ENBRIDGE INC
For the period ended Sep 30, 2025. Filed Nov 7, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Sep 30, 2025 · Filed Nov 7, 2025
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-Q
Period ended 2025-06-30; filed 2025-08-01.
0000950170-25-101102
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-09-30; filed 2025-11-07.
0001193125-25-270991
Item 2. 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 261 previous paragraphs and 240 current paragraphs.
126 unchanged; 75 reworded; 37 added; 42 removed; 18 previous and 2 current paragraphs rearranged.
Tables are not compared: 15 previous and 15 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 (37)
Current report
In September 2025, a joint stipulation of settlement was filed and is pending approval by the North Carolina Utilities Commission. If approved, updated rates would be effective November 1, 2025 and would reflect a revenue increase of US$34 million and a total revenue requirement of US$801 million.
Current report
In September 2025, Enbridge Gas Ontario closed a two-tranche offering consisting of 10-year medium-term notes and 30-year medium-term notes for an aggregate principal amount of $0.8 billion, which mature in September 2035 and September 2055, respectively.
Current report
In September 2025, we closed an offering consisting of 30-year non-call 5.15% fixed-to-fixed subordinated notes for a principal amount of $1.0 billion, which mature in December 2055.
Current report
Earnings attributable to common shareholders were negatively impacted by $414 million due to certain infrequent or other non-operating factors, primarily explained by the following:
Current report
a non-cash, net unrealized derivative fair value loss of $394 million ($299 million after-tax) in 2025, compared with a net unrealized gain of $112 million ($92 million 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
Current report
full-quarter contribution from the acquisition of Enbridge Gas North Carolina and increased revenue requirement from recovery of capital investments at Enbridge Gas Ohio both in our Gas Distribution and Storage segment.
Current report
three full quarters of contributions from the US Gas Utilities in our Gas Distribution and Storage segment;
Current report
EBITDA was negatively impacted by $42 million, primarily explained by lower contributions from the Flanagan South and Spearhead Pipelines of the Gulf Coast and Mid-Continent System.
Current report
EBITDA was positively impacted by $23 million due to certain infrequent or other non-operating factors, primarily explained by:
Current report
After taking into consideration the factors above, the remaining $5 million increase is primarily explained by the following significant business factors:
Current report
favorable Regional Oil Sands results primarily from higher volumes;
Current report
EBITDA was positively impacted by a non-cash gain of $16 million from the redemption of Enbridge's special 25.0% economic interest in the Rio Bravo Pipeline Project by the Whistler Parent JV.
Current report
The remaining $108 million increase is primarily explained by the following significant business factors:
Current report
higher revenues at Aitken Creek due to favorable storage spreads; and
Current report
lower earnings at Tomorrow RNG primarily due to lower RIN pricing and timing of RIN sales.
Current report
EBITDA was negatively impacted by $896 million due to certain infrequent or other non-operating factors, primarily explained by:
Current report
a gain of $16 million from the redemption of Enbridge's special 25.0% economic interest in the Rio Bravo Pipeline Project by the Whistler Parent JV.
Current report
The remaining $575 million increase is primarily explained by the following significant business factors:
Current report
higher revenues at Aitken Creek due to favorable storage spreads;
Current report
lower earnings at Tomorrow RNG primarily due to lower RIN pricing and timing of RIN sales.
Current report
EBITDA was positively impacted by $38 million primarily explained by full-quarter contributions from the acquisition of Enbridge Gas North Carolina and increased revenue requirement from recovery of capital investments at Enbridge Gas Ohio.
Current report
The remaining $14 million increase is primarily explained by higher revenue from sale of renewable energy certificates compared to the third quarter of 2024.
Current report
EBITDA was negatively impacted by $25 million due to certain infrequent or other non-operating factors, primarily explained by:
Current report
EBITDA was negatively impacted by $616 million primarily explained by a non-cash, net unrealized loss of $397 million in 2025, compared with a net unrealized gain of $206 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk.
Current report
a non-cash, net unrealized gain of $1 million in 2025, compared with a net gain of $35 million in 2024, reflecting changes in the fair value of investments held by our captive insurance subsidiaries; and
Current report
$86 million of integration costs incurred related to the Acquisitions in 2025, compared to $55 million of integration and transaction costs in 2024.
Current report
3 Includes amounts for the construction of the Southern Illinois Connector Pipeline, which is expected to be 50% jointly-owned with Energy Transfer, costs to upgrade the Energy Transfer Crude Oil Pipeline, in which we have a 27.6% ownership interest, as well as amounts fully attributable to Enbridge.
Current report
4 Our redeemable noncontrolling interest holder, Stonlasec8 Indigenous Investments Limited Partnership, will have the opportunity to participate in designated capital programs once they have been completed or substantially completed. As a result, our ownership interest in the program(s) may change in future periods. Refer to Part I. Item 1. Financial Statements - Note 9. Redeemable Noncontrolling Interest.
Current report
LIQUIDS PIPELINES
Current report
Southern Illinois Connector -The construction of a new 24-inch pipeline from Wood River to Patoka, Illinois, connecting the Platte Pipeline to our jointly-owned Energy Transfer Crude Oil Pipeline. In addition, the project includes new pump stations to provide incremental capacity to the Platte system. Incremental volumes are secured under long-term take-or-pay agreements with investment grade customers. The project has an expected in-service date in 2028.
Current report
Pelican CO 2 Hub -A 50/50 joint venture with a subsidiary of Occidental Petroleum Corporation (Oxy) to design, construct and operate a carbon dioxide transportation and sequestration hub in the Louisiana Mississippi River corridor. Oxy will manage the sequestration portions of the project, while Enbridge will manage the pipeline. Development is supported by a long-term take-or-pay offtake agreement with an investment grade counterparty and the facility is expected to enter service in 2029.
Current report
Canyon System Pipelines - A component of the Canyon System Pipelines project serving bp's Tiber offshore production facility in the US Gulf Coast (USGC). This project includes both crude oil and natural gas pipeline extensions and is expected to enter service in 2029. The Canyon System Pipelines project was previously sanctioned to support bp's Kaskida offshore development and includes a 24/26-inch oil pipeline connecting to Shell Pipeline Company LP's Green Canyon 19 Platform and a 12-inch gas pipeline connecting to our existing Magnolia Gas Gathering Pipeline.
Current report
Algonquin Reliable Affordable Resilient Enhancement -An enhancement of our Algonquin Pipeline to serve incremental demand across the northeastern US. The project is anticipated to enhance supply reliability and improve affordability by reducing winter price volatility for customers. We expect the project to enter service in 2029.
Current report
USGC Storage Growth Program - An expansion of our Egan Hub and Moss Bluff natural gas storage facilities in the USGC, to provide 16 billion cubic feet (Bcf) and 7 Bcf of new site capacity, respectively. Egan Hub will be expanded over two phases, with each phase expected to enter service in 2030 and 2033, respectively. The expansion of our Moss Bluff facility is expected to enter service in 2028. These projects are expected to improve site injection and withdrawal rates, optimizing existing capacity, and to offer storage capacity to USGC liquefied natural gas facilities during periods of high demand.
Current report
For the initial 5.25 years, the notes carry a fixed interest rate. On December 17, 2030, the interest rate will be reset to equal the Five-Year Government of Canada bond yield plus a margin of 2.39%.
Current report
higher long-term debt repayments and lower long-term debt issuances in 2025 when compared to the same period in 2024.
Current report
The factors above were partially offset by proceeds of $712 million, net of transaction costs, received from Stonlasec8 Indigenous Investments Limited Partnership for their noncontrolling interest investment in our BC Pipeline system.
Removed paragraphs (42)
Previous report
NONCONTROLLING INTEREST INVESTMENT
Previous report
BC Pipeline System
Previous report
On July 2, 2025, Stonlasec8 Indigenous Alliance 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, resulting in the First Nations Partnership owning a 12.5% interest in that system.
Previous report
Subsequent to the First Nations Partnership's investment, we will hold an 87.5% controlling interest in these assets, which are included in our Gas Transmission segment, and continue to manage and operate the pipeline system.
Previous report
Algonquin
Previous 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.
Previous report
Maritimes & Northeast Pipeline
Previous report
Maritimes & Northeast Pipeline 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.
Previous report
a net positive adjustment of $8 million ($6 million after-tax) in 2025 to the gas inventory at the Aitken Creek Gas Storage Facility (Aitken Creek), compared to a net negative adjustment of $29 million ($21 million after-tax) in 2024; and
Previous report
the absence in 2025 of a loss of $25 million ($19 million after-tax) as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to a joint venture with WhiteWater/I Squared Capital and MPLX LP (the Whistler Parent JV); partially offset by
Previous report
the absence in 2025 of a gain on sale of $1.1 billion ($765 million after-tax) on the disposition of interests in the Alliance Pipeline, 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 NRGreen Power Limited Partnership (NRGreen);
Previous report
$42 million ($33 million after-tax) of integration costs incurred related to the Acquisitions in 2025, as compared to $16 million ($13 million after-tax) of integration and transaction costs in 2024.
Previous report
full-quarter contributions from the acquisitions of Enbridge Gas Utah and Enbridge Gas North Carolina in our Gas Distribution and Storage segment;
Previous report
lower income tax expense mainly driven by higher investment tax credits; and
Previous report
a non-cash, net unrealized derivative fair value gain of $1.3 billion ($1.0 billion after-tax) in 2025, compared with a net unrealized loss of $885 million ($678 million 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;
Previous report
two full-quarter contributions from the acquisitions of Enbridge Gas Ohio, Enbridge Gas Utah, and Enbridge Gas North Carolina in our Gas Distribution and Storage segment;
Previous report
EBITDA was negatively impacted by $119 million, primarily explained by the following significant business factors:
Previous report
lower contributions from the Gulf Coast and Mid-Continent System due to lower spot volumes on the Flanagan South Pipeline and Spearhead Pipeline; and
Previous report
EBITDA was positively impacted by $29 million due to certain infrequent or other non-operating factors, primarily explained by:
Previous report
After taking into consideration the factors above, the remaining $41 million increase is primarily explained by the following significant business factors:
Previous report
lower contributions from the Gulf Coast and Mid-Continent System due to lower spot volumes on the Flanagan South Pipeline and Spearhead Pipeline; and
Previous report
EBITDA was negatively impacted by $955 million due to certain infrequent or other non-operating factors, primarily explained by:
Previous report
a net positive adjustment of $8 million to the gas inventory at Aitken Creek in 2025, compared to a net negative adjustment of $29 million in 2024; and
Previous report
The remaining $302 million increase is primarily explained by the following significant business factors:
Previous report
EBITDA was negatively impacted by $912 million due to certain infrequent or other non-operating factors, primarily explained by:
Previous report
The remaining $467 million increase is primarily explained by the following significant business factors:
Previous report
higher revenues at Aitken Creek;
Previous report
The remaining $273 million increase is primarily explained by the following significant business factors:
Previous report
full-quarter contributions from the acquisitions of Enbridge Gas Utah and Enbridge Gas North Carolina;
Previous report
lower operating and administrative costs primarily due to lower employee related costs at Enbridge Gas Ontario;
Previous report
EBITDA was negatively impacted by $2 million due to certain infrequent or other non-operating factors, primarily explained by:
Previous report
lower fees earned in 2025 on certain wind development contracts; and
Previous report
EBITDA was positively impacted by $2 million due to certain infrequent or other non-operating factors, primarily explained by:
Previous report
a non-cash, net unrealized gain of $1.3 billion in 2025, compared with a net unrealized loss of $229 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk; partially offset by
Previous report
$42 million of integration costs incurred related to the Acquisitions in 2025, compared to $16 million of integration and transaction costs in 2024.
Previous report
$63 million of integration costs incurred related to the Acquisitions in 2025, compared to $30 million of integration and transaction costs in 2024.
Previous report
The factors above were partially offset by net draws of short-term borrowings in 2025 when compared to net repayments during the same period in 2024.
Previous report
DAKOTA ACCESS PIPELINE
Previous report
We hold an effective 27.6% interest in the Bakken Pipeline System, which includes the Dakota Access Pipeline (DAPL). The Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court for the District of Columbia (the District Court) challenging the Army Corps’ easement for DAPL, citing concerns over the adequacy of the Army Corps' environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018. In 2017 and again in 2020, the District Court found deficiencies in the Army Corps’ environmental assessments and ordered the preparation of a full Environmental Impact Statement (EIS).
Previous report
In July 2020, the District Court vacated the easement and ordered the pipeline shut down, but that order was stayed by the US Court of Appeals for the District of Columbia. In January 2021, the US Court of Appeals upheld the requirement for an EIS and confirmed the easement’s vacatur, though it ruled that DAPL could continue operating absent an injunction. The US Supreme Court declined to review the case, and the Army Corps indicated it would not seek to halt operations during the review process.
Showing the first 40 of 42 passages. Open the source sections for the rest.
Reworded paragraphs (75)
Previous 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 intends to make a motion filing to implement the rates to be effective November 1, 2025, subject to refund. East Tennessee expects settlement discussions with shippers to commence in the third quarter of 2025.
Current wording
East Tennessee Natural Gas, LLC (East Tennessee) filed a rate case on April 29, 2025. On May 29, 2025, the Federal Energy Regulatory Commission (FERC) issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In compliance with the order, East Tennessee has made a motion 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
On September 19, 2024, the FERC initiated a review of Vector Pipeline L.P.’s (Vector) rates. Vector subsequently 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, subject to refund and establishing hearing procedures. In compliance with the order, Vector placed the rate reductions 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. Vector expects settlement discussions with shippers to commence in the third quarter of 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, subject to refund and establishing hearing procedures. In compliance with the order, Vector placed the rate reductions 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. Settlement discussions with shippers commenced in the third quarter of 2025.
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 incentive rate-setting (Price Cap IR) mechanism (Phase 2) to be used for the remainder of the IR term (2025–2028). A third phase (Phase 3) was established with the OEB in 2023. Phase 3 addresses cost allocation and the harmonization of rates and rate classes 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 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 incentive rate setting (Price Cap IR) mechanism (Phase 2) to be used for the remainder of the IR term (2025-2028). A third phase (Phase 3) was established with the OEB in 2023. Phase 3 addresses cost allocation and the harmonization of rates, rate classes and services and is anticipated to be completed in 2026.
Previous wording
In December 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). Enbridge Gas Ontario initiated various appeals of select aspects of the Phase 1 Decision, including a review motion with the OEB that concluded in April 2025 with the OEB denying its motion to vary the Phase 1 Decision which disallowed recoverability of certain undepreciated capital. Enbridge Gas Ontario continues to pursue appeal and judicial review applications to the Ontario Divisional Court that challenge some of the OEB’s Phase 1 findings with respect to depreciation, equity thickness and undepreciated capital. These proceedings are at the stage of written submissions and no hearing dates have been scheduled yet.
Current wording
In December 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). Enbridge Gas Ontario initiated various appeals of select aspects of the Phase 1 Decision, including a review motion with the OEB that concluded in April 2025 with the OEB denying its motion to vary the Phase 1 Decision which disallowed recoverability of certain undepreciated capital. Enbridge Gas Ontario continues to pursue appeal and judicial review applications to the Ontario Divisional Court that challenge some of the OEB’s Phase 1 findings with respect to depreciation, equity thickness and undepreciated capital. Hearing dates in March 2026 have been scheduled for the hearing of the appeal and judicial review applications.
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 mechanism to be used for determining rates for 2025-2028. The Price Cap IR 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 the OEB rendered its Decision in May 2025. Rates effective January 1, 2025 were set using the Price Cap IR mechanism.
Current wording
In November 2024, the OEB issued its Decision approving the Phase 2 Partial Settlement Proposal (Phase 2 Settlement). The Phase 2 Settlement established a Price Cap IR mechanism to be used for determining rates for 2025-2028. The Price Cap IR 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 the OEB rendered its Decision in May 2025. Rates effective January 1, 2025 were set using the Price Cap IR mechanism.
Previous wording
In June 2025, the Ohio Commission issued an order approving an annual revenue decrease (compared to current rates) of US$26.3 million, including an ROE of 9.79%, an increase to the equity thickness to 51.9%, and the continuation of the Pipeline Infrastructure Replacement and Capital Expenditure Programs. The order also resulted in disallowances of $330 million (US$240 million) including regulatory assets related to pension balances of $280 million (US$204 million) and other disallowances of $50 million (US$36 million) and the subsequent impairments recognized for the period ended June 30, 2025.
Current wording
In June 2025, the Ohio Commission ordered a decrease to annual revenue, compared to current rates, of US$26.3 million, utilizing an ROE of 9.79%, an increase to the equity thickness to 51.9%, and the continuation of the Pipeline Infrastructure Replacement and Capital Expenditure Programs. The order also resulted in disallowances of $330 million (US$240 million), including regulatory assets related to pension balances of $280 million (US$204 million) and other disallowances of $50 million (US$36 million), which were recognized for the period ended June 30, 2025.
Previous wording
In July 2025, Enbridge Gas Ohio filed an application for rehearing regarding certain aspects of the order and continues to assess legal options.
Current wording
In July 2025, Enbridge Gas Ohio filed an application for rehearing regarding certain aspects of the Order. The Ohio Commission corrected some accounting errors in its Order addressing the rehearing application resulting in an additional US$12 million revenue requirement and a total annual revenue requirement of US$895 million. The Ohio Commission also required Enbridge Gas Ohio to make an additional cost of service filing reflecting the Ohio Commission’s decisions. The Ohio Commission approved Enbridge Gas Ohio’s filing on October 15, 2025. New rates were put into effect on November 1, 2025.
Previous wording
On April 1, 2025, Enbridge Gas North Carolina filed its first rates application since 2021 with the North Carolina Utilities Commission. This rate case aims to reflect the costs of delivering natural gas to customers and recover investments in infrastructure to support service reliability and customer growth. Enbridge Gas North Carolina is proposing a 12% increase to its residential natural gas rates.
Current wording
In April 2025, Enbridge Gas North Carolina filed its first rates application since 2021 with the North Carolina Utilities Commission. This rate case proposed the recovery of costs to deliver natural gas to customers and investments in infrastructure to support service reliability and customer growth. Enbridge Gas North Carolina proposed a total revenue requirement of US$854 million.
Previous wording
On May 1, 2025, Enbridge Gas Utah filed its first rates application since 2022 with the Utah Public Service Commission. This rate case aims to reflect the costs of delivering natural gas to customers and recover investments in infrastructure to support service reliability and customer growth. Enbridge Gas Utah is proposing a 9.5% increase to its residential natural gas rates.
Current wording
In May 2025, Enbridge Gas Utah filed its first rates application since 2022 with the Utah Public Service Commission. This rate case proposed the recovery of costs to deliver natural gas to customers and investments in infrastructure to support service reliability and customer growth. Enbridge Gas Utah proposed a total revenue requirement of US$657 million. On September 26, 2025, Enbridge Gas Utah filed a settlement reflecting a revenue increase of US$62 million and a total revenue requirement of US$604 million. A decision on the filing is expected before the end of the year with new rates expected to take effect on January 1, 2026.
Previous wording
In July 2025, Enbridge Gas Ontario and Enbridge Pipelines Inc. extended the maturity dates of their $2.5 billion and $2.0 billion 364-day extendible credit facilities, respectively, to July 2027, which includes a one-year term out provision from July 2026.
Current wording
In July 2025, Enbridge Gas Ontario and Enbridge Pipelines Inc. extended the maturity dates of their $2.5 billion and $2.0 billion 364-day extendible credit facilities, respectively, to July 2027, which includes one-year term out provisions from July 2026.
Previous wording
As at June 30, 2025, after adjusting for the impact of floating-to-fixed interest rate swap hedges, approximately 7% of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements -Note 10. Risk Management and Financial Instrumentsfor more information on our interest rate hedging program.
Current wording
As at September 30, 2025, after adjusting for the impact of floating-to-fixed interest rate swap hedges, approximately 8% of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements -Note 12. Risk Management and Financial Instrumentsfor more information on our interest rate hedging program.
Previous wording
the absence in 2025 of a deferred tax recovery of $82 million due to change in state apportionment as a result of the Acquisitions; and
Current wording
the absence in 2025 of a deferred tax recovery of $59 million due to a change in state apportionment as a result of the acquisition of Public Service Company of North Carolina, Incorporated (PSNC).
Previous wording
After taking into consideration the factors above, the remaining $457 million increase in earnings attributable to common shareholders is primarily explained by:
Current wording
After taking into consideration the factors above, the remaining $197 million decrease in earnings attributable to common shareholders is primarily explained by:
Previous wording
higher depreciation and amortization expense mainly driven by a full quarter ownership of the acquired US Gas Utilities;
Current wording
higher depreciation and amortization expense mainly driven by a full quarter ownership of Enbridge Gas North Carolina and other assets placed into service after Q3 2024; and
Previous wording
lower contributions from the Gulf Coast and Mid-Continent System in our Liquids Pipelines segment due to lower spot volumes on the Flanagan South and Spearhead Pipelines.
Current wording
lower contributions from the Flanagan South and Spearhead Pipelines of the Gulf Coast and Mid-Continent System in our Liquids Pipelines segment.
Previous wording
higher contributions from our Gas Transmission segment primarily due to favorable contracting and lower operating costs on our US Gas Transmission assets and recognition of increased revenue attributable to Algonquin and Texas Eastern rate case settlements;
Current wording
higher contributions from our Gas Transmission segment primarily due to recognition of increased revenue attributable to Algonquin and Texas Eastern rate case settlements, contributions from the Texas Eastern Venice Extension project, and favorable contracting and lower operating costs on our US Gas Transmission assets; and
Previous wording
Earnings attributable to common shareholders were positively impacted by $159 million due to certain infrequent or other non-operating factors, primarily explained by the following:
Current wording
Earnings attributable to common shareholders were positively impacted by $300 million due to certain infrequent or other non-operating factors, primarily explained by the following:
Previous wording
a non-cash, net unrealized derivative fair value gain of $1.4 billion ($1.0 billion after-tax) in 2025, compared with a net unrealized loss of $208 million ($160 million 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;
Current wording
a non-cash, net unrealized derivative fair value gain of $944 million ($742 million after-tax) in 2025, compared with a net unrealized loss of $773 million ($586 million 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;
Previous wording
the absence in 2025 of a deferred tax recovery of $82 million due to change in state apportionment as a result of the Acquisitions.
Current wording
the absence in 2025 of a deferred tax recovery of $141 million due to a change in state apportionment as a result of the Acquisitions.
Previous wording
After taking into consideration the factors above, the remaining $170 million increase in earnings attributable to common shareholders is primarily explained by:
Current wording
After taking into consideration the factors above, the remaining $260 million increase in earnings attributable to common shareholders is primarily explained by:
Previous wording
higher contributions from our Gas Transmission segment primarily due to favorable contracting in our US Gas Transmission assets, and the recognition of increased revenue attributable to Algonquin and Texas Eastern rate case settlements.
Current wording
higher contributions from our Gas Transmission segment primarily due to the recognition of increased revenue attributable to Algonquin and Texas Eastern rate case settlements, favorable contracting in our US Gas Transmission assets, and contributions from the Texas Eastern Venice Extension project; and
Previous wording
higher contributions from our Liquids Pipelines segment due to equity earnings related to a litigation settlement and higher contributions from Mainline System due to higher tolls and operational efficiencies; and
Current wording
equity earnings related to a litigation settlement in our Liquids Pipelines segment.
Previous wording
higher interest expense primarily due to higher average debt balances principal outstanding; and
Current wording
higher interest expense primarily due to higher average debt balances principal outstanding;
Previous wording
higher depreciation and amortization expense mainly driven by two full quarters' ownership of the acquired US Gas Utilities;
Current wording
higher depreciation and amortization expense mainly driven by three full quarters' ownership of the US Gas Utilities;
Previous wording
higher realized foreign exchange losses on hedge settlements in Eliminations and Other;
Current wording
lower interest income due to investing in 2024, cash sources from the pre-funding of the Acquisitions in Eliminations and Other;
Previous wording
lower contributions from the Gas Transmission segment due to the sale of our interests in Alliance Pipeline and Aux Sable in April 2024.
Current wording
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 production facilities due to lower Renewable Identification Number (RIN) pricing and timing of RIN sales.
Previous wording
a non-cash, net unrealized gain of $38 million in 2025, compared with a net unrealized loss of $6 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks; partially offset by
Current wording
a non-cash, net unrealized gain of $54 million in 2025, compared with a net unrealized gain of $20 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks; partially offset by
Previous wording
a net negative adjustment to crude oil inventory of $6 million in 2025, compared with a net positive adjustment of $15 million in 2024.
Current wording
a net negative adjustment to crude oil inventory of $13 million in 2025, compared with a net positive adjustment of $3 million in 2024.
Previous wording
higher Mainline System contributions as a result of annual escalators and surcharge effective July 1, 2024 and lower power costs from operational efficiencies and lower mill rates, net of lower demand; and
Current wording
higher Mainline System contributions 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; and
Previous wording
favorable contracting and lower operating costs on our US Gas Transmission assets;
Current wording
favorable contracting and lower operating costs on our US Gas Transmission assets; partially offset by
Previous 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
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; and
Previous wording
the absence in 2024 of a non-cash, net unrealized gain of $40 million, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks;
Current wording
a non-cash, net unrealized loss of $30 million in 2025, compared with a net unrealized loss of $4 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks; partially offset by
Previous wording
a net positive adjustment of $23 million in 2025 to the gas inventory at Aitken Creek compared to a net negative adjustment of $29 million in 2024; and
Current wording
a net positive adjustment of $25 million in 2025 to the gas inventory at Aitken Creek compared to a net negative adjustment of $47 million in 2024;
Previous wording
the absence in 2025 of a loss of $25 million as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV.
Current wording
the absence in 2025 of a loss of $29 million as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV; and
Previous wording
contributions from the acquisition of equity interests in the Whistler Parent JV and in the Delaware Basin Residue in the second and fourth quarters of 2024, respectively;
Current wording
contributions from the acquisition of equity interests in the Whistler Parent JV and the Delaware Basin Residue in the second and fourth quarters of 2024, respectively, and the Matterhorn Express Pipeline in the second quarter of 2025;
Previous wording
the absence of 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
two full quarters of contributions from the acquired US Gas Utilities including Enbridge Gas Ohio, Enbridge Gas Utah and Enbridge Gas North Carolina;
Current wording
three full quarters of contributions from the US Gas Utilities;
Previous wording
when compared with the normal forecast embedded in rates, the positive impact of weather on EBITDA for Enbridge Gas Ontario was approximately $10 million in 2025, compared to a negative impact of approximately $28 million in the same period of 2024.
Current wording
when compared with the normal forecast embedded in rates, the positive impact of weather on EBITDA for Enbridge Gas Ontario was approximately $20 million in 2025 compared to a negative impact of approximately $105 million in the same period of 2024;
Previous wording
a non-cash, net unrealized gain of $2 million in 2025, compared with a net unrealized loss of $25 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.
Current wording
EBITDA was negatively impacted by $27 million primarily explained by a non-cash, net unrealized gain of $2 million in 2025, compared with a net unrealized gain of $28 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
the absence in 2025 of a gain on sale of $29 million related to the disposition of our interest in NRGreen.
Current wording
the absence in 2025 of a gain on sale of $29 million related to the disposition of our interest in NRGreen; and
Showing the first 40 of 75 pairs. Open the source sections for the rest.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
lower contributions from the Gulf Coast and Mid-Continent System due to lower spot volumes on the Flanagan South and Spearhead Pipelines; and
Current report — wording carried from elsewhere
The notes carried an original maturity date in October 2025.
Rearranged previous paragraphs (18)
Previous report — wording carried elsewhere
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;
Previous report — wording carried elsewhere
positive earnings impact in Enbridge Gas Ontario in our Gas Distribution and Storage segment due to higher storage optimization and pricing, higher distribution margin, and colder weather in 2025 compared to a negative impact in 2024.
Previous report — wording carried elsewhere
Earnings attributable to common shareholders were positively impacted by $714 million due to certain infrequent or other non-operating factors, primarily explained by the following:
Previous report — wording carried elsewhere
lower contributions from the Bakken System due to lower volumes.
Previous report — wording carried elsewhere
the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to the same period in 2024.
Previous report — wording carried elsewhere
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 report — wording carried elsewhere
the absence in 2025 of a loss of $25 million as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV.
Previous report — wording carried elsewhere
contributions from the acquisition of equity interests in the Whistler Parent JV and in the Delaware Basin Residue in the second and fourth quarters of 2024, respectively;
Previous report — wording carried elsewhere
higher earnings from our investment in DCP; and
Previous report — wording carried elsewhere
EBITDA was negatively impacted by $330 million due to an impairment 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.
Previous report — wording carried elsewhere
when compared with the normal forecast embedded in rates, the positive impact of weather on EBITDA for Enbridge Gas Ontario was approximately $19 million in 2025 compared to a negative impact of approximately $106 million in the same period of 2024;
Previous report — wording carried elsewhere
higher storage optimization and pricing at Enbridge Gas Ontario; and
Previous report — wording carried elsewhere
higher distribution margin resulting from increases in rates and customer base at Enbridge Gas Ontario.
Previous report — wording carried elsewhere
the absence in 2025 of a gain on sale of $29 million related to the disposition of our interest in NRGreen; partially offset by
Previous report — wording carried elsewhere
The remaining $27 million decrease is primarily explained by:
Previous report — wording carried elsewhere
lower contributions from European offshore wind facilities.
Previous report — wording carried elsewhere
EBITDA was positively impacted by $2.4 billion, primarily due to certain infrequent or non-operating factors, explained by:
Previous report — wording carried elsewhere
On July 28, 2025, EEP redeemed at par all of the outstanding US$500 million 5.88% senior notes that carried an original maturity date in October 2025.