked financings to approximately $3.3 billion demonstrating the Company's ongoing commitment to ESG leadership.
Proceeds from these offerings were primarily used to repay existing indebtedness, partially fund capital projects, and for other general corporate purposes.
FINANCIAL OUTLOOK
The Company expects full year 2021 EBITDA and DCF to remain within its previously provided guidance range of $13.9 billion to $14.3 billion and $4.70 to $5.00 per share, respectively.
EBITDA across each of the Company's four businesses benefited from strong operating performance in the first nine months of 2021, which is expected to continue in the fourth quarter. In addition, the completion of the Line 3 Replacement Project, the T-South Reliability and Expansion Program, the Spruce Ridge Project, the Moda acquisition discussed in detail below, and several smaller capital projects within the third quarter, are expected to provide incremental EBITDA contributions in the fourth quarter and in 2022. However, these positive operating factors have been, and are expected to continue to be, impacted by a weaker USD currency (net of foreign exchange hedges), warmer than normal weather in Ontario impacting Gas Distribution and Storage and negative contributions from Energy Services, which remains challenged by narrow location and quality differentials, as well as backwardation in commodity prices.
DCF is expected to benefit from lower overall financing costs resulting from favorable short-term interest rates and USD denominated interest expense which benefits from a weaker USD currency, lower cash taxes primarily due to increased utilization of existing tax pools to offset U.S. taxable income, and slightly lower than planned Gas Distribution and Storage maintenance spending.
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SECURED GROWTH PROJECT EXECUTION UPDATE
The Company's approximately $17 billion secured growth capital program is well-diversified across its four businesses and contractually underpinned by commercial frameworks consistent with its low-risk pipeline-utility model. Capital expenditures to date across the secured capital program are approximately $10 billion, with $7 billion remaining to be spent.
Enbridge is on track to place approximately $10 billion of capital into service in 2021, which is expected to generate significant EBITDA and free cash flow growth in 2022. Since July 1, 2021, Enbridge has placed approximately $8 billion of capital projects into service, including:
•the US$4.0 billion U.S. portion of the Line 3 Replacement Project and associated US$0.5 billion Southern Access Expansion to 1.2 million barrels per day (mmbpd);
•the $1.0 billion T-South Reliability and Expansion Program and the $0.5 billion Spruce Ridge Project, which increase capacity on the B.C. Pipeline; and,
•the combined US$0.1 billion Appalachia to Market and Middlesex Extension projects, which support reliable natural gas supply into the U.S. Northeast.
In addition, Enbridge continues to advance execution of its multi-year US$2.1 billion Gas Transmission and Midstream modernization program, and is on track to add an estimated 45 thousand Gas Distribution and Storage customers in 2021, including related capital expenditures.
In Renewable Power Generation, construction of the three previously announced French offshore wind projects, Saint-Nazaire, Fécamp, and Calvados, is advancing on schedule for the targeted in-service dates ranging between late 2022 and 2024. Combined, these projects will provide 1.4 GW (0.3 GW net) of generation capacity in France, enough to power over 1 million homes with renewable energy.
Line 3 Replacement Project and Southern Access Expansion
The U.S. portion of the Line 3 Replacement Project was placed into service on October 1, 2021. This completes the final step of the full replacement project from Hardisty, AB to Superior, WI, restoring its capacity to 760 kbpd. This project enhances the continued safe and reliable operations of Enbridge's Mainline System, which provides essential feedstock to meet U.S. and Canadian refinery demand.
For the first nine months of 2021, Enbridge has been collecting a partial surcharge of US$0.20 per barrel on the Canadian portion of Line 3 Replacement Project, which commenced operations in late 2019. As of October 1, 2021, the full Line 3 Replacement surcharge of US$0.935 per barrel, inclusive of a US$0.04 per barrel receipt terminalling surcharge, is in effect. Inclusive of the surcharge increase and restored capacity, the project is expected to contribute approximately $200 million of incremental EBITDA in the fourth quarter of 2021, and support significant cash flow growth in 2022 and beyond.
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In addition, the Company has placed into service the expansion of Southern Access (Line 61) originating at Enbridge's Superior, Wisconsin Terminal and flowing to the Flanagan, Illinois Terminal. The expansion increases Southern Access's capacity by approximately 200 thousand barrels per day (kbpd) to 1.2 mmbpd and ensures market access for additional barrels flowing on the Mainline with the completion of the Line 3 Replacement Project.
Upon completion of the Line 3 Replacement Project and Southern Access Expansion, and net of system optimizations already in operation, the Company anticipates average annual ex-Gretna Mainline capacity of approximately 3.1 mmbpd and average throughput for the fourth quarter of approximately 2.95 mmbpd.
OTHER BUSINESS UPDATES
Changes to Board of Directors
Today, Enbridge announced that its Board of Directors has appointed Gaurdie Banister and Jane Rowe as directors of Enbridge, effective November 4, 2021.
Also, on November 1, 2021, Mr. Marcel R. Coutu and Ms. V. Maureen Kempston Darkes each notified Enbridge of their intention to resign from the Board of Directors of the Company, effective November 1, 2021. Neither Mr. Coutu’s nor Ms. Kempston Darkes’ decision to resign from the Board of Directors was the result of any disagreement relating to the Company's operations, policies or practices.
"On behalf of the Board of Directors of Enbridge, we are very pleased to welcome Gaurdie and Jane to the Enbridge Board. They each have extensive business experience and will be excellent additions to our Board. We look forward to their contributions. At the same time, we would like to thank Marcel and Maureen for their valuable service and contributions to Enbridge over the years,” stated Greg Ebel, the Chair of the Board of Directors of Enbridge.
Liquids Pipelines
Mainline Contracting
The Mainline Contracting hearing before the Canada Energy Regulator (CER) concluded during the quarter. The CER is now reviewing the record developed throughout the regulatory process and has indicated that it anticipates it will release its decision in November of this year.
The current Competitive Toll Settlement (CTS) expired on June 30, 2021 and, consistent with the terms of the CTS agreement, the tolls in effect at that time remained in effect on July 1, 2021 on an interim basis subject to finalization and refund, if any. With the U.S. portion of the Line 3 Replacement Project entering service, these interim tolls have been updated effective October 1, 2021 to include the full Line 3 Replacement surcharge of US$0.935 per barrel inclusive of a US$0.04 receipt terminalling surcharge.
Moda Acquisition
On October 12, 2021, Enbridge closed the previously announced acquisition of Moda Midstream Operating LLC for US$3.0 billion. The acquisition included a 100 percent operating interest in the Ingleside Energy Center, North America's largest crude oil export terminal, located near Corpus Christi, Texas. This state-of-the-art terminal consists of 15.3 million barrels of storage, fully contracted under long-term take-or-pay storage contracts, and 1.6 mmbpd of export capacity underpinned by 925 kbpd of long-term take-or-pay vessel loading contracts.
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In addition, Enbridge acquired a 20 percent interest in the 670-kbpd Cactus II Pipeline, a 100 percent operating interest in the 300-kbpd Viola pipeline, and a 100 percent interest in the 350-thousand-barrel Taft Terminal. Together with the Ingleside Energy Center, these pipelines and storage assets provide a fully integrated light crude export platform.
This acquisition significantly advances Enbridge's U.S. Gulf Coast export strategy and provides connectivity to low-cost and long-lived reserves in the Permian and Eagle Ford basins. The acquired assets are expected to be immediately and strongly accretive to DCF and earnings per share and provide further organic growth opportunities supporting Enbridge's post-2023 growth outlook.
Gas Transmission and Midstream
Regulatory Update
The Company's regulatory strategy requires periodic rate case filings to ensure just and reasonable returns on and of the capital invested into its critical energy delivery systems.
On September 10, 2021, the Federal Energy Regulatory Commission (FERC) approved a Stipulation and Agreement filed with regards to the Section 4 East Tennessee rate case filed on June 30, 2020. On an annualized basis, this settlement is expected to provide an incremental EBITDA contribution of approximately US$10 million.
During the quarter, Enbridge filed a Section 4 rate case on the Texas Eastern system to reflect growth in the system's rate base and an increase in cost of service, primarily as a result of system modernization, and safety and reliability investments. The FERC has accepted the filing, allowing filed rate increases to take effect after a 5 month suspension period, subject to refund. Negotiations with shippers are expected to begin in early 2022.
Gas Distribution and Storage
Hydrogen Blending
On October 1, 2021, Enbridge's first large scale green hydrogen blending facility located in Markham, Ontario was commissioned, adding up to 2% hydrogen by volume into the gas stream for 3,600 customers. This project has the potential to contribute to the avoidance of up to 120 tCO 2 e annually, and could pave the way for blending into the entire Ontario gas distribution system.
In addition, Enbridge continues to develop a second green hydrogen blending facility in Gatineau, Quebec, in partnership with Evolugen. This facility could blend up to 15% hydrogen by volume for 43,000 customers and has the potential to contribute to the avoidance of up to 15,000 tCO 2 e annually.
RNG Development
The Company announced its seventh RNG project located at the City of Toronto's Disco Road Solid Waste Management Facility. This facility will produce RNG from biodegradable waste collected as part of the City of Toronto's Green Bin program and inject it into Enbridge Gas Inc.'s natural gas distribution system lowering natural gas related CO 2 emissions. The project is expected to be in service in 2023.
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Enbridge is developing a further 10 to 15 projects independently within its franchise, and across Canada in partnership with Comcor Technologies and Walker Industries.
Renewable Power Generation
Formation of New Energies Team and Additional Partnerships
During the third quarter, Enbridge announced the creation of a dedicated team focused on advancing low-carbon energy infrastructure opportunities across the Company's energy delivery businesses. The team will leverage and build on Enbridge's early investments in RNG, hydrogen and carbon capture, utilization and storage (CCUS), as well as other low-carbon technologies.
The Company announced a MoU with Shell to develop low-carbon energy solutions across North America leveraging both companies' extensive experience, complimentary assets and commitment to ESG leadership. Enbridge and Shell will explore opportunities to collaborate on potential green and blue hydrogen production, renewable power generation where the parties bring unique strengths, and CCUS opportunities, which at present excludes the Alberta market given various opportunities already under development.
Enbridge also announced a partnership with Vanguard Renewables, a leading U.S. developer of RNG infrastructure. Under the partnership, Vanguard Renewables will initially build and operate up to 8 digesters in the U.S. Northeast and Midwest capable of producing approximately
2 Bcf/year of RNG from food and farm waste, with Enbridge investing up to $100 million in RNG upgrading and transportation assets, and providing marketing services that leverage its extensive energy infrastructure assets and capabilities. This partnership positions Enbridge as the partner of choice for future mixed-waste RNG development projects.
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THIRD QUARTER 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 third quarter of 2021.
GAAP SEGMENT EBITDA AND CASH FLOW FROM OPERATIONS

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Liquids Pipelines | 1,673 |  | 2,090 |  |  | 5,756 |  | 5,280 |
Gas Transmission and Midstream | 884 |  | 334 |  |  | 2,725 |  | 230 |
Gas Distribution and Storage | 282 |  | 298 |  |  | 1,374 |  | 1,285 |
Renewable Power Generation | 91 |  | 93 |  |  | 362 |  | 376 |
Energy Services | (204) |  | (34) |  |  | (379) |  | (12) |
Eliminations and Other | (121) |  | 207 |  |  | 191 |  | (498) |
EBITDA | 2,605 |  | 2,988 |  |  | 10,029 |  | 6,661 |
Earnings attributable to common shareholders | 682 |  | 990 |  |  | 3,976 |  | 1,208 |
Cash provided by operating activities | 2,163 |  | 2,302 |  |  | 6,954 |  | 7,527 |

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.
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DISTRIBUTABLE CASH FLOW

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Liquids Pipelines | 1,898 |  | 1,732 |  |  | 5,623 |  | 5,395 |
Gas Transmission and Midstream | 986 |  | 945 |  |  | 2,928 |  | 3,017 |
Gas Distribution and Storage | 296 |  | 315 |  |  | 1,403 |  | 1,330 |
Renewable Power Generation | 89 |  | 93 |  |  | 356 |  | 361 |
Energy Services | (116) |  | (110) |  |  | (277) |  | (37) |
Eliminations and Other | 116 |  | 22 |  |  | 281 |  | 6 |
Adjusted EBITDA 1,3 | 3,269 |  | 2,997 |  |  | 10,314 |  | 10,072 |
Maintenance capital | (142) |  | (256) |  |  | (412) |  | (595) |
Interest expense 1 | (665) |  | (721) |  |  | (1,977) |  | (2,141) |
Current income tax 1 | (89) |  | (83) |  |  | (210) |  | (325) |
Distributions to noncontrolling interests 1 | (66) |  | (68) |  |  | (207) |  | (232) |
Cash distributions in excess of equity earnings 1 | 52 |  | 197 |  |  | 248 |  | 479 |
Preference share dividends | (92) |  | (94) |  |  | (274) |  | (284) |
Other receipts of cash not recognized in revenue 2 | 23 |  | 118 |  |  | 74 |  | 250 |
Other non-cash adjustments | — |  | (2) |  |  | (2) |  | 7 |
DCF 3 | 2,290 |  | 2,088 |  |  | 7,554 |  | 7,231 |
Weighted average common shares outstanding | 2,024 | 2,021 |  |  | 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 Schedules reconciling adjusted EBITDA and DCF are available as Appendices to this news release.
Third quarter 2021 DCF increased $202 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 due to timing of spend; and
•lower interest expense due to favorable interest rates on short-term borrowings as well as the impact of a weaker USD currency that positively impacts the translation of interest payments on USD denominated debt; partially offset by
•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; and
•lower receipts of cash not recognized in revenue primarily due to shippers utilizing take-or-pay commitments on contracted assets that contain make-up right provisions in the third quarter of 2021 when compared with the third quarter of 2020, which allows for the recognition of the revenue in Adjusted EBITDA.
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ADJUSTED EARNINGS

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Adjusted EBITDA 1 | 3,269 |  | 2,997 |  |  | 10,314 |  | 10,072 |
Depreciation and amortization | (944) |  | (935) |  |  | (2,805) |  | (2,766) |
Interest expense 2 | (654) |  | (708) |  |  | (1,941) |  | (2,099) |
Income taxes 2 | (355) |  | (278) |  |  | (1,023) |  | (1,133) |
Noncontrolling interests 2 | (34) |  | (21) |  |  | (90) |  | (28) |
Preference share dividends | (98) |  | (94) |  |  | (280) |  | (284) |
Adjusted earnings 1 | 1,184 |  | 961 |  |  | 4,175 |  | 3,762 |
Adjusted earnings per common share | 0.59 |  | 0.48 |  |  | 2.06 |  | 1.86 |

1 Schedules reconciling adjusted EBITDA and adjusted earnings are available as Appendices to this news release.
2 Presented net of adjusting items.
Adjusted earnings increased $223 million and adjusted earnings per share increased $0.11 compared with the third quarter in 2020. The increase in adjusted earnings was driven by the same factors impacting business performance and adjusted EBITDA as discussed under Adjusted EBITDA by Segments below, as well as lower interest expense due to favorable interest rates on short-term borrowings as well as the impact of a weaker USD currency that positively impacts the translation of interest payments on USD denominated debt.
ADJUSTED EBITDA BY SEGMENTS
Adjusted EBITDA by segment is reported on a Canadian dollar basis. Adjusted EBITDA generated from U.S. dollar denominated businesses, primarily within Liquids Pipelines and Gas Transmission and Midstream, were translated at a lower average Canadian dollar exchange rate in the third quarter of 2021 (C$1.26/US$) when compared with the corresponding 2020 period (C$1.33/US$).
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 September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Mainline System | 1,083 |  | 994 |  |  | 3,264 |  | 3,070 |
Regional Oil Sands System | 225 |  | 195 |  |  | 693 |  | 605 |
Gulf Coast and Mid-Continent System | 252 |  | 213 |  |  | 702 |  | 714 |
Other 1 | 338 |  | 330 |  |  | 964 |  | 1,006 |
Adjusted EBITDA 2 | 1,898 |  | 1,732 |  |  | 5,623 |  | 5,395 |
Operating Data (average deliveries – thousands of bpd) |  |  |  |  |
Mainline System - ex-Gretna volume 3 | 2,673 | 2,555 |  | 2,680 | 2,612
Regional Oil Sands System 4 | 1,899 | 1,399 |  | 1,911 | 1,549
International Joint Tariff (IJT)5 | $4.27 |  | $4.27 |  |  | $4.27 |  | $4.23 |
Competitive Tolling Settlement Surcharges 5 | $0.26 |  | $0.26 |  |  | $0.26 |  | $0.19 |
Line 3 Canada Interim Surcharge 5,6 | $0.20 |  | $0.20 |  |  | $0.20 |  | $0.20 |

1 Other consists of Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines & Other.
2 Schedules reconciling adjusted EBITDA are available as Appendices to 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 third quarter of 2021 was C$1.26/US$ (Q3 2020: C$1.20/US$).
The U.S. portion of the Mainline System is subject to FX translation similar to the Company’s other U.S. based businesses, which are translated at the average spot rate for a given period. A portion of this U.S. dollar translation exposure is hedged under the Company's enterprise-wide financial risk management program. The offsetting hedge settlements are reported within Eliminations and Other.
6 Interim surcharge for the Canadian portion of the Line 3 Replacement Project, which was placed into service on December 1, 2019. The interim surcharge was replaced by the full Line 3 Replacement surcharge beginning on October 1, 2021 with the completion of the U.S. portion of the Line 3 Replacement Project.
Liquids Pipelines adjusted EBITDA increased $166 million compared with the third quarter of 2020, primarily related to:
•higher Mainline System throughput compared with the third quarter of 2020 driven by the rebounding demand for crude oil and related products from the impacts of the COVID-19 pandemic, and a higher effective foreign exchange hedge rate (C$1.26 in 2021 vs. C$1.20 in 2020) on hedges used to manage foreign exchange risk of the U.S. dollar denominated Canadian Mainline revenue;
•higher throughput within the Regional Oil Sands System due to recovery from the impacts of the COVID-19 pandemic and completion of the Woodland Pipeline expansion in June 2021; and
•higher contributions from the Gulf Coast and Mid-Continent System due primarily to higher throughput on the Seaway Crude Pipeline System; partially offset by
•lower throughput on the Flanagan South Pipeline reflected in Gulf Coast and Mid-Continent System driven by robust PADD II refinery demand resulting in less volumes available to move towards the U.S. Gulf Coast; and
13

•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 gains in the Eliminations and Other segment as part of the Company's enterprise-wide financial risk management program.
GAS TRANSMISSION AND MIDSTREAM

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
U.S. Gas Transmission | 732 |  | 762 |  |  | 2,235 |  | 2,417 |
Canadian Gas Transmission | 130 |  | 111 |  |  | 412 |  | 354 |
U.S. Midstream | 85 |  | 36 |  |  | 169 |  | 116 |
Other | 39 |  | 36 |  |  | 112 |  | 130 |
Adjusted EBITDA 1 | 986 |  | 945 |  |  | 2,928 |  | 3,017 |

1 Schedules reconciling adjusted EBITDA are available as Appendices to this news release.
•
Gas Transmission and Midstream adjusted EBITDA increased $41 million compared with the third quarter of 2020 primarily related to:
•higher U.S. Gas Transmission contributions from the Atlantic Bridge Phase III project, with in-service notifications to FERC in January of 2021 and increased revenue due to the absence of pressure restrictions that existed on the Texas Eastern system in 2020;
•higher Canadian Gas Transmission contributions due timing of operating and administrative expenses; and
•higher U.S. midstream contributions as a result of higher commodity prices benefiting Enbridge's Aux Sable and DCP joint ventures; partially offset by
•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, which is partially offset by realized gains in the Eliminations and Other segment as part of the Company's enterprise-wide financial risk management program.
14

GAS DISTRIBUTION AND STORAGE

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Enbridge Gas Inc. (EGI) | 294 |  | 327 |  |  | 1,317 |  | 1,286 |
Other | 2 |  | (12) |  |  | 86 |  | 44 |
Adjusted EBITDA 1 | 296 |  | 315 |  |  | 1,403 |  | 1,330 |
Operating Data |  |  |  |  |
EGI |  |  |  |  |
Volumes (billions of cubic feet) | 302 |  | 297 |  |  | 1,383 |  | 1,286 |
Number of active customers 2 (millions) |  |  |  | 3.8 |  | 3.8 |
Heating degree days 3 |  |  |  |  |
Actual | 61 |  | 90 |  |  | 2,350 |  | 2,423 |
Forecast based on normal weather 4 | 94 |  | 94 |  |  | 2,538 |  | 2,533 |

1 Schedules reconciling adjusted EBITDA are available as Appendices to this news release.
2 Number of active customers is the number of natural gas consuming customers at the end of the reported period.
3 Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in EGI's distribution franchise areas.
4 Normal weather is the weather forecast by EGI in its legacy rate zones, using the forecasting methodologies approved by the Ontario Energy Board.
Gas Distribution and Storage adjusted EBITDA will typically follow a seasonal profile. It is generally highest in the first and fourth quarters of the year reflecting greater volumetric demand during the heating season. The magnitude of the seasonal EBITDA fluctuations will vary from year-to-year reflecting the impact of colder or warmer than normal weather on distribution volumes. Results include contributions from Noverco within Other. The Noverco transaction is anticipated to close in late 2021 or early 2022.
Gas Distribution and Storage adjusted EBITDA decreased $19 million compared with the third quarter of 2020 primarily related to the timing of operating expenditures. This has been partially offset by higher distribution revenue charges resulting from increases in annual rates and customer base growth.
RENEWABLE POWER GENERATION

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA 1 | 89 |  | 93 |  |  | 356 |  | 361 |

1 Schedules reconciling adjusted EBITDA are available as Appendices to this news release.
Renewable Power Generation adjusted EBITDA decreased $4 million compared with the third quarter of 2020 primarily related to lower wind resources at the Canadian wind facilities partially offset by lower mechanical repair costs at certain U.S. wind facilities.
15

ENERGY SERVICES

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA 1 | (116) |  | (110) |  |  | (277) |  | (37) |

1 Schedules reconciling adjusted EBITDA are available as Appendices to this news release.
Energy Services adjusted EBITDA decreased $6 million compared with the third quarter of 2020. Significant compression of location and quality differentials in certain markets remain, along with limited storage opportunities in 2021 due to market price backwardation. These conditions lead to fewer opportunities to achieve profitable transportation margins on facilities in which Energy Services holds capacity obligations.
ELIMINATIONS AND OTHER

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Operating and administrative recoveries | 66 |  | 58 |  |  | 153 |  | 166 |
Realized foreign exchange hedge settlement gains/(losses) | 50 |  | (36) |  |  | 128 |  | (160) |
Adjusted EBITDA 1 | 116 |  | 22 |  |  | 281 |  | 6 |

1 Schedules reconciling adjusted EBITDA are available as Appendices to this news release.
Operating and administrative recoveries captured in this segment reflect the cost of centrally delivered services (including depreciation of corporate assets) inclusive of amounts recovered from business units for the provision of those services. Also, as previously noted, U.S. dollar denominated earnings within the segment results are translated at average foreign exchange rates during the quarter. The offsetting impact of settlements made under the Company's enterprise foreign exchange hedging program are captured in this segment.
Eliminations and Other adjusted EBITDA increased $94 million compared with the third quarter of 2020 due to realized foreign exchange gains in 2021 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 third quarter of 2021 (Q3 2020:$1.33) compared with a hedge rate of $1.32 for the third quarter of 2021 (Q3 2020:$1.29).
16

CONFERENCE CALL
Enbridge will host a conference call and webcast on November 5, 2021 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide an enterprise wide business update and review 2021 third 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 9798691. The call will be audio webcast live at https://event.on24.com/wcc/r/3402404/9DF8A3A8FCEFF35C5F575413CA0478CB. 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 approximately 24 hours after the event. 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: 9798691).
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 3, 2021, the Company's Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2021 to shareholders of record on November 15, 2021.

| Dividend per share
Common Shares 1 | $0.83500 |
Preference Shares, Series A | $0.34375 |
Preference Shares, Series B | $0.21340 |
Preference Shares, Series C 2 | $0.16081 |
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 $0.835 from $0.81, effective March 1, 2021.
2 The quarterly dividend per share paid on Series C was increased to $0.15501 from $0.15349 on March 1, 2021, increased to $0.15753 from $0.15501 on June 1, 2021, and increased to $0.16081 from $0.15753 on September 1, 2021, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.
17

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; 2021 financial guidance; energy intensity and emissions reduction targets; the expected supply of, demand for and prices of crude oil, natural gas, natural gas liquids, liquified natural gas and renewable energy; anticipated utilization of our existing assets, including throughput on the Mainline; expected EBITDA and expected adjusted EBITDA; expected earnings/(loss) and adjusted earnings/(loss); expected DCF and DCF per share; expected future cash flows; expected performance of the Company’s businesses; financial strength and flexibility and investment capacity; capital allocation priorities; expectations on sources of liquidity and sufficiency of financial resources; expected in-service dates and costs related to announced projects and projects under construction and for maintenance; expected future growth and expansion opportunities; expected benefits of transactions; and expected future actions and decisions of regulators and courts and the timing and impact thereof; toll and rate case discussions and filings, including Mainline Contracting.
Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the COVID-19 pandemic and the duration and impact thereof; the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; energy transition; anticipated utilization of our existing assets; exchange rates; inflation; interest rates; availability and price of labour and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; weather; anticipated reductions in operating costs; the timing and closing of acquisitions and dispositions; the realization of anticipated benefits and synergies of transactions and projects; governmental legislation; litigation; impact of the Company's dividend policy on its future cash flows; credit ratings; capital project funding; 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; and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation, interest rates and the COVID-19 pandemic impact the economies and business environments in which the Company operates and may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected
18

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.
19

ABOUT ENBRIDGE INC.
Enbridge Inc. is a leading North American energy infrastructure company. We safely and reliably deliver the energy people need and want to fuel quality of life. Our core businesses include Liquids Pipelines, which transports approximately 25 percent of the crude oil produced in North America; Gas Transmission and Midstream, which transports approximately 20 percent of the natural gas consumed in the U.S.; Gas Distribution and Storage, which serves approximately 3.8 million retail customers in Ontario and Quebec; and Renewable Power Generation, which owns approximately 1,766 megawatts (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

20

NON-GAAP RECONCILIATIONS APPENDICES
This news release contains references to adjusted EBITDA, adjusted earnings, adjusted earnings per common share and DCF. Management believes the presentation of these metrics gives useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company.
Adjusted EBITDA represents EBITDA adjusted for unusual, infrequent or other non-operating factors on both a consolidated and segmented basis. Management uses adjusted EBITDA to set targets and to assess the performance of the Company and its Business Units.
Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, infrequent or other non-operating factors included in adjusted EBITDA, as well as adjustments for unusual, infrequent or other non-operating factors in respect of depreciation and amortization expense, interest expense, income taxes and noncontrolling interests on a consolidated basis. Management uses adjusted earnings as another measure of the Company’s ability to generate earnings.
DCF is defined as cash flow provided by operating activities before the impact of changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, infrequent or other non-operating factors. Management also uses DCF to assess the performance of the Company and to set its dividend payout target.
Reconciliations of forward-looking non-GAAP financial measures to comparable GAAP measures are not available due to the challenges and impracticability with estimating some of the items, particularly certain contingent liabilities, and non-cash unrealized derivative fair value losses and gains which are subject to market variability. Because of those challenges, a reconciliation of forward-looking non-GAAP financial measures is not available without unreasonable effort.
Our non-GAAP measures described above are not measures that have standardized meaning prescribed by generally accepted accounting principles in the United States of America (U.S. GAAP) and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers.
The tables below provide a reconciliation of the non-GAAP measures to comparable GAAP measures.
21

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

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Liquids Pipelines | 1,673 |  | 2,090 |  |  | 5,756 |  | 5,280 |
Gas Transmission and Midstream | 884 |  | 334 |  |  | 2,725 |  | 230 |
Gas Distribution and Storage | 282 |  | 298 |  |  | 1,374 |  | 1,285 |
Renewable Power Generation | 91 |  | 93 |  |  | 362 |  | 376 |
Energy Services | (204) |  | (34) |  |  | (379) |  | (12) |
Eliminations and Other | (121) |  | 207 |  |  | 191 |  | (498) |
EBITDA | 2,605 |  | 2,988 |  |  | 10,029 |  | 6,661 |
Depreciation and amortization | (944) |  | (935) |  |  | (2,805) |  | (2,766) |
Interest expense | (648) |  | (718) |  |  | (1,923) |  | (2,105) |
Income tax expense | (199) |  | (231) |  |  | (952) |  | (273) |
Earnings attributable to noncontrolling interests | (34) |  | (20) |  |  | (93) |  | (25) |
Preference share dividends | (98) |  | (94) |  |  | (280) |  | (284) |
Earnings attributable to common shareholders | 682 |  | 990 |  |  | 3,976 |  | 1,208 |

ADJUSTED EBITDA TO ADJUSTED EARNINGS

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Liquids Pipelines | 1,898 |  | 1,732 |  |  | 5,623 |  | 5,395 |
Gas Transmission and Midstream | 986 |  | 945 |  |  | 2,928 |  | 3,017 |
Gas Distribution and Storage | 296 |  | 315 |  |  | 1,403 |  | 1,330 |
Renewable Power Generation | 89 |  | 93 |  |  | 356 |  | 361 |
Energy Services | (116) |  | (110) |  |  | (277) |  | (37) |
Eliminations and Other | 116 |  | 22 |  |  | 281 |  | 6 |
Adjusted EBITDA | 3,269 |  | 2,997 |  |  | 10,314 |  | 10,072 |
Depreciation and amortization | (944) |  | (935) |  |  | (2,805) |  | (2,766) |
Interest expense | (654) |  | (708) |  |  | (1,941) |  | (2,099) |
Income tax expense | (355) |  | (278) |  |  | (1,023) |  | (1,133) |
Earnings attributable to noncontrolling interests | (34) |  | (21) |  |  | (90) |  | (28) |
Preference share dividends | (98) |  | (94) |  |  | (280) |  | (284) |
Adjusted earnings | 1,184 |  | 961 |  |  | 4,175 |  | 3,762 |
Adjusted earnings per common share | 0.59 |  | 0.48 |  |  | 2.06 |  | 1.86 |

22

EBITDA TO ADJUSTED EARNINGS

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
EBITDA | 2,605 |  | 2,988 |  |  | 10,029 |  | 6,661 |
Adjusting items: |  |  |  |  |
Change in unrealized derivative fair value (gain)/loss - Foreign exchange | 436 |  | (569) |  |  | (85) |  | 201 |
Change in unrealized derivative fair value (gain)/loss - Commodity prices | 88 |  | (73) |  |  | 102 |  | (24) |
Equity investment impairment | 111 |  | 615 |  |  | 111 |  | 2,351 |
Equity investment asset and goodwill impairment | — |  | — |  |  | — |  | 324 |
Texas Eastern re-establishment of EDIT regulated liability | — |  | — |  |  | — |  | 159 |
Employee severance, transition and transformation costs | 34 |  | 24 |  |  | 106 |  | 303 |
Other | (5) |  | 12 |  |  | 51 |  | 97 |
Total adjusting items | 664 |  | 9 |  |  | 285 |  | 3,411 |
Adjusted EBITDA | 3,269 |  | 2,997 |  |  | 10,314 |  | 10,072 |
Depreciation and amortization | (944) |  | (935) |  |  | (2,805) |  | (2,766) |
Interest expense | (648) |  | (718) |  |  | (1,923) |  | (2,105) |
Income tax expense | (199) |  | (231) |  |  | (952) |  | (273) |
Earnings attributable to noncontrolling interests | (34) |  | (20) |  |  | (93) |  | (25) |
Preference share dividends | (98) |  | (94) |  |  | (280) |  | (284) |
Adjusting items in respect of: |  |  |  |  |
Interest expense | (6) |  | 10 |  |  | (18) |  | 6 |
Income tax expense | (156) |  | (47) |  |  | (71) |  | (860) |
Earnings attributable to noncontrolling interests | — |  | (1) |  |  | 3 |  | (3) |
Adjusted earnings | 1,184 |  | 961 |  |  | 4,175 |  | 3,762 |
Adjusted earnings per common share | 0.59 |  | 0.48 |  |  | 2.06 |  | 1.86 |

23

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

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 1,898 |  | 1,732 |  |  | 5,623 |  | 5,395 |
Change in unrealized derivative fair value gain/(loss) | (222) |  | 360 |  |  | 84 |  | (90) |
Property tax settlement | — |  | — |  |  | 57 |  | — |
Asset write-down loss | — |  | — |  |  | — |  | (13) |
Employee severance, transition and transformation costs | (3) |  | (2) |  |  | (8) |  | (9) |
Other | — |  | — |  |  | — |  | (3) |
Total adjustments | (225) |  | 358 |  |  | 133 |  | (115) |
EBITDA | 1,673 |  | 2,090 |  |  | 5,756 |  | 5,280 |

GAS TRANSMISSION AND MIDSTREAM

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 986 |  | 945 |  |  | 2,928 |  | 3,017 |
Equity investment impairment | (111) |  | (615) |  |  | (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 | (38) |  | (5) |  |  | (104) |  | 26 |
Other | 47 |  | 9 |  |  | 12 |  | 21 |
Total adjustments | (102) |  | (611) |  |  | (203) |  | (2,787) |
EBITDA | 884 |  | 334 |  |  | 2,725 |  | 230 |

GAS DISTRIBUTION AND STORAGE

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 296 |  | 315 |  |  | 1,403 |  | 1,330 |
Change in unrealized derivative fair value gain/(loss) | (2) |  | 11 |  |  | 12 |  | 2 |
Employee transition and transformation costs | (10) |  | (20) |  |  | (38) |  | (35) |
Other | (2) |  | (8) |  |  | (3) |  | (12) |
Total adjustments | (14) |  | (17) |  |  | (29) |  | (45) |
EBITDA | 282 |  | 298 |  |  | 1,374 |  | 1,285 |

24

RENEWABLE POWER GENERATION

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 89 |  | 93 |  |  | 356 |  | 361 |
Change in unrealized derivative fair value gain | 2 |  | — |  |  | 6 |  | 2 |
Disposition - MATL transmission assets | — |  | — |  |  | — |  | 13 |
Total adjustments | 2 |  | — |  |  | 6 |  | 15 |
EBITDA | 91 |  | 93 |  |  | 362 |  | 376 |

ENERGY SERVICES

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | (116) |  | (110) |  |  | (277) |  | (37) |
Change in unrealized derivative fair value gain/(loss) | (88) |  | 73 |  |  | (102) |  | 24 |
Net inventory adjustment | — |  | 3 |  |  | — |  | 1 |
Total adjustments | (88) |  | 76 |  |  | (102) |  | 25 |
EBITDA | (204) |  | (34) |  |  | (379) |  | (12) |

ELIMINATIONS AND OTHER

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 116 |  | 22 |  |  | 281 |  | 6 |
Change in unrealized derivative fair value gain/(loss) | (214) |  | 198 |  |  | (17) |  | (115) |
Change in corporate guarantee obligation | — |  | — |  |  | — |  | (74) |
Investment write-down loss | — |  | — |  |  | — |  | (43) |
Employee severance, transition and transformation costs | (21) |  | (2) |  |  | (60) |  | (259) |
Other | (2) |  | (11) |  |  | (13) |  | (13) |
Total adjustments | (237) |  | 185 |  |  | (90) |  | (504) |
EBITDA | (121) |  | 207 |  |  | 191 |  | (498) |

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

| Three months ended September 30, |  | Nine months ended September 30,
| 2021 | 2020 |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Cash provided by operating activities | 2,163 |  | 2,302 |  |  | 6,954 |  | 7,527 |
Adjusted for changes in operating assets and liabilities 1 | 443 |  | (110) |  |  | 1,068 |  | (213) |
| 2,606 |  | 2,192 |  |  | 8,022 |  | 7,314 |
Distributions to noncontrolling interests 2 | (66) |  | (68) |  |  | (207) |  | (232) |
Preference share dividends | (92) |  | (94) |  |  | (274) |  | (284) |
Maintenance capital expenditures 3 | (142) |  | (256) |  |  | (412) |  | (595) |
Significant adjusting items: |  |  |  |  |
Other receipts of cash not recognized in revenue 4 | 23 |  | 118 |  |  | 74 |  | 250 |
Employee severance, transition and transformation costs | 36 |  | 25 |  |  | 108 |  | 304 |
Distributions from equity investments in excess of cumulative earnings 2 | 52 |  | 159 |  |  | 297 |  | 412 |
Other items | (127) |  | 12 |  |  | (54) |  | 62 |
DCF | 2,290 |  | 2,088 |  |  | 7,554 |  | 7,231 |

1 Changes in operating assets and liabilities, net of recoveries.
2 Presented net of adjusting items.
3 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.
4 Consists of cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements.
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