ENBRIDGE INC
For the period ended Dec 31, 2025. Filed Feb 13, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 13, 2026
ENB$46.89-2.5%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-14.
0000895728-25-000006
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-13.
0001193125-26-049810
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 360 previous paragraphs and 326 current paragraphs.
99 unchanged; 110 reworded; 107 added; 145 removed; 6 previous and 10 current paragraphs rearranged.
Tables are not compared: 18 previous and 18 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (107)
Current report
LIQUIDS PIPELINES INVESTMENT
Current report
Mainline System Capital Investment
Current report
In 2025, we announced plans to invest up to US$1.3 billion in our Mainline System through 2028. These investments are expected to earn a return through the Mainline Tolling Settlement and will be focused on extending the service life of the underlying assets, as well as further enhancing reliability and efficiency given continuing demands on the system.
Current report
NONCONTROLLING INTEREST INVESTMENT
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BC Pipeline System
Current report
On July 2, 2025, Stonlasec8 Indigenous Investments Limited Partnership (the First Nations Partnership), an entity representing 38 First Nations in British Columbia (BC), invested approximately $736 million in our Westcoast Energy Inc. BC natural gas pipeline system.
Current report
As at December 31, 2025, we own 87.53% of the BC Pipeline system, which is included in our Gas Transmission segment, and continue to manage and operate the pipeline system. The First Nations Partnership owns the remaining 12.47% interest.
Current report
Algonquin Gas Transmission, LLC (Algonquin) filed a rate case on May 30, 2024 and a settlement in principle was reached with customers in December 2024. A Stipulation and Agreement was approved by the Federal Energy Regulatory Commission (FERC) on April 25, 2025 with rates effective December 1, 2024.
Current report
Maritimes & Northeast
Current report
Maritimes & Northeast (M&N) United States (US) filed a rate case on May 30, 2024 and a settlement in principle was reached with customers in December 2024. A Stipulation and Agreement was approved by the FERC on April 25, 2025 with rates effective January 1, 2025.
Current report
The toll settlement agreement for M&N Canada expired in December 2025. M&N Canada reached a toll settlement with shippers for the effective period from January 1, 2026 to December 31, 2027. On December 15, 2025, M&N Canada filed the 2026–2027 toll settlement agreement with the Canada Energy Regulator (CER) for review and approval. A CER decision is expected in the first quarter of 2026.
Current report
East Tennessee
Current report
Vector
Current report
Enbridge Gas Ontario
Current report
Phase 1 of the application established 2024 base rates on a cost-of-service basis.
Current report
Phase 2 established a price cap incentive rate-setting (Price Cap IR) mechanism for 2025–2028.
Current report
Phase 3 addresses cost allocation and the harmonization of rates, rate classes and services. Completion of Phase 3 is expected in 2026.
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Phase 1
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In December 2023, the OEB issued its decision on Phase 1. Enbridge Gas Ontario continues to appeal through Ontario courts the OEB's Phase 1 findings on depreciation, equity thickness and undepreciated capital, with hearing dates scheduled in 2026.
Current report
Phase 2
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Generic Cost of Capital Proceeding
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In March 2025, the OEB released its decision in the generic cost of capital proceeding. The OEB determined that Enbridge Gas Ontario's equity thickness would remain at 38% as approved in the Phase 1 decision. The OEB also revised the formula for calculating ROE by reducing flotation costs by 25 basis points. The new formula will be applicable to Enbridge Gas Ontario at its next rebasing expected in 2029. Until then, rates will continue to reflect the 2024 ROE of 9.21%.
Current report
In June 2025, the Ohio Commission ordered a decrease to annual revenue of US$26.3 million, utilizing an ROE of 9.79%, and an increase to the equity thickness to 51.9%. The order also resulted in disallowances of $330 million (US$240 million), including regulatory pension assets of $280 million (US$204 million) and other disallowances of $50 million (US$36 million) which were recognized for the year ended December 31, 2025.
Current report
The order authorized the continuation of the Pipeline Infrastructure Replacement (PIR) and Capital Expenditure Programs (CEP) through 2028, with 3% increases of capital expenditures under the PIR per year. Assets placed in service accrue a carrying cost at the cost of long-term debt approved in the most recent rate case until incorporated into rates via annual filings.
Current report
In July 2025, Enbridge Gas Ohio filed a rehearing application for certain aspects of the order. The Ohio Commission corrected errors in its order addressing the rehearing application, resulting in a reduction of the original annual revenue decrease to US$14.3 million. Updated rates were effective on November 1, 2025. On December 12, 2025, Enbridge Gas Ohio filed a notice of appeal with the Ohio Supreme Court, focusing on the Ohio Commission's treatment of the pension fund and capitalized incentive-compensation costs.
Current report
In December 2025, Enbridge Gas Ohio filed a base rate case application proposing an annual revenue increase of US$163 million, subject to update and adjustments, to be effective in early 2027. The base rate increase was proposed to recover Enbridge Gas Ohio's investment in distribution infrastructure and other costs to serve, including operating expenses and debt servicing costs.
Current report
Enbridge Gas North Carolina
Current report
In April 2025, Enbridge Gas North Carolina filed its first rates application since 2021 with the North Carolina Utilities Commission, proposing the recovery of costs to deliver natural gas to customers and investments in infrastructure to support service reliability and customer growth.
Current report
In September 2025, a settlement agreement was filed reflecting an annual revenue increase of US$33 million. The settlement was approved by the North Carolina Utilities Commission on December 9, 2025, with updated rates effective November 1, 2025.
Current report
The settlement includes a Major Projects Rider for the Moriah Energy Center LNG facility and the T-15 Reliability Project, as a standalone cost recovery mechanism between general base rate cases.
Current report
Enbridge Gas Utah
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In May 2025, Enbridge Gas Utah filed its first rates application since 2022 with the Utah Public Service Commission, proposing the recovery of costs to deliver natural gas to customers and investments in infrastructure to support service reliability and customer growth.
Current report
In September 2025, Enbridge Gas Utah filed a settlement and final order approving an annual revenue increase of US$61 million was issued on December 24, 2025 with updated rates effective January 1, 2026.
Current report
On February 25, 2025, Enbridge Pipelines Inc. redeemed below par all of the outstanding $100 million 4.10% medium-term notes that carried an original maturity date in July 2112.
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RESULTSOF OPERATIONS
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Year ended December 31, 2025, compared with year ended December 31, 2024
Current report
Earnings attributable to common shareholders was positively impacted by $1.5 billion due to certain infrequent or other non-operating factors, primarily explained by the following:
Current report
equity earnings of $87 million ($65 million after-tax) from our investment in DCP Midstream, LP (DCP), as a result of DCP's gain on disposition from certain pipeline assets; partially offset by
Current report
an impairment of $330 million ($261 million after-tax) of certain rate-regulated assets related to pension and other disallowances as a result of the Ohio Commission's June 2025 order related to Enbridge Gas Ohio's rate case; and
Current report
an impairment loss of $240 million ($176 million after-tax) of certain non-core Liquids Pipelines assets.
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Removed paragraphs (145)
Previous report
MAINLINE TOLLING AGREEMENT
Previous report
The Mainline Tolling Settlement (MTS) is a negotiated settlement with a term of seven and a half years through the end of 2028 that covers both the Canadian and US portions of the Mainline, except for Lines 8 and 9 which are tolled on a separate basis. Enbridge Inc. (Enbridge) filed an application with the Canadian Energy Regulator (CER) for approval of the MTS on December 15, 2023 and the CER issued an order on March 4, 2024 approving Enbridge’s application as filed. Refer to Part I. Item I. Business - Business Segments - Liquids Pipelines - Tolling Framework for detailed terms of the MTS.
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ACQUISITIONS
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US Gas Utilities
Previous report
On September 30, 2024, we acquired all of the membership interests of Fall North Carolina Holdco LLC, which owns 100% of PSNC, for cash consideration of $2.7 billion (US$2.0 billion) (the PSNC Acquisition). PSNC is a public utility primarily engaged in the purchase, sale, transportation and distribution of natural gas to residential, commercial and industrial customers in North Carolina. PSNC operates under rates approved by the North Carolina Utilities Commission (North Carolina Commission). Subsequent to its acquisition, PSNC conducts business as Enbridge Gas North Carolina.
Previous report
On May 31, 2024, we acquired all of the membership interests of Fall West Holdco LLC which owns 100% of Questar and Wexpro for cash consideration of $4.1 billion (US$3.0 billion) (the Questar Acquisition). Questar is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Utah, southwestern Wyoming and southeastern Idaho. The Utah Public Service Commission (Utah Commission), the Wyoming Public Service Commission (Wyoming Commission), and the Idaho Public Utilities Commission (Idaho Commission) have granted Questar the necessary regulatory approvals to serve these areas. Wexpro develops and produces cost-of-service gas reserves for Questar and operates under agreements with the states of Utah and Wyoming. Subsequent to its acquisition, Questar conducts business as Enbridge Gas Utah, Enbridge Gas Wyoming, and Enbridge Gas Idaho in those respective states.
Previous report
On March 6, 2024, we acquired all of the outstanding shares of capital stock of EOG for cash consideration of $5.8 billion (US$4.3 billion) (the EOG Acquisition). EOG is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Ohio and is regulated by the Public Utilities Commission of Ohio (Ohio Commission). Subsequent to its acquisition, EOG conducts business as Enbridge Gas Ohio.
Previous report
The Acquisitions further diversify, and are complementary to, our existing gas distribution operations.
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Joint Venture with WhiteWater/I Squared and MPLX
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On May 29, 2024, we formed a joint venture (the Whistler Parent JV) with WhiteWater/I Squared Capital (WhiteWater/I Squared) and MPLX LP (MPLX) that will develop, construct, own and operate natural gas pipeline and storage assets connecting Permian Basin natural gas supply to growing liquefied natural gas (LNG) and other US Gulf Coast demand. The Whistler Parent JV is owned by WhiteWater/I Squared (50.6%), MPLX (30.4%) and Enbridge (19.0%) and owns the following assets:
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•a 100% interest in the Whistler Pipeline, a 450-mile intrastate pipeline transporting natural gas from the Waha Header in the Permian Basin to Agua Dulce, Texas;
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•a 100% interest in the Rio Bravo Pipeline project, two new parallel 137-mile pipelines transporting natural gas from the Agua Dulce supply area to NextDecade's Rio Grande LNG project in Brownsville, Texas;
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•a 70% interest in the ADCC Pipeline, a new 40-mile pipeline which was placed into service in July 2024 and is designed to transport 1.7 billion cubic feet per day (bcf/d) of natural gas from the terminus of the Whistler Pipeline in Agua Dulce, Texas to Cheniere's Corpus Christi LNG export facility; and
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•a 50% interest in Waha Gas Storage, a 2.0 bcf gas storage cavern facility connecting to key Permian egress pipelines including the Whistler Pipeline.
Previous report
In connection with the formation of the Whistler Parent JV, we contributed our 100% interest in the Rio Bravo Pipeline project and $487 million (US$357 million) of cash to the Whistler Parent JV. In addition to our 19.0% equity interest in the Whistler Parent JV, we received a special equity interest in the Whistler Parent JV which provides for a 25.0% economic interest in the Rio Bravo Pipeline project. This interest is subject to certain redemption rights held by Whitewater/I Squared and MPLX. After the closing on May 29, 2024, we accrued for our share of the post-closing mandatory capital expenditures of approximately US$150 million for the Rio Bravo Pipeline project. Additional capital expenditures to complete the Rio Bravo Pipeline project will be proportionate to our economic interest.
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Acquisition of Renewable Natural Gas (RNG) Facilities
Previous report
On January 2, 2024, through a wholly-owned US subsidiary, we acquired six Morrow Renewables operating landfill gas-to-RNG production facilities (Tomorrow RNG) located in Texas and Arkansas for total consideration of $1.3 billion (US$1.0 billion), of which $584 million (US$439 million) was paid at close and an additional deferred consideration is payable within two years with a fair value of $757 million (US$568 million). The acquired assets align with and advance our lower-carbon strategy.
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ASSET MONETIZATION
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Disposition of Alliance Pipeline and Aux Sable Interests
Previous report
On April 1, 2024, we closed the sale of our 50.0% interest in the Alliance Pipeline, our interest in Aux Sable (including a 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a 50.0% interest in Aux Sable Canada LP) and our interest in NRGreen Power Limited Partnership (NRGreen) to Pembina Pipeline Corporation (Pembina) for $3.1 billion, including $327 million of non-recourse debt. A gain on disposal of $1.1 billion before tax, which is net of $1.0 billion of the goodwill from our Gas Transmission segment allocated to the disposal group, is included in Gain on disposition of equity investments in the Consolidated Statements of Earnings for the year ended December 31, 2024.
Previous report
Texas Eastern
Previous report
In May 2024, Texas Eastern Transmission, LP (Texas Eastern) reached a negotiated settlement with customers to increase rates starting October 1, 2024 with additional increases on January 1, 2026. Texas Eastern filed a Stipulation and Agreement with the Federal Energy Regulatory Commission (FERC) on June 3, 2024 and received approval on July 31, 2024 from the FERC of its uncontested settlement with customers.
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Maritimes & Northeast Pipeline
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Incentive Regulation Rate Application
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In August 2023, the OEB approved the Phase 1 Settlement and in December 2023, the OEB issued its Decision and Order on the remaining unsettled items in Phase 1 (Phase 1 Decision). These decisions include the following findings or orders:
Previous report
•energy transition risk requires us to carry out a risk assessment to consider further risk mitigation measures in three areas: system access and expansion capital spending, system renewal capital spending and depreciation policy;
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•all new small volume customers wishing to connect to natural gas are to pay their full connection costs as an upfront charge (the revenue horizon was set to zero years), rather than through rates over time effective January 2025;
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•approval of a harmonized depreciation methodology that reduced the amount of depreciation sought and adjusted asset lives including extensions of service life for certain asset classes;
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•the removal of $84 million of undepreciated integration capital costs from 2024 rate base; and
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•an increase in equity thickness from 36% to 38% effective 2024.
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Enbridge Gas Ontario filed a Notice of Appeal with the Ontario Divisional Court in January 2024 regarding various aspects of the Phase 1 Decision and subsequently filed an amended Notice of Appeal in December 2024 (Amended Appeal). The Amended Appeal focused on two aspects of the Phase 1 Decision: asset class average useful lives for depreciation purposes, and equity thickness. In January 2024, Enbridge Gas Ontario filed a Notice of Motion with the OEB requesting the OEB to review and vary the Phase 1 Decision which was subsequently amended in May 2024 (Amended Motion). The Amended Motion focused on two aspects of the Phase 1 Decision: asset class average useful lives for depreciation purposes, and the recoverability of integration capital. In October 2024, the OEB issued a decision on the Amended Motion and determined that only the issue of integration capital met the threshold to warrant a review. We are currently awaiting an OEB decision on the issue of integration capital.
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In May 2024, Bill 165, the Keeping Energy Costs Down Act, received royal assent, giving the Government of Ontario time-limited authority to set the revenue horizon for small volume customers, effectively reversing that aspect of the OEB's Phase 1 Decision. Regulations are now in place setting the revenue horizon for new customer connections to 40 years.
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On May 15, 2024, we established an at-the-market equity issuance program (ATM Program) which provided us with additional flexibility to fund the Acquisitions. From May 15, 2024 to July 31, 2024, 51,298,629 common shares were issued on Canadian and US exchanges at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.50 billion. On August 1, 2024, we terminated the ATM Program.
Previous report
On September 8, 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which were also used to finance a portion of the aggregate cash consideration payable for the Acquisitions discussed in Note 6 - Acquisitions and Dispositions.
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RESULTS OF OPERATIONS
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1 Non-GAAP financial measures.
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Earnings attributable to common shareholders decreased by $1.1 billion due to certain infrequent or other non-operating factors, primarily explained by the following:
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•the absence in 2024 of a gain of $151 million ($129 million after-tax) net of a deferred tax adjustment of $69 million recognized as a result of the discontinuation of regulatory accounting for Southern Lights Pipeline;
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•$137 million ($114 million after-tax) of integration and transaction costs incurred related to the Acquisitions in 2024, as compared to $31 million ($24 million after-tax) of transaction costs in 2023;
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•the absence of the receipt of a litigation claim settlement of $68 million ($52 million after-tax); and
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Reworded paragraphs (110)
Previous wording
Algonquin Gas Transmission, LLC (Algonquin) filed a rate case on May 30, 2024. On June 28, 2024, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In December 2024, Algonquin reached a settlement in principle with customers which will be filed for FERC approval in the first quarter 2025. If approved, rates will be effective December 1, 2024.
Current wording
East Tennessee Natural Gas, LLC (East Tennessee) filed a rate case on April 29, 2025. On May 29, 2025, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In compliance with the order, East Tennessee made a filing to implement the rates to be effective November 1, 2025, subject to refund. Settlement discussions with shippers commenced in the third quarter of 2025.
Previous wording
Maritimes & Northeast Pipeline (M&N) US filed a rate case on May 30, 2024. On June 27, 2024, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In December 2024, M&N US reached a settlement in principle with customers which will be filed for FERC approval in the first quarter 2025. If approved, rates will be effective January 1, 2025.
Current wording
Vector Pipeline L.P. (Vector) filed a rate case on May 30, 2025. On June 30, 2025, the FERC issued an order accepting and suspending tariff records filed in this rate case, and establishing hearing procedures. In compliance with the order, Vector placed the proposed rates into effect on July 1, 2025. Additionally, on July 1, 2025, the chief administrative law judge issued an order consolidating Vector’s outstanding review of rates initiated by the FERC in 2024 with Vector’s May 30, 2025 rate case filing. In February 2026, Vector reached a settlement in principle with all active participants that resolves all issues in the consolidated rate case, which will be filed for FERC approval in the first half of 2026. If approved, settlement rates will be effective April 1, 2026.
Previous wording
In October 2022, Enbridge Gas Inc. (Enbridge Gas Ontario) filed its application with the Ontario Energy Board (OEB) to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application initially sought approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term (2025-2028). A third phase (Phase 3) has been established with the OEB as part of the Phase 1 Partial Settlement Proposal (Phase 1 Settlement). Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones, and is anticipated to be completed in 2025.
Current wording
In October 2022, Enbridge Gas Inc. (Enbridge Gas Ontario) filed its application with the Ontario Energy Board (OEB) to establish a 2024–2028 Incentive Regulation (IR) rate setting framework:
Previous wording
In November 2024, the OEB issued its Decision approving the Phase 2 Partial Settlement Proposal (Phase 2 Settlement). The Phase 2 Settlement establishes a price cap IR rate setting mechanism to be used for establishing rates for 2025 – 2028. The price cap mechanism will establish new rates each year through an annual base rate adjustment to migrate an incremental $50 million in capitalized overheads to operating and maintenance costs, annual base rate escalation at inflation less a 0.28% productivity factor, annual updates for certain costs to be passed through to customers, and where applicable, it will provide for the recovery of material unexpected events and discrete incremental capital investments beyond those that can be funded through base rates. The price cap mechanism includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas Ontario to share equally with customers any earnings in excess of 100 basis points over the allowed return on equity (ROE), and 90% of any earnings in excess of 300 basis points over the allowed ROE. Issues not addressed as part of the Phase 2 Settlement proceeded to hearing in December 2024 and a decision is expected in the second quarter of 2025.
Current wording
Through a November 2024 decision on the Phase 2 partial settlement proposal, and a May 2025 decision on outstanding issues, the OEB approved a Price Cap IR mechanism for 2025–2028 rates. The mechanism includes an earnings sharing mechanism which requires earnings in excess of 100 basis points over the allowed return on equity (ROE) to be shared equally with customers, and 90% of any earnings in excess of 300 basis points over the allowed ROE. Rates effective January 1, 2025 and January 1, 2026, were set using the approved Price Cap IR mechanism.
Previous wording
In October 2023, Enbridge Gas Ohio filed its base rate case and schedules with the Ohio Commission. Enbridge Gas Ohio proposed a non-fuel, base rate annual revenue increase of $212 million, projected to be effective January 2025. The base rate increase was proposed to recover the significant investment in distribution infrastructure for the benefit of Ohio customers. The proposed rates would have provided for an ROE of 10.40% compared to the currently authorized ROE of 10.38%. In addition, Enbridge Gas Ohio requested approval for an alternative rate plan for the continuation and modification of certain programs, including Pipeline Infrastructure Replacement and Capital Expenditure Program. On December 18, 2024, Enbridge Gas Ohio filed a Notice of Intent to Modify Filed Positions. The Notice of Intent indicated a willingness to accept a reduced annual revenue requirement increase (from $212 million to $60 million) and, if the reduced position were adopted, to forgo filing a new base rate case until October 31, 2027. The hearing began on January 13, 2025, and remains underway.
Current wording
In October 2023, Enbridge Gas Ohio filed its first base rates application with the Ohio Commission since 2007, proposing a base rate annual revenue increase to be effective January 2025. The base rate increase was proposed to recover the significant investment in distribution infrastructure for the benefit of Ohio customers, including an ROE of 10.40%.
Previous wording
We completed long-term debt issuances totaling US$5.7 billion and $1.8 billion during the year ended December 31, 2024.
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We completed long-term debt issuances totaling $4.6 billion and US$4.7 billion during the year ended December 31, 2025.
Previous wording
On the March 8, 2024 call date, we redeemed at par all of the outstanding US$700 million three-year callable, 5.97% senior notes that carried an original maturity date in March 2026.
Current wording
On July 28, 2025, Enbridge Energy Partners, L.P. (EEP) redeemed at par all of the outstanding US$500 million 5.88% senior notes that carried an original maturity date in October 2025.
Previous wording
During our annual renewal process, we renewed and extended approximately $17.6 billion of our credit facilities with maturities ranging from 2025-2029. We also increased our letter of credit facilities by approximately $346 million and entered into new term loans with maturities ranging from 2029-2049 totaling approximately $542 million.
Current wording
During our annual renewal process, we renewed and extended approximately $22.1 billion of our credit facilities with maturities ranging from 2027–2030.
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As at December 31, 2024, after adjusting for the impact of floating-to-fixed interest rate swap hedges, less than 5% of our total debt is exposed to floating rates. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 23 - Risk Management and Financial Instruments for more information on our interest rate hedging program.
Current wording
As at December 31, 2025, after adjusting for the impact of floating-to-fixed interest rate swap hedges, approximately 9% of our total debt is exposed to floating rates. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 23 - Risk Management and Financial Instrumentsfor more information on our interest rate hedging program.
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•a non-cash, net unrealized loss of $2.1 billion ($1.6 billion after-tax) in 2024, compared with a net unrealized gain of $1.2 billion ($911 million after-tax) in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate, and commodity price risk;
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a non-cash, net unrealized derivative fair value gain of $1.3 billion ($999 million after-tax) in 2025, compared with a net unrealized loss of $2.1 billion ($1.6 billion after-tax) in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks; and
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•a gain on sale of $1.1 billion ($765 million after-tax) related to the disposition of interests in the Alliance Pipeline, Aux Sable and NRGreen;
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the absence in 2025 of a gain on sale of $1.1 billion ($765 million after-tax) on the disposition of our interests in the Alliance Pipeline and Aux Sable Liquid Products LP, Aux Sable Midstream LLC, and Aux Sable Canada LP (Aux Sable);
Previous wording
After taking into consideration the factors above, the remaining $294 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:
Current wording
After taking into consideration the factors above, the remaining $541 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:
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•higher interest expense primarily due to higher average principal outstanding resulting from the Acquisitions;
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higher interest expense primarily due to higher average debt principal outstanding;
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•higher depreciation and amortization expense mainly driven by acquisitions we completed in 2023 and 2024, as mentioned above;
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higher depreciation and amortization expense mainly driven by full year ownership of the US Gas Utilities;
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•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 the Enbridge Ingleside Energy Center due to higher demand and new storage contracts that commenced in the second quarter of 2024; and
Current wording
lower contributions from the Gulf Coast and Mid-Continent System in our Liquids Pipelines segment primarily due to lower spot volumes on the Flanagan South Pipeline;
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•lower contributions from Alliance Pipeline and Aux Sable from our Gas Transmission segment due to the sale of our interest in these investments in April 2024;
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lower contributions from our Gas Transmission segment due to the sale of our interests in Alliance Pipeline and Aux Sable in April 2024 and lower earnings from our Tomorrow RNG renewable natural gas facilities due to lower Renewable Identification Number (RIN) pricing and production volumes;
Previous wording
On September 5, 2023, Enbridge entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company (EOG), Questar Gas Company (Questar) and its related Wexpro companies (Wexpro), and Public Service Company of North Carolina, Incorporated (PSNC) (together, the Acquisitions).
Current wording
the absence in 2025 of interest income from cash pre-funding related to Enbridge's acquisitions of the East Ohio Gas Company (EOG), Questar Gas Company (Questar) and its related Wexpro companies (Wexpro), and Public Service Company of North Carolina, Incorporated (PSNC) (together, the Acquisitions) in Eliminations and Other.
Previous wording
Transportation and other services revenues of $19.7 billion, $19.2 billion and $17.9 billion for the years ended December 31, 2024, 2023 and 2022, respectively, were earned from our crude oil and natural gas pipeline transportation businesses and also include power generation revenues from our portfolio of renewable and power generation assets. For our transportation assets operating under market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator and, in most cost-of-service based arrangements, are reflective of our cost to provide the service plus a regulator-approved rate of return.
Current wording
Transportation and other services revenues of $20.2 billion, $19.7 billion and $19.2 billion, for the years ended December 31, 2025, 2024 and 2023, respectively, were earned from our crude oil and natural gas pipeline transportation businesses and also include power generation revenues from our portfolio of renewable and power generation assets. For our transportation assets operating under market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator and, in most cost-of-service based arrangements, are reflective of our cost to provide the service plus a regulator-approved rate of return.
Previous wording
Gas distribution sales revenues of $6.8 billion, $5.4 billion and $6.2 billion for the years ended December 31, 2024, 2023 and 2022, respectively, were recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are primarily driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through rates to customers and does not ultimately impact earnings due to its flow-through nature.
Current wording
Gas distribution sales revenues of $9.8 billion, $6.8 billion and $5.4 billion for the years ended December 31, 2025, 2024 and 2023, respectively, were recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are primarily driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through rates to customers and does not ultimately impact earnings due to its flow-through nature.
Previous wording
Commodity sales revenues of $27.0 billion, $19.0 billion and $29.2 billion for the years ended December 31, 2024, 2023 and 2022, respectively, were generated primarily through our crude oil marketing, natural gas and power marketing businesses. This includes the purchase and sale of crude oil, natural gas, power and NGL to generate a margin, which is typically a small fraction of gross revenue. Sales revenue generated from these operations reflect activity levels which are driven by differences in commodity prices between locations, grades and points in time, rather than on absolute prices. Commodity sales revenues also include revenue generated from our Tomorrow RNG business. Any residual commodity margin risk is closely monitored and managed. Revenues from these operations depend on activity levels, which vary from year-to-year depending on market conditions and commodity prices.
Current wording
Commodity sales revenues of $35.2 billion, $27.0 billion and $19.0 billion for the years ended December 31, 2025, 2024 and 2023, respectively, were generated primarily through our crude oil marketing, natural gas and power marketing businesses. This includes the purchase and sale of crude oil, natural gas, power and NGL to generate a margin, which is typically a small fraction of gross revenue. Sales revenue generated from these operations reflect activity levels which are driven by differences in commodity prices between locations, grades and points in time, rather than on absolute prices. Commodity sales revenues also include revenue generated from our Tomorrow RNG business. Any residual commodity margin risk is closely monitored and managed. Revenues from these operations depend on activity levels, which vary from year-to-year depending on market conditions and commodity prices.
Previous wording
•lower Mainline power costs from operational efficiencies and lower Alberta mill rates;
Current wording
higher Mainline System contributions (net of sharing) as a result of higher demand, annual escalators and surcharge effective July 1, 2024, and lower power costs from operational efficiencies and lower mill rates;
Previous wording
•the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2024, as compared to 2023, partially offset by
Current wording
the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to 2024; partially offset by
Previous wording
•a gain on sale of $1,063 million on the disposition of interests in the Alliance Pipeline and Aux Sable; and
Current wording
the absence in 2025 of a gain on sale of $1.1 billion on the disposition of interests in the Alliance Pipeline and Aux Sable; partially offset by
Previous wording
•an asset impairment loss of $137 million related to the Big Sandy Pipeline;
Current wording
the absence in 2025 of an asset impairment loss of $137 million related to the Big Sandy Pipeline;
Previous wording
•a net positive adjustment to crude oil inventory of $15 million in 2024, compared with a net negative adjustment of $16 million in 2023.
Current wording
a net positive adjustment of $32 million to the gas inventory at Aitken Creek in 2025, compared to a net negative adjustment of $33 million in 2024.
Previous wording
•favorable contracting and lower operating costs on our US Gas Transmission assets;
Current wording
favorable contracting on our US Gas Transmission assets;
Previous wording
•the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2024, compared to the same period in 2023, partially offset by
Current wording
the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to 2024; partially offset by
Previous wording
•lower contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments in April 2024.
Current wording
the absence of contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments in April 2024; and
Previous wording
•higher distribution charges resulting from increases in customer base and higher demand in the contract market at Enbridge Gas Ontario, partially offset by
Current wording
higher distribution margin resulting from increases in rates and customer base at Enbridge Gas Ontario;
Previous wording
•an impairment loss of $55 million related to certain assets.
Current wording
the absence in 2025 of an impairment loss of $55 million related to certain assets; partially offset by
Previous wording
•a non-cash, net unrealized loss of $13 million in 2024, compared with a net unrealized loss of $72 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and
Current wording
a realized loss of $139 million, partially offset by a non-cash, net unrealized gain of $112 million in 2025, compared with a net unrealized loss of $13 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.
Previous wording
Eliminations and Other includes operating and administrative costs that are not allocated to business segments, the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. Eliminations and Other also includes our natural gas and power marketing businesses and the impact of new business development activities and corporate investments.
Current wording
Eliminations and Other includes operating and administrative costs that are not allocated to business segments, the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiary. Eliminations and Other also includes our natural gas and power marketing businesses and the impact of new business development activities and corporate investments.
Previous wording
•a non-cash, net unrealized loss of $2.2 billion in 2024, compared with a net unrealized gain of $688 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks;
Current wording
a non-cash, net unrealized gain of $1.2 billion in 2025, compared with a net unrealized loss of $2.2 billion in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and
Previous wording
•severance costs of $105 million as a result of a workforce reduction in February 2024;
Current wording
the absence in 2025 of $105 million severance costs as a result of a workforce reduction in February 2024.
Previous wording
After taking into consideration the non-operating factors above, we saw a $278 million increase in EBITDA that is primarily explained by:
Current wording
After taking into consideration the non-operating factors above, we saw a $461 million decrease in EBITDA that is primarily explained by:
Previous wording
•higher realized foreign exchange loss on hedge settlements in 2024.
Current wording
higher realized foreign exchange losses on hedge settlements in 2025; and
Previous wording
1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.
Current wording
These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.
Previous wording
2 Expenditures to date and status of the project are determined as at December 31, 2024.
Current wording
Expenditures to date and status of the project are determined as at December 31, 2025.
Previous wording
4 Our equity contribution is approximately US$0.9 billion, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated in 2025, at which point Enbridge's preferred return will be set.
Current wording
Our expected investment is approximately US$2.3 billion, with the remainder financed through non-recourse project level debt.
Previous wording
5 Previously approved PSNC projects that were acquired by Enbridge through the Acquisitions.
Current wording
Previously approved projects that were acquired by Enbridge through the acquisition of PSNC.
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Rearranged current paragraphs (10)
Current report — wording carried from elsewhere
Non-GAAP financial measure. Refer to Non-GAAP and Other Financial Measures.
Current report — wording carried from elsewhere
The factors above were partially offset by:
Current report — wording carried from elsewhere
lower contributions from the Gulf Coast and Mid-Continent System primarily due to lower spot volumes on the Flanagan South Pipeline.
Current report — wording carried from elsewhere
the absence in 2025 of the acquisitions of EOG, Questar, PSNC, and Tomorrow RNG;
Current report — wording carried from elsewhere
the absence in 2025 of the acquisitions of equity interests in the Whistler Parent JV and DBR and contributions to our Fox Squirrel Solar investment; partially offset by
Current report — wording carried from elsewhere
a full year of capital expenditures from EOG, Questar, and PSNC, and higher capital expenditures from growth projects in our Gas Transmission and Renewable Power Generation segments.
Current report — wording carried from elsewhere
the absence in 2025 of the at-the-market program, which resulted in the issuance of 51,298,629 common shares for aggregate net proceeds of $2.5 billion in 2024; partially offset by
Current report — wording carried from elsewhere
higher long-term debt issuances in 2025 compared to 2024, and
Current report — wording carried from elsewhere
On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a
Current report — wording carried from elsewhere
On August 29, 2022, the Government of Canada released a statement formally invoking the dispute settlement provisions of the Agreement Between the US and Canada Concerning Transit Pipelines, 28 U.S.T. 7449 (1977) (1977 Transit Pipelines Treaty) in respect of this litigation, reiterating its concerns about the uninterrupted transmission of hydrocarbons through Line 5.
Rearranged previous paragraphs (6)
Previous report — wording carried elsewhere
•an asset impairment loss of $137 million ($103 million after-tax) related to the Big Sandy Pipeline;
Previous report — wording carried elsewhere
•severance costs of $105 million ($79 million after-tax) as a result of a workforce reduction in February 2024;
Previous report — wording carried elsewhere
•a non-cash revaluation loss of $33 million to the gas inventory at Aitken Creek; and
Previous report — wording carried elsewhere
The increase in cash used in investing activities primarily resulted from the following factors:
Previous report — wording carried elsewhere
•net repayments of short-term borrowings in 2023 when compared to net issuances in 2022;
Previous report — wording carried elsewhere
•increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding.