ENBRIDGE INC

CONSOLIDATED STATEMENTS OF EARNINGS

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

CONSOLIDATED STATE MENTS OF CASH FLOWS

1 As at September 30, 2025 and December 31, 2024, long-term restricted cash of$141 million (September 30, 2024 -$94 million) and$105 million (December 31, 2023 -nil), respectively, was included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

Variable Interest Entities (VIEs)(Note 7)

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2024. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2024. Amounts are stated in Canadian dollars unless otherwise noted.

Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as supply of and demand for crude oil and natural gas and may not be indicative of annual results.

Certain comparative figures in our interim consolidated financial statements have been reclassified to conform to the current year's presentation.

2. CHANGES IN ACCOUNTING POLICIES

The following policy became significant to Enbridge on July 2, 2025:

Noncontrolling Interests

Noncontrolling interests (NCI) represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as NCI within the equity section of the Consolidated Statements of Financial Position and, in the case of Redeemable NCI, within the mezzanine equity section of the Consolidated Statements of Financial Position between long-term liabilities and equity.

Westcoast Energy Limited Partnership’s (Westcoast LP) Class A noncontrolling unitholder has the option, exercisable at any time from and after July 2, 2035, to require the Class B and Class C unitholders of Westcoast LP to redeem all of the Class A units for cash at the then-current fair value, subject to certain limitations. On a quarterly basis, the Redeemable NCI carrying amount is recognized at the higher of the amount resulting from the application of Accounting Standards Codification (ASC) 810 Consolidationand the estimated current redemption value, with measurement adjustments to the carrying amount of Redeemable NCI recognized in retained earnings. The measurement adjustments to Redeemable NCI that are recognized in retained earnings impact our earnings per common share(Note 5).

FUTURE ACCOUNTING POLICY CHANGES

Income Tax Disclosures

Accounting Standards Update (ASU) 2023-09 was issued in December 2023 to improve income tax disclosures by requiring specified categories in the annual rate reconciliation that meet quantitative thresholds and further disaggregation on income taxes paid by jurisdiction. ASU 2023-09 is effective January 1, 2025 and should be applied prospectively, with retrospective application being permitted. The effects of the new standard on the presentation of our income tax note disclosures will be reflected in our December 31, 2025 annual consolidated financial statements.

Disaggregation of Income Statement Expenses

ASU 2024-03 was issued in November 2024 to improve financial reporting by requiring entities to disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. The ASU requires entities to disclose 1) the amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, (e) depreciation, depletion and amortization recognized as part of oil and gas producing activities, (f) expense reimbursements included in a relevant expense caption, and (g) selling expenses, and 2) a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. ASU 2024-03 is effective January 1, 2027, with interim period disclosure requirements effective after January 1, 2028 and can be applied either prospectively or retrospectively. We are currently assessing the impact of the new standard on our annual disclosures for the year ending December 31, 2027 and on our interim disclosures beginning in 2028.

3. REVENUE

Change in Revenue Classification

To better align the classification of revenues resulting from our acquisitions of the United States (US) Gas Utilities(Note 6), we have made adjustments to Gas distribution sales and Transportation and other services revenues. Revenues generated from customers who procure their own gas but use our distribution system for delivery to the end use location have been reclassified to Gas distribution sales revenue from Transportation and other services revenue on the Consolidated Statements of Earnings and reclassified to Gas distribution sales from Transportation revenue in the Revenue from Contracts with Customers tables below. Our prior period comparable results have been recast to reflect the change in revenue classification. This change did not have an impact on our Total operating revenues.

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services

Includes realized and unrealized gains and losses from our hedging program which for the three months ended September 30, 2025 were a net$13 million gain (2024 -$54 million gain) and for the nine months ended September 30, 2025 were a net$145 million gain (2024 -$15 million gain).

Includes revenues from lease contracts for the three months ended September 30, 2025 and 2024 of$116 million and$125 million, respectively, and for the nine months ended September 30, 2025 and 2024 of$415 million and$407 million, respectively.

These balances reflect a transfer from Transportation revenue to Gas distribution sales of$389 million and$1.1 billion for the three and nine months ended September 30, 2024, respectively.

We disaggregate revenues into categories which represent our principal performance obligations within each business segment. These revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.

Contract Balances

Contract receivables represent the amount of receivables derived from contracts with customers.

Contract assets represent the amount of revenues which have been recognized in advance of payments received for performance obligations we have fulfilled (or have partially fulfilled) and prior to the point in time at which our right to payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to receive the consideration becomes unconditional.

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenues. Revenue recognized during the three and nine months ended September 30, 2025 included in contract liabilities at the beginning of the period were$91 million and$380 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and nine months ended September 30, 2025 were$224 million and$435 million, respectively.

Performance Obligations

There were no material revenues recognized in the three and nine months ended September 30, 2025 from performance obligations satisfied in previous periods.

Revenues to be Recognized from Unfulfilled Performance Obligations

Total revenues from performance obligations expected to be fulfilled in future periods is$59.1 billion, of which$2.6 billion and$8.3 billion are expected to be recognized during the remaining three months ending December 31, 2025 and theyear ending December 31, 2026, respectively.

The revenues excluded from the amounts above based on optional exemptions available under ASC 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for revenues to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.

Recognition and Measurement of Revenues

Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

4. SEGMENTED INFORMATION

Refer to Note 3 - Revenue for a reconciliation of segment Operating revenues to the Consolidated Statements of Earnings.

The Gas Distribution and Storage segment includes the impact of an impairment recognized for certain rate-regulated assets related to pension and other disallowances as a result of the Public Utilities Commission of Ohio's (Ohio Commission) June 2025 order related to Enbridge Gas Ohio's rate case.

Capital Expenditures 1

Capital expenditures are cash basis plus equity component of the allowance for funds used during construction.

Property, Plant and Equipment

5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

NUMERATOR

The numerator used in calculating both basic and diluted earnings per share equals Earnings attributable to common shareholders per the Consolidated Statements of Earnings, less Redemption value adjustment attributable to redeemable NCI per the Consolidated Statements of Changes in Equity.

DENOMINATOR

The denominator of the basic earnings per common share calculation represents the weighted average number of common shares outstanding.

The denominator of the diluted earnings per common share calculation uses the treasury stock method to determine the dilutive impact of stock options and share-settled RSUs. This method assumes any proceeds from the exercise of stock options and vesting of share-settled RSUs would be used to purchase common shares at the average market price during the period. The basic weighted average shares outstanding are adjusted by this dilutive impact to derive the diluted weighted average shares outstanding.

Weighted average shares outstanding used to calculate basic and diluted earnings per common share are as follows:

For the three months ended September 30, 2024,15.2 million of anti-dilutive stock options with a weighted average exercise price of$55.56 were excluded from the diluted earnings per common share calculation. There wereno anti-dilutive stock options outstanding for the three months ended September 30, 2025.

For the nine months ended September 30, 2025 and 2024,1.6 million and 18.7 million, respectively, of anti-dilutive stock options with a weighted average exercise price of$60.37 and$54.18, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

The Board of Directors has declared the following quarterly dividends. All dividends are payable on December 1, 2025 to shareholders of record on November 14, 2025.

The quarterly dividend per share paid on Preference Shares, Series G was decreased to$0.32411 from$0.32515 on September 1, 2025 due to the reset of the dividend on a quarterly basis.

The quarterly dividend per share paid on Preference Shares, Series I was decreased to$0.29980 from$0.30058 on September 1, 2025 due to the reset of the dividend on a quarterly basis.

The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to$0.31601 from$0.31696 on September 1, 2025 due to the reset of the dividend on a quarterly basis.

The quarterly dividend per share paid on Preference Shares, Series 15 was increased to$0.35163 from$0.18644 on September 1, 2025 due to the reset of the annual dividend on September 1, 2025.

6. ACQUISITIONS AND DISPOSITIONS

BUSINESS COMBINATIONS

We accounted for each of the acquisitions discussed below using the acquisition method as prescribed by ASC 805 Business Combinations. In accordance with valuation methodologies described in ASC 820 Fair Value Measurement, acquired assets and assumed liabilities are recorded at their estimated fair values as at the date of acquisition.

The fair values of regulatory assets and liabilities, which are subject to rate-setting and cost recovery mechanisms under ASC 980 Regulated Operations, are equal to their carrying values at acquisition. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator's actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded at acquisition.

Public Service Company of North Carolina, Incorporated

On September 30, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall North Carolina Holdco LLC, which owns 100% of Public Service Company of North Carolina, Incorporated (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. Subsequent to its acquisition, PSNC conducts business as Enbridge Gas North Carolina.

The following table summarizes the estimated fair values that were assigned to the net assets of PSNC:

In the fourth quarter of 2024, immaterial adjustments were made to the PSNC Acquisition purchase price allocation.

a)

Current assets consist primarily of cash, trade and other accounts receivable, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $70 million due to the short period to maturity. A provision of $2 million for expected credit loss associated with accounts receivable has been recorded.

b)

PSNC's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, distribution and storage assets. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value.

c)

Long-term assets consist primarily of $114 million of regulatory assets expected to be recovered from customers in future periods through rates and equity interests in a liquefied natural gas (LNG) storage facility in North Carolina and in an intrastate natural gas pipeline.

d)

The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar yield, credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $156 million withno corresponding regulatory offset.

e)

Other long-term liabilities consist primarily of regulatory liabilities expected to be refunded to customers in future periods through rates.

f)

Goodwill is primarily attributable to the existing assembled assets and workforce of PSNC that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible.

Upon completion of the PSNC Acquisition, we began consolidating PSNC.

Our supplemental pro forma consolidated financial information for the three and nine months ended September 30, 2024, including the results of operations for PSNC as if the PSNC Acquisition had been completed on January 1, 2023, was as follows:

Questar Gas Company

On May 31, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall West Holdco LLC which owns 100% of Questar Gas Company (Questar) and its related Wexpro companies (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, the Wyoming Public Service Commission and the Idaho Public Utilities 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.

The following table summarizes the estimated fair values that were assigned to the net assets of Questar and Wexpro:

In the fourth quarter of 2024, immaterial adjustments were made to the Questar Acquisition purchase price allocation.

a)

Current assets consist primarily of cash, trade and other accounts receivable and inventory. The fair value of trade receivables from customers approximates their carrying value of $202 million due to the short period to maturity. A provision of $9 million for expected credit loss associated with accounts receivable has been recorded.

b)

Questar's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, distribution and storage assets. Wexpro's property, plant and equipment consists of cost-of-service gas and oil properties developed and produced for Questar. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value.

c)

Long-term assets consist primarily of funds collected from Questar by Wexpro and held in trust to fund future asset retirement obligations (ARO), as well as regulatory assets expected to be recovered from customers in future periods through rates.

d)

The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $301 million withno corresponding regulatory offset.

e)

Other long-term liabilities consist primarily of regulatory liabilities, expected to be refunded to customers in future periods through rates, as well as ARO. The fair value of the ARO liability was determined using a discounted cash flow approach.

f)

Goodwill is primarily attributable to the existing assembled assets and workforce of Questar and Wexpro that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible.

Upon completion of the Questar Acquisition, we began consolidating Questar and Wexpro. For the period beginning May 31, 2024 through to September 30, 2024, operating revenues and earnings attributable to common shareholders generated by Questar and Wexpro were immaterial.

Our supplemental pro forma consolidated financial information for the three and nine months ended September 30, 2024, including the results of operations for Questar and Wexpro as if the Questar Acquisition had been completed on January 1, 2023, was as follows:

The East Ohio Gas Company

On March 6, 2024, through a wholly-owned US subsidiary, we acquired all of the outstanding shares of capital stock of The East Ohio Gas Company (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 Ohio Commission. Subsequent to its acquisition, EOG conducts business as Enbridge Gas Ohio.

The following table summarizes the estimated fair values that were assigned to the net assets of EOG:

In the fourth quarter of 2024, immaterial adjustments were made to the EOG Acquisition purchase price allocation.

a)

Current assets consist primarily of trade and other accounts receivable, prepaid expenses, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $379 million due to the short period to maturity. A provision of $3 million for expected credit loss associated with accounts receivable has been recorded.

b)

EOG's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, gathering, distribution and storage assets. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value.

c)

Long-term assets consist primarily of overfunded pension plan assets of $367 million and $1.2 billion of regulatory assets expected to be recovered from customers in future periods through rates.

Pension plan assets attributable to the workforce acquired from EOG were transferred in cash to an Enbridge-sponsored pension plan based on their fair value as at March 6, 2024. The fair value of plan assets was determined using unadjusted quoted market prices for identical investments.

d)

The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $478 million withno corresponding regulatory offset.

e)

Other long-term liabilities consist primarily of regulatory liabilities expected to be refunded to customers in future periods through rates.

f)

Goodwill is primarily attributable to the existing assembled assets and workforce of EOG that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible.

Upon completion of the EOG Acquisition, we began consolidating EOG. For the period beginning March 6, 2024 through to September 30, 2024, EOG generated $751 million of operating revenues and $170 million of earnings attributable to common shareholders.

Our supplemental pro forma consolidated financial information for thethree and nine months ended September 30, 2024, including the results of operations for EOG as if the EOG Acquisition had been completed on January 1, 2023, was as follows:

The PSNC Acquisition, Questar Acquisition and EOG Acquisition (together, the Acquisitions) further diversify, and are complementary to, our existing gas distribution operations.

Acquisition of RNG Facilities

On January 2, 2024, through a wholly-owned US subsidiary, we acquiredsix Morrow Renewables operating landfill gas-to-renewable natural gas (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 withintwo years with a fair value of $757 million (US$568 million) (the RNG Facilities Acquisition). The acquired assets align with and advance our lower-carbon strategy.

The following table summarizes the estimated fair values that were assigned to the net assets of Tomorrow RNG:

a)

Intangible assets consist of long-term gas supply agreements with the respective facility's landfill owner. Fair value was determined using an income-based approach, specifically the multi-period excess earnings method, by estimating the present value of the after-tax cash flows attributable to the gas rights. The intangible assets will be amortized on a straight-line basis over the term of the respective agreement, inclusive of extension options, which range from 13 to 42 years (approximately nine years to the next extension period on a weighted-average basis).

b)

Tomorrow RNG's property, plant and equipment constitutes specialized landfill gas plant and equipment which collects gas produced by waste decomposition, treats and compresses the gas to pipeline specifications. The direct method of replacement cost was used to determine the majority of the fair value of property, plant and equipment. Adjustments were then applied for estimated physical deterioration.

c)

Goodwill is primarily attributable to expected future returns from a portfolio of both operating and scalable RNG assets, furthering the diversity of our renewable projects portfolio and accelerating progress toward our energy transition goals. The goodwill balance recognized has been assigned to our Gas Transmission segment and is tax deductible over 15 years.

d)

We entered intosix non-interest bearing promissory notes due to Morrow Renewables, the total value of which represents deferred payments of $808 million (US$606 million) due withintwo years. The first payment was made on January 2, 2025 and the second payment is due on December 31, 2025. The $757 million (US$568 million) recognized in the purchase price represents the fair value of deferred consideration at the date of acquisition using the imputed interest rate method over the terms of the notes.

Upon completion of the RNG Facilities Acquisition, we began consolidating Tomorrow RNG. For the period beginning January 2, 2024 through to September 30, 2024, operating revenues and earnings attributable to common shareholders generated by Tomorrow RNG were immaterial. The impact to our supplemental pro forma consolidated operating revenues and earnings attributable to common shareholders for the three and nine months ended September 30, 2024, as if the RNG Facilities Acquisition had been completed on January 1, 2023, was also immaterial.

NONCONTROLLING INTEREST INVESTMENT

On July 1, 2025, Westcoast Energy Inc. (Westcoast) completed a reorganization in which substantially all of the property and assets relating to the British Columbia (BC) Pipeline system were transferred to a newly formed partnership, Westcoast LP. On July 2, 2025, Stonlasec8 Indigenous Investments Limited Partnership (the First Nations Partnership) invested approximately $736 million to subscribe for all of the Class A units of Westcoast LP, resulting in a 12.5% interest in the partnership. The cash consideration of $736 million and a respective Redeemable NCI based on the consideration received less transaction costs were recorded in the Consolidated Statements of Financial Position on close, to reflect the interest held by the First Nations Partnership. Subsequent to the First Nations Partnership's investment, we hold an 87.5% controlling interest in Westcoast LP and continue to manage and operate the BC Pipeline system. Refer to Note 7 - Variable Interest Entities and Note 9 - Redeemable Noncontrolling Interest.

DISPOSITION

Disposition of Alliance Pipeline and Aux Sable Interests

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 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 nine months ended September 30, 2024. Our equity investments in the Alliance Pipeline and Aux Sable were previously included in our Gas Transmission segment. Our equity investment in NRGreen was previously included in our Renewable Power Generation segment.

EQUITY INVESTMENT TRANSACTIONS

Joint Venture with WhiteWater/I Squared and MPLX

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 plans to develop, construct, own and operate natural gas pipeline and storage assets connecting Permian Basin natural gas supply to growing 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 is accounted for as an equity method investment.

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 the Whistler Parent JV, which was redeemed on July 17, 2025 for net proceeds of $180 million (US$130 million). 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.

The contribution of our interest in the Rio Bravo Pipeline project to the Whistler Parent JV in exchange for the equity interests discussed above represents a non-cash transaction in Cash Flows from Investing Activities and does not have an effect on our Consolidated Statements of Cash Flows. This component of the transaction resulted in a reduction of $321 million (US$235 million) to Property, plant and equipment, net and a corresponding increase to Long-term investments in the Consolidated Statements of Financial Position. The cash component of the transaction, as well as subsequent cash payments made for post-closing mandatory capital expenditures, have been reflected as contributions in Cash Flows from Investing Activities.

7. VARIABLE INTEREST ENTITIES

CONSOLIDATED VARIABLE INTEREST ENTITIES

Our consolidated VIEs consist of legal entities of which we are the primary beneficiary. We are the primary beneficiary when our variable interest(s) provide(s) us with (i) the power to direct the activities of the VIE that most significantly impact the entity's economic performance and (ii) the obligation to absorb losses, or the right to receive benefits, from the VIE that could potentially be significant to the VIE. We determine whether we are the primary beneficiary of a VIE by considering qualitative and quantitative factors, including, but not limited to: decision-making responsibilities, the VIE capital structure, risk and reward sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties.

Westcoast LP is a BC limited partnership which holds and operates our Westcoast BC Pipeline system, serving customers in western Canada and the US Pacific Northwest. The limited partners, Westcoast and the First Nations Partnership, hold 87.49% and 12.5% interests in Westcoast LP, respectively. The remaining 0.01% general partner interest is held by Westcoast Energy GP Inc., a wholly-owned subsidiary.

Westcoast LP is considered a VIE as its limited partners lack substantive participating rights and kick-out rights. In addition to having the obligation to absorb losses and the right to expected returns, we, through Westcoast’s direct interests and the operating agreement between Westcoast and Westcoast LP, have the ability to direct the activities of Westcoast LP's principal operations, thereby making us the primary beneficiary of the VIE.

The following table includes assets only to be used to settle the liabilities of Westcoast LP. The

creditors of the liabilities of Westcoast LP do not have recourse to us as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.

On July 2, 2025, we entered into a credit agreement with Westcoast LP, pursuant to which we provided a one-year non-revolving term credit facility of up to $100 million. As at September 30, 2025, there have been no drawdowns on the credit facility. We did not provide any other financial support to Westcoast LP during the period ended September 30, 2025.

8. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at September 30, 2025:

Maturity date is inclusive of the one-year term out option for certain credit facilities.

Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

In July 2025, we renewed approximately$8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2027, which includes aone-year term out provision from July 2026. We also renewed approximately$7.8 billion of ourfive-year credit facilities, extending the maturity dates to July 2030. Further, we extended the maturity dates of ourthree-year credit facilities to July 2028.

In July 2025, Enbridge Gas Inc. (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 includesone-year term out provisions from July 2026.

In addition to the committed credit facilities noted above, we maintain$1.6 billion of uncommitted demand letter of credit facilities, of which$994 million was unutilized as at September 30, 2025. As at December 31, 2024, we had$1.4 billion of uncommitted demand letter of credit facilities, of which$931 million was unutilized.

Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to our commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2027 to 2049.

As at September 30, 2025 and December 31, 2024, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of$11.7 billion and $10.3 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES

During thenine months ended September 30, 2025, we completed the following long-term debt issuances totaling$4.6 billion and US$2.8 billion:

Notes carry an interest rate set to equal the Canadian Overnight Repo Rate Average plus a margin of 85 basis points.

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%.

LONG-TERM DEBT REPAYMENTS

During thenine months ended September 30, 2025, we completed the following long-term debt repayments totaling US$3.0 billion,$2.0 billion and€21 million:

The notes carried an original maturity date in July 2112.

The notes carried an original maturity date in October 2025.

SUBORDINATED TERM NOTES

As at September 30, 2025 and December 31, 2024, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of$16.1 billion and $15.5 billion, respectively.

FAIR VALUE ADJUSTMENT

As at September 30, 2025 and December 31, 2024, the fair value adjustments to decrease total debt assumed in historical acquisitions were$440 million and$468 million, respectively.

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at September 30, 2025, we were in compliance with all such debt covenant provisions.

9. REDEEMABLE NONCONTROLLING INTEREST

The First Nations Partnership has the option, exercisable at any time from and after July 2, 2035, to require the Class B and Class C unitholders of Westcoast LP to redeem all of the Class A units for cash at the then-current fair value, subject to certain limitations. As a result of this redemption feature, we have classified the Class A units as Redeemable NCI within the mezzanine equity section of the Consolidated Statements of Financial Position. As at September 30, 2025, the outstanding Class B and Class C units of Westcoast LP are held by us.

Designated capital programs within Westcoast LP will be funded by us in exchange for Class C units. The Class C units will not have any economic or voting entitlements until after the respective program has been completed or substantially completed. Following completion or substantial completion, the First Nations Partnership has an option to purchase the respective Class C units up to its then-current ownership interest in Westcoast LP.

The changes in our Redeemable NCI were as follows:

10. SHARE CAPITAL

On May 15, 2024, we filed prospectus supplements in Canada and the US to establish an at-the-market equity issuance program (the ATM Program) that allowed us to issue and sell, at our discretion, up to $2.75 billion (or the US dollar equivalent) of our common shares from treasury to the public from time to time at the market prices prevailing at the time of sale through the Toronto Stock Exchange, the New York Stock Exchange or any other marketplace in Canada or the US where the common shares may be traded.

During the period from May 15, 2024 to July 31, 2024,51,298,629 common shares were issued and sold under the ATM Program at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.50 billion ($2.48 billion, net of aggregate commissions paid of $16.3 million and other issuance costs). On August 1, 2024, we terminated the ATM Program. Net proceeds from sales of common shares under the ATM Program were used to partially fund the Questar Acquisition and the PSNC Acquisition and to pay related fees and expenses.

11. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

Changes in Accumulated other comprehensive income (AOCI) attributable to our common shareholders for thenine months ended September 30, 2025 and 2024 are as follows:

Reported within Interest expense and Other income/(expense) in the Consolidated Statements of Earnings.

These components are included in the computation of net periodic benefit credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

Reported within Transportation and other services revenues in the Consolidated Statements of Earnings.

12. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

Our earnings, cash flows and other comprehensive income/(loss) (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risks). Formal risk management policies, processes and systems have been designed to mitigate these risks.

The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.

Foreign Exchange Risk

We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.

We employ financial derivative instruments to hedge foreign currency-denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency-denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in US dollar-denominated investments and subsidiaries using US dollar-denominated debt.

Interest Rate Risk

Our earnings, cash flows and OCI are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We have a policy of limiting the maximum floating rate debt to 30% of total debt outstanding. To ensure compliance with our policy, we monitor and adjust our debt portfolio mix of fixed and variable rate debt instruments in conjunction with the use of derivative instruments. We have implemented a program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps and costless collars. These swaps have an average fixed rate of 2.8%.

We are exposed to changes in the fair value of fixed rate debt that arise as a result of changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in fair value. Executed fixed-to-floating interest rate swaps have an average swap rate of 2.8%.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. A combination of qualifying and non-qualifying forward starting interest rate swaps is used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via execution of floating-to-fixed interest rate swaps with an average swap rate of 3.5%.

Commodity Price Risk

Our earnings, cash flows and OCI are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy marketing subsidiaries. These commodities include natural gas, crude oil, power and natural gas liquids (NGL). We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. For our US Gas Utilities, changes in derivatives' fair values are deferred as regulatory assets or liabilities until settlement. We use primarily non-qualifying derivative instruments to manage commodity price risk.

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through the revaluation of outstanding units every period.

TOTAL DERIVATIVE INSTRUMENTS

We have a policy of entering into individual International Swaps and Derivatives Association, Inc. (ISDA) agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions in those circumstances.

The following tables summarize the Consolidated Statements of Financial Position location and carrying value of our derivative instruments, as well as the maximum potential settlement amounts, in the event of the specific circumstances described above.

The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments:

Represents the notional amount of long-term debt issuances hedged.

Represents the notional amount of net purchase/(sale).

Total is an average net purchase/(sale) of power.

Derivatives Designated as Fair Value Hedges

The following table presents interest rate and foreign exchange derivative instruments that are designated and qualify as fair value hedges. The realized and unrealized gain or loss on the derivative is included in Other income/(expense) or Interest expense in the Consolidated Statements of Earnings. The offsetting loss or gain on the hedged item attributable to the hedged risk is included in Other income/(expense) or Interest expense in the Consolidated Statements of Earnings. Any excluded components are included in the Consolidated Statements of Comprehensive Income.

The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income

The following table presents the effect of cash flow hedges and fair value hedges on our consolidated earnings and comprehensive income, before the effect of income taxes:

Reported within Interest expense and Other income/(expense) in the Consolidated Statements of Earnings.

Reported within Transportation and other services revenues in the Consolidated Statements of Earnings.

We estimate that a loss of$1 million from AOCI related to open cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows istwo years as at September 30, 2025.

Non-Qualifying Derivatives

The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives:

Reported within Other income/(expense) in the Consolidated Statements of Earnings.

For the respective nine months ended periods, reported within Transportation and other services revenues (2025 -$101 million gain; 2024 -$14 million loss), Commodity sales (2025 -$46 million loss; 2024 -$91 million loss), Commodity costs (2025 -$206 million gain; 2024 -$103 million gain) and Operating and administrative expense (2025 -$21 million gain; 2024 -$33 million loss) in the Consolidated Statements of Earnings. The fair value change in our US Gas Utilities is deferred as regulatory assets/(liabilities) (2025 -$49 million gain; 2024 -$14 million gain).

Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

LIQUIDITY RISK

Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. Our shelf prospectuses with securities regulators enable ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximatelyone year without accessing the capital markets. We were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at September 30, 2025. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities. We also identify other potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.

CREDIT RISK

Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through the maintenance and monitoring of credit exposure limits, contractual requirements and netting arrangements. We also review counterparty credit exposure using external credit rating services and other analytical tools to manage credit risk.

We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:

Other is comprised of commodity clearing house and crude oil, natural gas and power counterparties.

As at September 30, 2025, we did not provide any letters of credit in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We heldno cash collateral on derivative asset exposures as at September 30, 2025 and December 31, 2024.

Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation.

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, the assessment of counterparty credit ratings and netting arrangements. Within the Gas Distribution and Storage segment, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

FAIR VALUE MEASUREMENTS

Our financial assets and liabilities measured at fair value on a recurring basis include derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

FAIR VALUE OF FINANCIAL INSTRUMENTS

We categorize our financial instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

Level 1

Level 1 includes financial instruments measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a financial instrument is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Under the fair value hierarchy, cash and cash equivalents are classified as Level 1. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations, US and Canadian treasury bills, and investments in exchange-traded funds held by our captive insurance subsidiaries. We also have restricted long-term investments in exchange-traded funds and common shares held in trust in accordance with the regulatory requirements of the Canada Energy Regulator (CER) under the Land Matters Consultation Initiative (LMCI) and to cover future pipeline decommissioning costs in the state of Minnesota.

Level 2

Level 2 includes financial instrument valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Financial instruments in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the financial instrument. Derivatives valued using Level 2 inputs include non-exchange-traded derivatives such as over-the-counter foreign exchange forward and cross-currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.

We have also categorized the fair value of our long-term debt, investments in debt securities held by our captive insurance subsidiaries, and restricted long-term investments in Canadian government bonds held in trust in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our long-term debt is based on quoted market prices for instruments of similar credit risk and tenor. When possible, the fair value of our restricted long-term investments is based on quoted market prices for similar instruments and, if not available, based on broker quotes.

Level 3

Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivative's fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on the extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power, NGL and natural gas contracts, basis swaps, commodity swaps, and power and energy swaps, physical forward commodity contracts, as well as options. We do not have any other financial instruments categorized in Level 3.

We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third-party brokers. For non-exchange-traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread, as well as the credit default swap spreads associated with our counterparties, in our estimation of fair value.

Fair Value of Derivatives

We have categorized our derivative assets and liabilities measured at fair value as follows:

The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:

Financial and physical forward commodity contracts are valued using a market approach valuation technique.

One million British thermal units (mmbtu).

Commodity options contracts are valued using an option model valuation technique.

If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives.

Changes in the net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:

Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

There wereno transfers into or out of Level 3 as at September 30, 2025 or December 31, 2024.

Net Investment Hedges

We currently have designated a portion of our US dollar-denominated debt as a hedge of our net investment in US dollar-denominated investments and subsidiaries.

During the nine months ended September 30, 2025 and 2024, we recognized unrealized foreign exchange gains of$297 million and losses of$244 million, respectively, on the translation of US dollar-denominated debt, in OCI. During the nine months ended September 30, 2025 and 2024, we recognized realized losses of$81 million and$113 million, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.

Fair Value of Other Financial Instruments

Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled$188 million and$187 million as at September 30, 2025 and December 31, 2024, respectively.

We have restricted long-term investments and cash held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements under the LMCI, to cover future pipeline decommissioning costs in the state of Minnesota and to satisfy retirement obligations as Wexpro properties are abandoned. These investments are classified as available-for-sale, recognized at fair value and included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position. As at September 30, 2025, the fair value of investments in Level 1 and Level 2 was$838 million and$407 million, respectively (December 31, 2024 -$491 million and$507 million, respectively). Our Level 2 investments had a cost basis of$408 million as at September 30, 2025 (December 31, 2024 -$540 million). There were unrealized holding gains of$50 million and$96 million on these investments for the three and nine months ended September 30, 2025, respectively (2024 - gains of$46 million and$45 million, respectively). During the nine months ended September 30, 2025, we purchased and sold investments totaling$1.1 billion and$995 million, respectively (2024 - purchases of$319 million and sales of$240 million). The resulting net cash flow impact is presented under Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.

We have a wholly-owned captive insurance subsidiary whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. As at September 30, 2025, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiary wasnil and$1.2 billion, respectively (December 31, 2024 -$114 million and$1.1 billion, respectively). Our investments in debt securities had a cost basis of$1.1 billion as at September 30, 2025 and December 31, 2024. These investments in equity funds and debt securities are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, respectively, and are recorded in Other current assets and Long-term investments in the Consolidated Statements of Financial Position. There were unrealized holding gains ofnil and$1 million for the three and nine months ended September 30, 2025, respectively (2024 - gains of$14 million and$35 million, respectively).

As at September 30, 2025 and December 31, 2024, our long-term debt, including finance lease liabilities, had a carrying value before debt issuance costs of$102.9 billion and $101.6 billion, respectively, and a fair value of$101.7 billion and $98.9 billion, respectively.

The fair value of financial assets and liabilities other than derivative instruments, certain long-term investments in other entities, restricted long-term investments, investments held by our captive insurance subsidiaries and long-term debt described above approximate their carrying value due to the short period to maturity.

13. INCOME TAXES

The effective income tax rates for the three months ended September 30, 2025 and 2024 were 27.2% and 17.7%, respectively, and for the nine months ended September 30, 2025 and 2024 were 22.9% and 22.3%, respectively.

The period-over-period increase in the effective income tax rate for the three months ended was due to higher US minimum tax, the prior year tax benefits relating to the state apportionment income tax rate change due to the PSNC Acquisition(Note 6), and certain rate-regulated adjustments, partially offset by higher US investment tax credits relative to the decrease in earnings over the comparative periods.

The period-over-period increase in the effective income tax rates for the nine-months ended was due to higher US minimum tax, the prior year tax benefits relating to the state apportionment income tax rate change due to the Acquisitions(Note 6), the non-taxable portion of the gain on the prior year disposition of Alliance Pipeline and Aux Sable(Note 6), and certain rate-regulated adjustments, partially offset by higher US investment tax credits and the prior year write-down of non-deductible goodwill on the Gas Transmission segment relative to the increase in earnings over the comparative periods.

14. OTHER INCOME/(EXPENSE)

15. CONTINGENCIES

LITIGATION

We and our subsidiaries are subject to various legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our interim consolidated financial position or results of operations.

TAX MATTERS

We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

INSURANCE

We maintain an insurance program for us, our subsidiaries and certain of our affiliates to mitigate a certain portion of our risks. However, not all potential risks arising from our operations are insurable or are insured by us as a result of availability, high premiums and for various other reasons. We self-insure a significant portion of certain risks through our wholly-owned captive insurance subsidiaries, which requires certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices and the selection of estimated loss among estimates derived using different methods. Our insurance coverage is also subject to terms and conditions, exclusions and large deductibles or self-insured retentions which may reduce or eliminate coverage in certain circumstances.

Our insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, terms, policy limits and/or deductibles can vary substantially. We can give no assurance that we will be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable. In such cases, we may decide to self-insure additional risks.

In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among entities on an equitable basis based on an insurance allocation agreement we have entered into with us and other subsidiaries.