EX-99.1 2 ei-ex991newsreleasexdocume.htm EX-99.1
NEWS RELEASE
Enbridge Reports Record 2024 Financial Results, Reaffirms 2025 Financial Guidance and Executes on Business Priorities
CALGARY, AB, February 14, 2025 /CNW/ - Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported fourth quarter 2024 financial results, reaffirmed its 2025 financial guidance and provided a quarterly business update.
Highlights
(All financial figures are unaudited and in Canadian dollars unless otherwise noted. * identifies non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.)
•Full-year GAAP earnings of $5.1 billion or $2.34 per common share, compared with GAAP earnings of $5.8 billion or $2.84 per common share in 2023
•Full-year adjusted earnings* of $6.0 billion or $2.80 per common share*, compared with $5.7 billion or $2.79 per common share in 2023
•Full-year adjusted earnings before interest, income taxes and depreciation and amortization (EBITDA)* of $18.6 billion, an increase of 13%, compared with $16.5 billion in 2023
•Full-year cash provided by operating activities of $12.6 billion, compared with $14.2 billion in 2023
•Full-year distributable cash flow (DCF)* of $12.0 billion, an increase of 6%, compared with $11.3 billion in 2023
•Achieved financial guidance for the 19th consecutive year, demonstrating the stability and predictability of Enbridge's business
•Increased the 2025 quarterly dividend by 3.0% to $0.9425 ($3.77 annualized) per share reflecting the 30th consecutive annual increase
•Reached settlements in principle with customers on Algonquin Gas Transmission LLC (Algonquin) and Maritimes & Northeast Pipeline (M&N U.S.)
•Announced a definitive agreement to sell our minority interest in the East-West Tie Limited Partnership for proceeds of $129 million
•Signed a letter of intent with the Government of Alberta to evaluate opportunities to accelerate capacity additions on Enbridge's Liquids Pipelines network
•Placed $5 billion of organic projects into service in 2024 across all four business units
•Sanctioned $8 billion of new organic projects during 2024
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CEO COMMENT
Greg Ebel, President and CEO commented the following:
"2024 has been a historic year for Enbridge. We completed the previously announced $19 billion acquisition of three leading U.S. gas utilities (the Acquisitions), raised our dividend for the 30th consecutive year, and posted record EBITDA and DCF per share marking the 19th straight year that we have met or exceeded our financial guidance. Enbridge's operational and financial performance throughout the year helped deliver a 37% total annual return to investors and 2025 is off to a good start. Our low-risk business model continues to deliver predictable results and stable returns for shareholders and impacts from proposed tariffs on U.S. energy imports are not expected to be to material to Enbridge's financial guidance. I would also like to acknowledge and thank our dedicated and hardworking employees who, once again, delivered for our customers, communities and investors in 2024.
“In Liquids Pipelines, Mainline volumes for 2024 averaged 3.1 million barrels per day, exceeding our guidance assumption, and the system has been in apportionment since November. Western Canadian Sedimentary Basin (WCSB) production growth has expedited customer discussions to expand our Mainline and Express-Platte pipeline systems. In addition, we signed a letter of intent with the Government of Alberta to develop opportunities to accelerate the expansion of our system even further. To the south, our Permian, Mid-Continent and U.S. Gulf Coast systems continue to be highly utilized. In 2024, we moved record volumes through the Enbridge Ingleside Energy Center (EIEC) and the Gray Oak Pipeline. We already have capacity expansions underway on both of these assets, and just recently completed the integration of two additional marine docks purchased at EIEC in 2024. That acquisition is expected to double the number of Very Large Crude Carrier loading windows available at the terminal and strengthen EIEC's position as a premier energy export facility in the Gulf Coast.
“In Gas Transmission, we sanctioned Tennessee Ridgeline, a US$1.1 billion expansion of the East Tennessee Natural Gas system, which will deliver natural gas for the Tennessee Valley Authority to support a 1.5 GW gas generation plant. In Texas, we also announced two accretive investments in the Permian, establishing meaningful equity stakes in the Whistler Pipeline, the ADCC Pipeline, Waha Gas Storage LLC, and the recently sanctioned Blackcomb Pipeline. Also in the Permian, we acquired 15% of the Delaware Basin Residue pipeline system, which is a key supply conduit for the Whistler Pipeline and extends Enbridge's natural gas value chain deeper into the basin. In the Gulf, we sanctioned two sets of projects to serve BP Exploration & Production Company's Kaskida development and Shell and Equinor's Sparta development. These projects are expected to help extend our growth to the end of the decade and are designed to accommodate connections from new discoveries in the area.
“In Gas Distribution, we completed the $19 billion, once-in-a-generation, acquisition of three leading U.S. gas distribution companies. This transaction positions Enbridge as the owner of North America's largest natural gas utility franchise and complements our existing low-risk business model, and each of the utilities is well-positioned to serve growing natural gas demand in North America. As part of the Acquisitions, we've added two larger secured projects to our backlog, both in North Carolina. The first, Moriah Energy Center, is a 2 Bcf liquefied natural gas facility in Person County that will enhance reliability for our growing customer base. The second, the T15 Reliability Project, will connect Enbridge Gas North Carolina to Duke Energy's 1.4 GW Roxboro gas-fired generation power plant. Incrementally, we are actively evaluating opportunities across our entire utility portfolio to service growing power demand.
“In Renewable Power, we capitalized on decreasing solar panel costs and strong demand for renewable Power Purchase Agreements (PPAs) and sanctioned ~1,200 net MW across three projects, all backed by long-term PPAs with Amazon, AT&T and Toyota. All of this capacity is expected to be fully in-service in 2026, with over 200 MW already operating. Short construction windows and favorable tax incentives are
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enabling Enbridge to put highly efficient capital to work to deliver attractive quick-cycle returns. We also continued our track record of regularly recycling capital and announced the sale of our interest in East West Tie Line at a multiple of 17x enterprise value-to-EBITDA (2024).
"Looking ahead, we'll continue to adhere to our long-held capital allocation priorities. A strong balance sheet, growing shareholder returns, and capital discipline govern each strategic decision. Our scale and diversification, in combination with our incumbent footprint and low-risk business model, continue to provide competitive advantages as demand for all forms of North American energy reaches new heights. We'll continue to equity-self fund attractive risk-adjusted conventional and renewable projects. These efforts collectively position the Company for long-term success, making Enbridge a first-choice investment."
FINANCIAL RESULTS SUMMARY
Financial results for the three and twelve months ended December 31, 2024 and 2023 are summarized in the table below:

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars, except per share amounts; number of shares in millions) |  |  |  |  |
GAAP Earnings attributable to common shareholders | 493 |  | 1,726 |  |  | 5,053 |  | 5,839 |
GAAP Earnings per common share | 0.23 |  | 0.81 |  |  | 2.34 |  | 2.84 |
Cash provided by operating activities | 3,662 |  | 3,812 |  |  | 12,600 |  | 14,201 |
Adjusted EBITDA 1 | 5,130 |  | 4,107 |  |  | 18,620 |  | 16,454 |
Adjusted Earnings 1 | 1,640 |  | 1,363 |  |  | 6,037 |  | 5,743 |
Adjusted Earnings per common share 1 | 0.75 |  | 0.64 |  |  | 2.80 |  | 2.79 |
Distributable Cash Flow 1 | 3,074 |  | 2,732 |  |  | 11,991 |  | 11,267 |
Weighted average common shares outstanding | 2,178 |  | 2,126 |  |  | 2,155 |  | 2,056 |

1 Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.
GAAP earnings attributable to common shareholders for the fourth quarter of 2024 decreased by $1.2 billion, or $0.58 per share, compared with the same period in 2023. This decrease was primarily due to non-cash, unrealized changes in the value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks and the absence in 2024 of non-cash gains recognized as a result of the discontinuation of rate-regulated accounting for the Southern Lights Pipeline. These negative impacts were partially offset by lower impairments related to certain capital projects, capital costs and pension balances in the fourth quarter of 2023 as a result of the Ontario Energy Board (OEB) Phase 1 Decision, as well as the quarterly operating performance factors discussed below.
On a full year basis for 2024, GAAP earnings attributable to common shareholders decreased by $786 million due to the same factors discussed above. Those negative impacts were partially offset by a gain on sale related to the disposition of interests in the Alliance Pipeline and Aux Sable and the absence in 2024 of a realized loss due to termination of foreign exchange hedges related to the Competitive Tolling Settlement and the annual operating performance factors discussed below.
The period-over-period comparability of GAAP earnings attributable to common shareholders is impacted by certain unusual, infrequent factors or other non-operating factors which are noted in the reconciliation schedule included in Appendix A of this news release. Refer to the Company's annual Management's
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Discussion & Analysis for 2024 filed in conjunction with the year-end financial statements for a detailed discussion of GAAP financial results.
Adjusted EBITDA in the fourth quarter of 2024 increased by $1.0 billion compared with the same period in 2023. This was due primarily to contributions from the Acquisitions, higher Mainline system tolls from annual escalators, lower Mainline power costs, favorable contracting and lower operating costs on U.S. Gas Transmission assets, higher distribution charges from increases in rates and customer base at Enbridge Gas Ontario, higher renewable contributions from the generation of investment tax credits and the effect of translating U.S. dollar earnings at a higher average exchange rate in 2024, as compared to 2023. These factors were partially offset by lower Mainline throughput and lower uncommitted volumes on Flanagan South Pipeline, and the absence of contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments in April 2024.
Adjusted EBITDA for the year ended December 31, 2024 increased by $2.2 billion compared with the same period in 2023. This was primarily driven by the impact of the operating factors listed above, as well as higher contributions from the Gulf Coast and Mid-Continent System due primarily to higher volumes, the discontinuation of rate-regulated accounting for the Southern Lights Pipeline, the acquisition of an additional 24.25% interest in the Hohe See and Albatros Offshore Wind Facilities in November, 2023 and higher investment income in our Eliminations and Other segment. These factors were partially offset by warmer weather impacting Enbridge Gas Ontario, and lower annualized Mainline tolls as a result of revised tolls effective July 1, 2023 and a lower Line 3 Replacement (L3R) surcharge.
Adjusted earnings in the fourth quarter of 2024 increased by $277 million, or $0.11 per share, compared with the same period in 2023, due to EBITDA factors discussed above, partially offset by higher financing costs and depreciation expense from the Acquisitions and capital investments as well as higher taxes on higher earnings and an increase in U.S. Corporate Alternative Minimum taxes (U.S. minimum tax).
Adjusted earnings for the year ended December 31, 2024 increased by $294 million, or $0.01 per share, compared with the same period in 2023, primarily due to the same factors discussed above for the fourth quarter.
DCF for the fourth quarter of 2024 increased by $342 million compared with the same period in 2023, primarily due to EBITDA factors discussed above, partially offset by higher financing costs and maintenance capital from the Acquisitions and capital investments as well as higher taxes on higher earnings and an increase in U.S. minimum tax.
DCF for the year ended December 31, 2024 increased by $724 million, compared with the same period in 2023, primarily due to the same factors discussed above for the fourth quarter.
Per share metrics in 2024, relative to 2023, are impacted by the prefunding activities for the Acquisitions, including the bought deal equity issuance in the third quarter of 2023 and at-the-market (ATM) issuances in the second quarter of 2024 as part of the financing plan for the Acquisitions.
Detailed financial information and analysis can be found below under Fourth Quarter 2024 Financial Results.
FINANCIAL OUTLOOK
The Company reaffirms its 2025 financial guidance for adjusted EBITDA between $19.4 billion and $20.0 billion and DCF per share between $5.50 and $5.90.
Enbridge expects annualized contributions from the Acquisitions, projects placed into service and acquired during 2024, and the Texas Eastern Transmission, LP (TETLP) rate settlement to drive the majority of growth in 2025.
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Enbridge increased its 2025 quarterly dividend by 3.0% to $0.9425 ($3.77 annualized) per share, commencing with the dividend payable on March 1, 2025 to shareholders of record on February 14, 2025.
The Company also reaffirms its 2023 to 2026 near-term growth outlook of 7-9% for adjusted EBITDA growth, 4-6% for adjusted earnings per share (EPS) growth and approximately 3% for DCF per share growth.
FINANCING UPDATE
Enbridge did not undertake any public debt financings in the fourth quarter of 2024. Enbridge plans to continue financing its secured capital growth program within an equity self-funding model
The company's Debt-to-EBITDA metric at the end of the year was 5.0x. This metric only includes partial year EBITDA from the Acquisitions in 2024 and during the fourth quarter, the impact of the translation of U.S. dollar debt principal was approximately 0.2x. Enbridge expects annualized EBITDA contributions from the Acquisitions to strengthen its debt-to-EBITDA metric towards the midpoint of its 4.5-5.0x target range throughout 2025.
SECURED GROWTH PROJECT EXECUTION UPDATE
Enbridge brought approximately $5 billion of growth projects into service in 2024 across each of its business units, including:
•$1.9 billion of Gas Distribution's Utility Growth Capital across all four utilities
•US$0.5 billion of Gas Transmission's modernization program
•US$0.5 billion Venice Extension project;
•US$0.4 billion Fox Squirrel Solar Phase 2 and 3
•$0.7 billion Fécamp Offshore Wind Project
During the year, Enbridge added approximately $8 billion of new organic growth projects to its backlog, including Tennessee Ridgeline, Canyon System Pipelines, Sparta Pipeline, Orange Grove Solar, Sequoia Solar and another year of Utility Growth and Gas Transmission modernization capital. The secured growth backlog now sits at approximately $26 billion and is underpinned by commercial frameworks consistent with Enbridge's low-risk model.
Financing of the secured growth program is expected to be provided entirely through the Company's anticipated $8-9 billion of annual growth capital investable capacity.
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FOURTH QUARTER BUSINESS UPDATES
Liquids Pipelines: Government of Alberta Letter of Intent
On January 6, 2025, Enbridge signed a Letter of Intent with the Government of Alberta to form a working group, alongside the Alberta Petroleum Marketing Commission to evaluate future egress, transport, storage, terminaling and market access opportunities across Enbridge's pipeline network to accelerate further egress development. Enbridge plans to engage with customers, governments, communities and Indigenous groups as it develops cost effective plans to add incremental egress to its network.
Gas Transmission: Algonquin
In December 2024, Algonquin reached a settlement in principle with customers which will be filed for Federal Energy Regulatory Commission (FERC) approval in the first quarter of 2025. Rates are expected to be effective December 1, 2024.
Gas Transmission: Maritimes & Northeast Pipeline
In December 2024, M&N U.S. reached a settlement in principle with customers which will be filed for FERC approval in the first quarter 2025. Rates are expected to be effective January 1, 2025.
Gas Distribution: Enbridge Gas Ontario Rebasing Phase 2 Update
On November 29, 2024, the OEB issued its Decision approving the Phase 2 Partial Settlement Proposal and accompanying Rate Order that allows for the recovery of 2024 impacts resulting from the Phase 2 settlement through a rate rider that will be effective throughout 2025, and for the establishment of interim 2025 rates effective January 1, 2025.
The Phase 2 Partial Settlement Proposal establishes a harmonized storage cost allocation methodology, the level of Dawn to Corunna Project costs to be included in regulated rates, and cost recovery for utility services provided for unregulated Enbridge Sustain activities. In addition, the Phase 2 Partial Settlement Proposal establishes a price cap incentive regulation rate setting mechanism to be used for establishing rates for 2025 to 2028. Interim 2025 rates approved as part of the Rate Order reflect application of this mechanism.
Issues not addressed as part of the Phase 2 Settlement Proposal include an intervenor proposal to decouple revenues from customer numbers, the appropriate meter reading performance metric, and the terms for including renewable natural gas as part of gas supply. 2024 and 2025 rates have been classified as interim pending the OEB decision on outstanding Phase 2 issues and the resolution of the Notice of Appeal and Amended Notice of Motion on Phase 1. Enbridge expects a decision on the Phase 2 unresolved issues in the first half of 2025.
Renewable Power: East-West Tie Line
Enbridge announced a definitive agreement to sell its 24% interest in the East-West Tie Limited Partnership to Hydro One Limited for cash proceeds of $0.1 billion. East-West Tie Limited Partnership owns the East-West Tie Line, a 450-kilometre, 230 kV double-circuit transmission line, regulated by the OEB, spanning from Wawa to Thunder Bay, Ontario, along the north shore of Lake Superior. The sale is expected to close in the first half of 2025.
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FOURTH QUARTER AND ANNUAL 2024 FINANCIAL RESULTS
GAAP Segment EBITDA and Cash Flow from Operations

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Liquids Pipelines | 2,352 |  | 2,439 |  |  | 9,531 |  | 9,383 |
Gas Transmission | 1,150 |  | 1,044 |  |  | 5,656 |  | 4,264 |
Gas Distribution and Storage | 1,015 |  | 238 |  |  | 2,869 |  | 1,592 |
Renewable Power Generation | 236 |  | (146) |  |  | 733 |  | 149 |
Eliminations and Other | (1,402) |  | 926 |  |  | (1,904) |  | 916 |
EBITDA 1 | 3,351 |  | 4,501 |  |  | 16,885 |  | 16,304 |
Earnings attributable to common shareholders | 493 |  | 1,726 |  |  | 5,053 |  | 5,839 |
Cash provided by operating activities | 3,662 |  | 3,812 |  |  | 12,600 |  | 14,201 |

1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
For purposes of evaluating performance, the Company makes adjustments to GAAP reported earnings, segment EBITDA and cash flow provided by operating activities for unusual, infrequent or other non-operating factors, which allow management and investors to more accurately compare the Company’s performance across periods, normalizing for factors that are not indicative of underlying business performance. Tables incorporating these adjustments follow below. Schedules reconciling EBITDA, adjusted EBITDA, adjusted EBITDA by segment, adjusted earnings, adjusted earnings per share and DCF to their closest GAAP equivalent are provided in the Appendices to this news release.
Adjusted EBITDA By Segment
Adjusted EBITDA generated from U.S. dollar denominated businesses was translated to Canadian dollars a t a higher average exchange rates (C$1.40/US$) i n the fourth quarter of 2024 when compared with the same quarter in 2023 (C$1.36/US$). On a full year basis, adjusted EBITDA generated from U.S. dollar denominated businesses was translated at C$1.37/US$, compared with $C1.35/US$ in 2023. A significant portion of U.S. dollar earnings are hedged under the Company's enterprise-wide financial risk management program. The hedge settlements are reported within Eliminations and Other.
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Liquids Pipelines

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Mainline System | 1,339 |  | 1,300 |  |  | 5,342 |  | 5,396 |
Regional Oil Sands System | 232 |  | 228 |  |  | 925 |  | 954 |
Gulf Coast and Mid-Continent Systems 1 | 369 |  | 442 |  |  | 1,596 |  | 1,582 |
Other Systems 2 | 455 |  | 395 |  |  | 1,791 |  | 1,503 |
Adjusted EBITDA 3 | 2,395 |  | 2,365 |  |  | 9,654 |  | 9,435 |
Operating Data (average deliveries – thousands of bpd) |  |  |  |  |
Mainline System volume 4 | 3,079 |  | 3,212 |  |  | 3,061 |  | 3,080 |
Canadian International Joint Tariff 5 ($C) | $1.75 |  | $1.65 |  |  | $1.70 |  | $1.65 |
U.S. International Joint Tariff 5 ($US) | $2.59 |  | $2.57 |  |  | $2.58 |  | $2.57 |
Line 3 Replacement Surcharge 6 ($US) | $0.76 |  | $0.77 |  |  | $0.76 |  | $0.77 |

1 Consists of Flanagan South Pipeline, Seaway Pipeline, Gray Oak Pipeline, Cactus II Pipeline, EIEC, and others.
2 Other consists of Southern Lights Pipeline, Express-Platte System, Bakken System, and others.
3 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
4 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.
5 Tariff tolls, per barrel, for heavy crude oil movements from Hardisty, AB to Chicago, IL. Effective July 1, 2023 the Company began collecting a dual currency, international joint tariff set within the negotiated settlement for tolls on the Mainline System. Excludes abandonment surcharge.
6 Effective July 1, 2022, the Line 3 Replacement Surcharge (L3R), exclusive of the receipt terminalling surcharge, is determined on a monthly basis by a volume ratchet based on the 9-month rolling average of ex-Gretna volumes. Each 50 kbpd volume ratchet above 2,835 kbpd (up to 3,085 kbpd) applies a US$0.035/bbl discount whereas each 50 kbpd volume ratchet below 2,350 kbpd (down to 2,050 kbpd) adds a US$0.04/bbl charge. Refer to Enbridge’s Application for a Toll Order respecting the implementation of the L3R Surcharges and CER Order TO-003-2021 for further details.
Liquids Pipelines adjusted EBITDA increased $30 million compared with the fourth quarter of 2023, primarily related to:
•higher Mainline System tolls from annual escalators, effective July 1, 2024 and lower Mainline power costs from operational efficiencies;
•higher contributions from Southern Lights Pipeline due primarily to the discontinuation of rate-regulated accounting as at December 31, 2023; and
•the favorable effect of translating U.S. dollar earnings at a higher average exchange rate in 2024, as compared to 2023; partially offset by
•lower Mainline volumes; and
•lower uncommitted volumes on Flanagan South Pipeline.
Full year 2024 Liquids Pipelines adjusted EBITDA increased by $219 million compared with 2023 and was primarily impacted by the same factors discussed above as well as:
•higher contributions from the Gulf Coast and Mid-Continent System due primarily to higher volumes on the Flanagan South Pipeline driven by the open season commitments that commenced in the first quarter of 2024, and EIEC due to higher demand and new storage contracts that commenced in the second quarter of 2024, partially offset by
•full year of lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower L3R surcharge.
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Gas Transmission

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
U.S. Gas Transmission | 1,009 |  | 833 |  |  | 3,795 |  | 3,433 |
Canadian Gas Transmission | 157 | 182 |  |  | 552 |  | 640 |
Other 1 | 106 | 69 |  |  | 435 | 325 |
Adjusted EBITDA 2 | 1,272 |  | 1,084 |  |  | 4,782 |  | 4,398 |

1 Other consists of Tomorrow RNG, Gulf Offshore assets, our investment in DCP Midstream, and others.
2 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
•
Gas Transmission adjusted EBITDA increased $188 million compared with the fourth quarter of 2023, primarily related to:
•contributions from the acquisitions of Aitken Creek Gas Storage in the fourth quarter of 2023, Tomorrow RNG in the first quarter of 2024, and Whistler Parent LLC in the second quarter of 2024;
•favorable contracting and lower operating costs on our U.S. Gas Transmission assets;
•contributions from the TETLP rate settlement, effective October 1, 2024; and
•the favorable effect of translating U.S. dollar earnings at a higher average exchange rate in 2024, compared to the same period in 2023; partially offset by
•lower contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments in April 2024.
Full year 2024 Gas Transmission adjusted EBITDA increased $384 million compared with 2023 and was primarily impacted by the same factors discussed above as well as:
•contributions from the acquisition of Tres Palacios in the second quarter of 2023.
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Gas Distribution and Storage

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Enbridge Gas Ontario 1 | 502 |  | 503 |  |  | 1,872 |  | 1,825 |
U.S. Gas Utilities 1 | 502 |  | — |  |  | 947 |  | — |
Other | 11 |  | 16 |  |  | 50 |  | 48 |
Adjusted EBITDA 2 | 1,015 |  | 519 |  |  | 2,869 |  | 1,873 |
Operating Data |  |  |  |  |
Enbridge Gas Ontario |  |  |  |  |
Volumes (billions of cubic feet) | 532 |  | 620 |  |  | 1,946 |  | 2,218 |
Number of active customers 3 (millions) | 3.9 |  | 3.9 |  |  | 3.9 |  | 3.9 |
Heating degree days 4 |  |  |  |  |
Actual | 927 |  | 1,152 |  |  | 2,546 |  | 3,418 |
Forecast based on normal weather 5 | 1,008 |  | 1,286 |  |  | 2,958 |  | 3,781 |

1 Enbridge Gas Inc. doing business as Enbridge Gas Ontario. U.S. Gas Utilities consist of East Ohio Gas (doing business as Enbridge Gas Ohio), Questar (Doing business as Enbridge Gas Utah) and PSNC (doing business as Enbridge Gas North Carolina).
2 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
3 Number of active customers is the number of natural gas consuming customers at the end of the reported period.
4 Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in Enbridge Gas Ontario's distribution franchise areas.
5 Normal weather is the weather forecast by Enbridge Gas Ontario in its legacy rate zones, using the forecasting methodologies approved by the OEB.
Adjusted EBITDA for Enbridge Gas Ontario, Enbridge Gas Utah and Enbridge Gas North Carolina typically follows a seasonal profile. EBITDA is generally highest in the first and fourth quarters of the year. Seasonal profiles for Enbridge Gas Ontario, Enbridge Gas Utah and Enbridge Gas North Carolina reflect greater volumetric demand during the heating season and the magnitude of the seasonal adjusted EBITDA fluctuations will vary from year-to-year in Ontario reflecting the impact of colder or warmer than normal weather on distribution volumes. Enbridge Gas Ohio's earnings are largely decoupled from volumes and less impacted by weather fluctuations. Enbridge Gas Utah and Enbridge Gas North Carolina have revenue decoupling mechanisms that are not impacted by weather or gas volume variability, but revenues are shaped to align with the seasonal usage profile. Enbridge Gas Ontario revenue can be affected by weather variability.
Adjusted EBITDA for the fourth quarter increased $496 million compared with the fourth quarter of 2023 primarily related to:
•contributions from the Enbridge Gas Ohio, Enbridge Gas Utah and Enbridge Gas North Carolina acquisitions in 2024; and
•higher distribution charges resulting from increases in rates and customer base, and higher demand in the contract market at Enbridge Gas Ontario; partially offset by
•the absence of favorable timing of operating costs present in the fourth quarter of 2023.
When compared with the normal forecast embedded in rates, the negative impact of weather for Enbridge Gas Ontario was approximately $23 million in the fourth quarter of 2024 compared to a negative impact of approximately $29 million in the fourth quarter of 2023.
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Full year 2024 Gas Distribution and Storage adjusted EBITDA increased by $996 million compared with 2023 and was primarily impacted by the same factors discussed above, as well as, warmer than normal weather in 2024 which negatively impacted 2024 Enbridge Gas Ontario EBITDA by approximately $58 million year over year.
When compared with the normal forecast embedded in rates, the negative impact of weather for Enbridge Gas Ontario was approximately $129 million in 2024 compared to a negative impact of approximately $71 million in 2023.
Renewable Power Generation

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA 1 | 308 |  | 141 |  |  | 820 |  | 531 |

1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
Renewable Power Generation adjusted EBITDA increased $167 million compared with the fourth quarter of 2023 primarily related to:
•higher contributions from our investment in Fox Squirrel Solar as a result of the generation of investment tax credits; and
•higher contributions from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities.
Full year 2024 Renewable Power Generation adjusted EBITDA increase d $289 million and was primarily impacted by the same factors discussed above as well as:
•strong wind resources at European offshore wind facilities, partially offset by
•the absence in 2024 of fees earned on certain wind and solar development contracts.
Eliminations and Other

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Operating and administrative recoveries | 206 |  | 17 |  |  | 587 |  | 158 |
Realized foreign exchange hedge settlement (loss)/gain | (66) |  | (19) |  |  | (92) |  | 59 |
Adjusted EBITDA 1 | 140 |  | (2) |  |  | 495 |  | 217 |

1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
Operating and administrative recoveries captured in this segment reflect the cost of centrally delivered services (including depreciation of corporate assets) inclusive of amounts recovered from business units for the provision of those services. U.S. dollar denominated earnings within operating segment results are translated at average foreign exchange rates during the quarter, and the impact of settlements made under the Company's enterprise foreign exchange hedging program are captured in this corporate segment.
Eliminations and Other adjusted EBITDA increased $142 million compared with the fourth quarter of 2023 due to:
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•higher investment income from elevated cash balances and from our wholly-owned captive insurance subsidiary; and
•lower operating costs; partially offset by
•higher realized foreign exchange loss on hedge settlements in 2024.
Full year 2024 Eliminations and Other adjusted EBITDA increased $278 million compared with 2023 due to the same factors discussed above as well as higher investment income from the pre-funding of the Acquisitions.
Distributable Cash Flow

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars; number of shares in millions) |  |  |  |  |
Liquids Pipelines | 2,395 |  | 2,365 |  |  | 9,654 |  | 9,435 |
Gas Transmission | 1,272 |  | 1,084 |  |  | 4,782 |  | 4,398 |
Gas Distribution and Storage | 1,015 |  | 519 |  |  | 2,869 |  | 1,873 |
Renewable Power Generation | 308 |  | 141 |  |  | 820 |  | 531 |
Eliminations and Other | 140 |  | (2) |  |  | 495 |  | 217 |
Adjusted EBITDA 1,3 | 5,130 |  | 4,107 |  |  | 18,620 |  | 16,454 |
Maintenance capital | (370) |  | (270) |  |  | (1,118) |  | (918) |
Interest expense 1 | (1,247) |  | (969) |  |  | (4,475) |  | (3,728) |
Current income tax 1 | (278) |  | (166) |  |  | (875) |  | (561) |
Distributions to noncontrolling interests 1 | (88) |  | (81) |  |  | (333) |  | (363) |
Cash distributions in excess of equity earnings 1 | 47 |  | 149 |  |  | 394 |  | 464 |
Preference share dividends 1 | (101) |  | (92) |  |  | (388) |  | (352) |
Other receipts of cash not recognized in revenue 2 | 8 |  | 37 |  |  | 97 |  | 210 |
Other non-cash adjustments | (27) |  | 17 |  |  | 69 |  | 61 |
DCF 3 | 3,074 |  | 2,732 |  |  | 11,991 |  | 11,267 |
Weighted average common shares outstanding 4 | 2,178 |  | 2,126 |  |  | 2,155 |  | 2,056 |

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.
4 Includes equity pre-funding for the Acquisitions which closed in 2024.
Fourth quarter 2024 DCF increased $342 million compared with the same period of 2023 primarily due to operational factors discussed above contributing to higher adjusted EBITDA, partially offset by:
•higher debt principal mainly attributable to the Acquisitions and higher average rates, resulting in higher interest expense;
•higher U.S. minimum tax;
•lower net distributions in excess of equity earnings for the quarter; and
•higher maintenance capital from the Acquisitions.
Full year 2024 DCF increased $724 million compared with 2023 results primarily due to the same factors discussed above.
12

Adjusted Earnings

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Adjusted EBITDA 1,2 | 5,130 |  | 4,107 |  |  | 18,620 |  | 16,454 |
Depreciation and amortization | (1,434) |  | (1,208) |  |  | (5,353) |  | (4,762) |
Interest expense 2 | (1,273) |  | (957) |  |  | (4,534) |  | (3,700) |
Income taxes 2 | (630) |  | (469) |  |  | (2,120) |  | (1,721) |
Noncontrolling interests 2 | (52) |  | (18) |  |  | (188) |  | (176) |
Preference share dividends | (101) |  | (92) |  |  | (388) |  | (352) |
Adjusted earnings 1 | 1,640 |  | 1,363 |  |  | 6,037 |  | 5,743 |
Adjusted earnings per common share 1 | 0.75 |  | 0.64 |  |  | 2.80 |  | 2.79 |

1 Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.
2 Presented net of adjusting items.
Adjusted earnings increased $277 million and adjusted earnings per share increased by $0.11 when compared with the fourth quarter in 2023 primarily due to higher adjusted EBITDA driven by operational factors discussed above, partially offset by:
•higher debt principal mainly attributable to the Acquisitions and higher average rates, resulting in higher interest expense;
•higher depreciation from assets acquired or placed into service since the fourth quarter of 2023; and
•higher income taxes due to higher earnings and higher US minimum tax.
Full year adjusted earnings increased $294 million and adjusted earnings per share increased $0.01 compared with 2023 due to the factors discussed above as well as, higher depreciation on assets acquired or placed into service beginning January 1, 2023.
Per share metrics were negatively impacted by the bought deal equity issuance in the third quarter of 2023 and ATM issuances in the second quarter of 2024, as part of the funding for the Acquisitions.
CONFERENCE CALL
Enbridge will host a conference call and webcast on February 14, 2025 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide a business update and review 2024 fourth quarter results. Analysts, members of the media and other interested parties can access the call toll free at 1-800-606-3040. The call will be audio webcast live at https://events.q4inc.com/attendee/980600506. It is recommended that participants dial in or join the audio webcast fifteen minutes prior to the scheduled start time. A webcast replay will be available soon after the conclusion of the event and a transcript will be posted to the website. The replay will be available for seven days after the call toll-free 1-(800)-606-3040 (conference ID: 9581867).
The conference call format will include prepared remarks from the executive team followed by a question and answer session for the analyst and investor community only. Enbridge’s media and investor relations teams will be available after the call for any additional questions.
13

DIVIDEND DECLARATION
On December 2, 2024, our Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2025 to shareholders of record on February 14, 2025.

| Dividend per share |
(Canadian dollars unless otherwise stated) |  |
Common Shares 1 | $0.94250 |  |
Preference Shares, Series A | $0.34375 |
Preference Shares, Series B | $0.32513 |
Preference Shares, Series D | $0.33825 |
Preference Shares, Series F | $0.34613 |
Preference Shares, Series G 2 | $0.37911 |
Preference Shares, Series H | $0.38200 |
Preference Shares, Series I 3 | $0.35507 |
Preference Shares, Series L | US$0.36612 |
Preference Shares, Series N | $0.41850 |
Preference Shares, Series P | $0.36988 |
Preference Shares, Series R | $0.39463 |
Preference Shares, Series 1 | US$0.41898 |
Preference Shares, Series 3 | $0.33050 |
Preference Shares, Series 4 4 | $0.37110 |
Preference Shares, Series 5 | US$0.41769 |
Preference Shares, Series 7 | $0.37425 |
Preference Shares, Series 9 5 | $0.35450 |
Preference Shares, Series 11 | $0.24613 |
Preference Shares, Series 13 | $0.19019 |
Preference Shares, Series 15 | $0.18644 |
Preference Shares, Series 19 | $0.38825 |

1 The quarterly dividend per common share was increased 3% to $0.9425 from $0.9150, effective March 1, 2025.
2 The quarterly dividend per share paid on Preference Shares, Series G was decreased to $0.37911 from $0.43014 on December 1, 2024 due to reset on a quarterly basis.
3 The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.35507 from $0.40589 on December 1, 2024 due to reset on a quarterly basis.
4 The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to $0.37110 from $0.42206 on December 1, 2024 due to reset on a quarterly basis.
5 The quarterly dividend per share paid on Preference Shares, Series 9 was increased to $0.35450 from $0.25606 on December 1, 2024 due to reset on an annual basis.
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FORWARD-LOOKING INFORMATION
Forward-looking information, or forward-looking statements, have been included in this news release to provide information about Enbridge and its subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: Enbridge’s corporate vision and strategy, including our strategic priorities and outlook; 2024 financial guidance and near term outlook, including projected DCF per share and adjusted EBITDA and expected growth thereof; expected dividends, dividend growth and dividend policy; the anticipated benefits of the acquisitions of three natural gas utilities from Dominion Energy, Inc. (the Acquisitions) and the expected integration thereof; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas liquids (NGL), liquefied natural gas (LNG), renewable natural gas (RNG) and renewable energy; anticipated utilization of our assets; expected EBITDA and adjusted EBITDA; expected earnings/(loss) and adjusted earnings/(loss); expected DCF and DCF per share; expected future cash flows; expected shareholder returns and asset returns; expected performance of Enbridge’s businesses; financial strength and flexibility; financing costs and plans, including with respect to the Acquisitions and our equity self-funding model; expectations on leverage, including Debt-to EBITDA ratio; sources of liquidity and sufficiency of financial resources; expected in-service dates and costs related to announced projects and projects under construction; capital allocation framework and priorities; impact of weather and seasonality; expected future growth and expansion opportunities, including secured growth program, development opportunities, customer growth, and lower carbon opportunities and strategy, including with respect to the projects; expected closings, benefits, accretion and timing of transactions, including with respect to the agreement to sell our interest in the East-West Tie Limited Partnership; 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 Enbridge Gas Inc. rebasing phase 2, and anticipated timing and impact therefrom.
Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, NGL, LNG, RNG and renewable energy; prices of crude oil, natural gas, NGL, LNG, RNG and renewable energy; anticipated utilization of our assets; exchange rates; inflation; interest rates; availability and price of labour and construction materials; the stability of our supply chain; operational reliability and performance; maintenance of support and regulatory approvals for our projects, toll and rate applications; anticipated in-service dates; weather; announced and potential acquisition, disposition and other corporate transactions and projects and the timing and benefits thereof; governmental legislation; litigation; credit ratings; hedging program; expected EBITDA and adjusted EBITDA; expected earnings/ (loss) and adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected future DCF and DCF per share; estimated future dividends; financial strength and flexibility; debt and equity market conditions; and general economic and competitive conditions. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL, LNG, RNG and renewable energy and the prices of these commodities are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs and are therefore inherent in all forward-looking statements. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and construction materials; the stability of our supply chain; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest
15

rates on borrowing costs; the impact of weather; the timing and closing of acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.
Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities; operating performance; regulatory parameters and decisions; litigation; acquisitions and dispositions and other transactions, and the realization of anticipated benefits therefrom, including the Acquisitions; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; global geopolitical conditions; political decisions; public opinion; dividend policy; changes in tax laws and tax rates; exchange rates; interest rates; inflation; commodity prices; and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this news release and in Enbridge’s other filings with Canadian and U.S. securities regulators. The impact of any one assumption, risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty, as these are interdependent, and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statement made in this news release or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.
16

ABOUT ENBRIDGE INC.
At Enbridge, we safely connect millions of people to the energy they rely on every day, fueling quality of life through our North American natural gas, oil and renewable power networks and our growing European offshore wind portfolio. We're investing in modern energy delivery infrastructure to sustain access to secure, affordable energy and building on more than a century of operating conventional energy infrastructure and two decades of experience in renewable power. We're advancing new technologies including hydrogen, renewable natural gas, carbon capture and storage. Headquartered in Calgary, Alberta, Enbridge's common shares trade under the symbol ENB on the Toronto (TSX) and New York (NYSE) stock exchanges. To learn more, visit us at enbridge.com.
None of the information contained in, or connected to, Enbridge’s website is incorporated in or otherwise forms part of this news release.

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

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NON-GAAP RECONCILIATIONS APPENDICES
This news release contains references to EBITDA, adjusted EBITDA, adjusted earnings, adjusted earnings per common share and DCF per share. 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 and uses EPS to assess performance of the Company.
DCF is defined as cash flow provided by operating activities before the impact of changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests, preference share dividends and maintenance capital expenditures and further adjusted for unusual, infrequent or other non-operating factors. Management also uses DCF to assess the performance of the Company and to set its dividend payout target.
This news release also contains references to Debt-to-EBITDA, a non-GAAP ratio which utilizes adjusted EBITDA as one of its components. Debt-to-EBITDA is used as a liquidity measure to indicate the amount of adjusted earnings to pay debt, as calculated on the basis of generally accepted accounting principles in the United States of America (U.S. GAAP), before covering interest, tax, depreciation and amortization.
Reconciliations of forward-looking non-GAAP financial measures and non-GAAP ratios to comparable
GAAP measures are not available due to the challenges and impracticability of estimating certain items, particularly certain contingent liabilities and non-cash unrealized derivative fair value losses and gains
subject to market variability. Because of those challenges, a reconciliation of forward-looking non-GAAP financial measures and non-GAAP ratios is not available without unreasonable effort.
Our non-GAAP financial measures and non-GAAP ratios described above are not measures that have standardized meaning prescribed by U.S. GAAP and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers.
The tables below provide a reconciliation of the non-GAAP measures to comparable GAAP measures.
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APPENDIX A
NON-GAAP RECONCILIATIONS – ADJUSTED EBITDA AND ADJUSTED EARNINGS
CONSOLIDATED EARNINGS

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Liquids Pipelines | 2,352 | 2,439 |  |  | 9,531 |  | 9,383 |
Gas Transmission | 1,150 | 1,044 |  |  | 5,656 |  | 4,264 |
Gas Distribution and Storage | 1,015 | 238 |  |  | 2,869 |  | 1,592 |
Renewable Power Generation | 236 | (146) |  |  | 733 |  | 149 |
Eliminations and Other | (1,402) |  | 926 |  |  | (1,904) |  | 916 |
EBITDA | 3,351 |  | 4,501 |  |  | 16,885 |  | 16,304 |
Depreciation and amortization | (1,384) |  | (1,166) |  |  | (5,167) |  | (4,613) |
Interest expense | (1,118) |  | (1,103) |  |  | (4,419) |  | (3,812) |
Income tax expense | (231) |  | (664) |  |  | (1,668) |  | (1,821) |
(Earnings)/loss attributable to noncontrolling interests | (23) |  | 250 |  |  | (190) |  | 133 |
Preference share dividends | (102) |  | (92) |  |  | (388) |  | (352) |
Earnings attributable to common shareholders | 493 |  | 1,726 |  |  | 5,053 |  | 5,839 |

ADJUSTED EBITDA TO ADJUSTED EARNINGS

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Liquids Pipelines | 2,395 |  | 2,365 |  |  | 9,654 |  | 9,435 |
Gas Transmission | 1,272 |  | 1,084 |  |  | 4,782 |  | 4,398 |
Gas Distribution and Storage | 1,015 |  | 519 |  |  | 2,869 |  | 1,873 |
Renewable Power Generation | 308 |  | 141 |  |  | 820 |  | 531 |
Eliminations and Other | 140 |  | (2) |  |  | 495 |  | 217 |
Adjusted EBITDA | 5,130 |  | 4,107 |  |  | 18,620 |  | 16,454 |
Depreciation and amortization | (1,434) |  | (1,208) |  |  | (5,353) |  | (4,762) |
Interest expense | (1,273) |  | (957) |  |  | (4,534) |  | (3,700) |
Income tax expense | (630) |  | (469) |  |  | (2,120) |  | (1,721) |
Earnings attributable to noncontrolling interests | (52) |  | (18) |  |  | (188) |  | (176) |
Preference share dividends | (101) |  | (92) |  |  | (388) |  | (352) |
Adjusted earnings | 1,640 |  | 1,363 |  |  | 6,037 |  | 5,743 |
Adjusted earnings per common share | 0.75 |  | 0.64 |  |  | 2.80 |  | 2.79 |

19

EBITDA TO ADJUSTED EARNINGS

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
EBITDA | 3,351 |  | 4,501 |  |  | 16,885 |  | 16,304 |
Adjusting items: |  |  |  |  |
Change in unrealized derivative fair value (gain)/loss | 1,433 |  | (1,012) |  |  | 2,175 |  | (1,255) |
Employee severance costs | — |  | — |  |  | 105 |  | — |
Competitive Toll Settlement realized hedge loss | — |  | — |  |  | — |  | 638 |
Net gain on sale | — |  | — |  |  | (1,092) |  | — |
Assets impairment | 192 |  | 732 |  |  | 192 |  | 732 |
Litigation provisions and settlements | — |  | — |  |  | — |  | 56 |
Southern Lights regulatory accounting discontinuation | — |  | (151) |  |  | — |  | (151) |
Other | 154 |  | 37 |  |  | 355 |  | 130 |
Total adjusting items | 1,779 |  | (394) |  |  | 1,735 |  | 150 |
Adjusted EBITDA | 5,130 |  | 4,107 |  |  | 18,620 |  | 16,454 |
Depreciation and amortization | (1,384) |  | (1,166) |  |  | (5,167) |  | (4,613) |
Interest expense | (1,121) |  | (1,103) |  |  | (4,419) |  | (3,812) |
Income tax expense | (231) |  | (664) |  |  | (1,668) |  | (1,821) |
Earnings attributable to noncontrolling interests | (23) |  | 250 |  |  | (190) |  | 133 |
Preference share dividends | (101) |  | (92) |  |  | (388) |  | (352) |
Adjusting items in respect of: |  |  |  |  |
Depreciation and amortization | (50) |  | (42) |  |  | (186) |  | (149) |
Interest expense | (152) |  | 146 |  |  | (115) |  | 112 |
Income tax expense | (399) |  | 195 |  |  | (452) |  | 100 |
Earnings attributable to noncontrolling interests | (29) |  | (268) |  |  | 2 |  | (309) |
Adjusted earnings | 1,640 |  | 1,363 |  |  | 6,037 |  | 5,743 |
Adjusted earnings per common share | 0.75 |  | 0.64 |  |  | 2.80 |  | 2.79 |

20

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

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 2,395 |  | 2,365 |  |  | 9,654 |  | 9,435 |
Change in unrealized derivative fair value gain/(loss) | (18) |  | 60 |  |  | 2 |  | 615 |
CTS realized hedge loss | — |  | — |  |  | — |  | (638) |
Southern Lights regulatory accounting discontinuation | — |  | 151 |  |  | — |  | 151 |
Assets impairment | — |  | (86) |  |  | — |  | (86) |
Litigation settlement gain | — |  | — |  |  | — |  | 68 |
Other | (25) |  | (51) |  |  | (125) |  | (162) |
Total adjustments | (43) |  | 74 |  |  | (123) |  | (52) |
EBITDA | 2,352 |  | 2,439 |  |  | 9,531 |  | 9,383 |

GAS TRANSMISSION

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 1,272 |  | 1,084 |  |  | 4,782 |  | 4,398 |
Change in unrealized derivative fair value gain/(loss) - Commodity prices | 1 |  | 34 |  |  | (3) |  | 32 |
Gain on sale of Alliance and Aux Sable | — |  | — |  |  | 1,063 |  | — |
Assets impairment | (137) |  | (82) |  |  | (137) |  | (82) |
Litigation provision | — |  | — |  |  | — |  | (124) |
Other | 14 |  | 8 |  |  | (49) |  | 40 |
Total adjustments | (122) |  | (40) |  |  | 874 |  | (134) |
EBITDA | 1,150 |  | 1,044 |  |  | 5,656 |  | 4,264 |

GAS DISTRIBUTION AND STORAGE

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 1,015 |  | 519 |  |  | 2,869 |  | 1,873 |
Assets impairment | — |  | (281) |  |  | — |  | (281) |
Total adjustments | — |  | (281) |  |  | — |  | (281) |
EBITDA | 1,015 |  | 238 |  |  | 2,869 |  | 1,592 |

21

RENEWABLE POWER GENERATION

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 308 |  | 141 |  |  | 820 |  | 531 |
Change in unrealized derivative fair value gain/(loss) - Commodity prices | (7) |  | 4 |  |  | (20) |  | (80) |
Assets impairment | (55) |  | (283) |  |  | (55) |  | (283) |
Gain on sale of NR Green | — |  | — |  |  | 29 |  | — |
Other | (10) |  | (8) |  |  | (41) |  | (19) |
Total adjustments | (72) |  | (287) |  |  | (87) |  | (382) |
EBITDA | 236 |  | (146) |  |  | 733 |  | 149 |

ELIMINATIONS AND OTHER

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 140 |  | (2) |  |  | 495 |  | 217 |
Change in unrealized derivative fair value gain/(loss) - Foreign exchange | (1,316) |  | 873 |  |  | (2,032) |  | 623 |
Employee severance costs | — |  | — |  |  | (105) |  | — |
Other | (226) |  | 55 |  |  | (262) |  | 76 |
Total adjustments | (1,542) |  | 928 |  |  | (2,399) |  | 699 |
EBITDA | (1,402) |  | 926 |  |  | (1,904) |  | 916 |

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

| Three months ended December 31, |  | Twelve months ended December 31,
| 2024 | 2023 |  | 2024 | 2023
(unaudited; millions of Canadian dollars) |  |  |  |  |
Cash provided by operating activities | 3,662 |  | 3,812 |  |  | 12,600 |  | 14,201 |
Adjusted for changes in operating assets and liabilities 1 | (219) |  | (850) |  |  | 133 |  | (2,311) |
| 3,443 |  | 2,962 |  |  | 12,733 |  | 11,890 |
Distributions to noncontrolling interests 2 | (88) |  | (81) |  |  | (333) |  | (363) |
Preference share dividends 2 | (101) |  | (92) |  |  | (388) |  | (352) |
Maintenance capital | (370) |  | (270) |  |  | (1,118) |  | (918) |
Significant adjusting items: |  |  |  |  |
Other receipts of cash not recognized in revenue | 8 |  | 37 |  |  | 97 |  | 210 |
Employee severance costs, net of tax | — |  | — |  |  | 95 |  | — |
Distributions from equity investments in excess of cumulative earnings 2 | 151 |  | 296 |  |  | 801 |  | 639 |
CTS realized hedge loss, net of tax | — |  | — |  |  | — |  | 479 |
Litigation settlement gain | — |  | — |  |  | — |  | (68) |
Other items | 31 |  | (120) |  |  | 104 |  | (250) |
DCF | 3,074 |  | 2,732 |  |  | 11,991 |  | 11,267 |

1 Changes in operating assets and liabilities, net of recoveries.
2 Presented net of adjusting items.
23