Enbridge Inc: Form 10-Q for the period ended Sep 30, 2024

INTRODUCTION

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our interim consolidated financial statements and the accompanying notes included in Part I. Item 1. Financial Statements of this quarterly report on Form 10-Q and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of our annual report on Form 10-K for the year ended December 31, 2023.

We continue to qualify as a foreign private issuer for purposes of the United States Securities Exchange Act of 1934, as amended (Exchange Act), as determined annually as of the end of our second fiscal quarter. We intend to continue to file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K with the United States (US) Securities and Exchange Commission (SEC) instead of filing the reporting forms available to foreign private issuers. We also intend to maintain our Form S-3 registration statements.

RECENT DEVELOPMENTS

ACQUISITIONS

US Gas Utilities

On September 5, 2023, Enbridge Inc. (Enbridge) entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company (EOG), Questar Gas Company (Questar) and its related Wexpro companies (Wexpro), and Public Service Company of North Carolina, Incorporated (PSNC) (together, the Acquisitions). The Acquisitions further diversify, and are complementary to, our existing gas distribution operations.

On September 30, 2024, through a wholly-owned US subsidiary, we acquired 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. Going forward, PSNC will conduct business as Enbridge Gas North Carolina.

On May 31, 2024, through a wholly-owned US subsidiary, we acquired Questar and Wexpro for cash consideration of $4.1 billion (US$3.0 billion) (the Questar Acquisition). Questar is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Utah, southwestern Wyoming and southeastern Idaho. The Public Utilities Commissions of Utah, Wyoming and Idaho 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. Questar conducts business as Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho in those respective states.

On March 6, 2024, through a wholly-owned US subsidiary, we acquired EOG for cash consideration of $5.8 billion (US$4.3 billion) (the EOG Acquisition). EOG is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Ohio and is regulated by the Public Utilities Commission of Ohio. EOG conducts business as Enbridge Gas Ohio.

Joint Venture with WhiteWater/I Squared and MPLX

On May 29, 2024, through a wholly-owned US subsidiary, we formed a joint venture (the Whistler Parent JV) with WhiteWater/I Squared Capital (WhiteWater/I Squared) and MPLX LP (MPLX) that will develop, construct, own and operate natural gas pipeline and storage assets connecting Permian Basin natural gas supply to growing liquefied natural gas (LNG) and other US Gulf Coast demand.The Whistler Parent JV is owned by WhiteWater/I Squared (50.6%), MPLX (30.4%) and Enbridge (19.0%) and owns the following assets:

• a 100% interest in the Whistler Pipeline, a 450-mile intrastate pipeline transporting natural gas from the Waha Header in the Permian Basin to Agua Dulce, Texas;
• a 100% interest in the Rio Bravo Pipeline project, two new parallel 137-mile pipelines transporting natural gas from the Agua Dulce supply area to NextDecade's Rio Grande LNG project in Brownsville, Texas;
• a 70% interest in the ADCC Pipeline, a new 40-mile pipeline which was placed into service in July 2024 and is designed to transport 1.7 billion cubic feet per day (bcf/d) of natural gas from the terminus of the Whistler Pipeline in Agua Dulce, Texas to Cheniere's Corpus Christi LNG export facility; and
• a 50% interest in Waha Gas Storage, a 2.0 bcf gas storage cavern facility connecting to key Permian egress pipelines including the Whistler Pipeline.

In connection with the formation of the Whistler Parent JV, we contributed our 100% interest in the Rio Bravo Pipeline project and $487 million (US$357 million) of cash to the Whistler Parent JV. In addition to our 19.0% equity interest in the Whistler Parent JV, we received a special equity interest in the Whistler Parent JV which provides for a 25.0% economic interest in the Rio Bravo Pipeline project. This interest is subject to certain redemption rights held by Whitewater/I Squared and MPLX. After the closing on May 29, 2024, we accrued for our share of the post-closing mandatory capital expenditures of approximately US$150 million for the Rio Bravo Pipeline project. Additional capital expenditures to complete the Rio Bravo Pipeline project will be proportionate to our economic interest.

ASSET MONETIZATION

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 (Pembina) for $3.1 billion, including $327 million of non-recourse debt, subject to customary closing adjustments. 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.

GAS TRANSMISSION RATE PROCEEDINGS

Texas Eastern

In May 2024, Texas Eastern Transmission, LP (Texas Eastern) reached a negotiated settlement with customers to increase rates starting October 1, 2024 and filed a Stipulation and Agreement with the Federal Energy Regulatory Commission (FERC) on June 3, 2024. Texas Eastern received approval on July 31, 2024 from the FERC of its uncontested settlement with customers.

Algonquin

Algonquin Gas Transmission, LLC (Algonquin) filed a rate case on May 30, 2024. On June 28, 2024, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In compliance with the order, Algonquin will make a motion filing to implement the rates to be effective December 1, 2024, subject to refund. Settlement negotiations with shippers have commenced.

Maritimes & Northeast Pipeline

Maritimes & Northeast Pipeline (M&N) US filed a rate case on May 30, 2024. On June 27, 2024, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In compliance with the order, M&N US will make a motion filing to implement the rates to be effective December 1, 2024, subject to refund. Settlement negotiations with shippers have commenced.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

Incentive Regulation Rate Application

In October 2022, Enbridge Gas Inc. (Enbridge Gas Ontario) filed its application with the Ontario Energy Board (OEB) to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application initially sought approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term (2025–2028). A third phase (Phase 3) was established with the OEB in 2023. Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones.

On December 21, 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). Enbridge Gas Ontario filed a Notice of Appeal with the Ontario Divisional Court on January 22, 2024 regarding various aspects of the Phase 1 Decision. On January 29, 2024, Enbridge Gas Ontario also filed a Notice of Motion with the OEB requesting the OEB to review and vary the Phase 1 Decision. Our Notice of Motion was subsequently amended on May 29, 2024 (Amended Motion). The Amended Motion focused on two aspects of the Phase 1 Decision: asset class average useful lives for depreciation purposes and the recoverability of integration capital. On October 8, 2024, the OEB issued a decision on the Amended Motion and determined that the asset class average useful lives issue did not meet the threshold to warrant a review, however the issue of integration capital did meet the threshold to warrant a review. After it receives written submissions on the issue of integration capital, the OEB will make a determination on whether there will be an oral hearing. The outcome and timing of a decision on the matter of integration capital is uncertain.

On February 24, 2024, the Government of Ontario introduced Bill 165, the Keeping Energy Costs Down Act (the Act). The Act gives the Government of Ontario time-limited authority to set the revenue horizon for small volume customers, effectively reversing that aspect of the OEB's Phase 1 Decision. The Act proceeded to and passed a final vote in the provincial legislature on May 15, 2024 and received royal assent on May 16, 2024. Regulations are now in place setting the revenue horizon for new customer connections to 40 years.

The Phase 1 Decision resulted in interim 2024 rates, pending Phase 2 of the proceeding and resolution of the Amended Motion. An updated Draft Interim Rate Order reflecting the Phase 1 Decision was filed on March 15, 2024 and subsequently approved by the OEB on April 11, 2024. The Interim Rate Order implemented 2024 rates on May 1, 2024, with an effective date of January 1, 2024.

Enbridge Gas Ontario filed its Phase 2 evidence on April 26, 2024. Phase 2 will establish the incentive rate mechanism for 2025-2028, and will also address unregulated storage cost allocation and new energy transition proposals. Phase 3 is anticipated to be completed in 2025.

FINANCING UPDATE

On the March 8, 2024 call date, we redeemed at par all of the outstanding US$700 million three-year callable, 5.97% senior notes that carried an original maturity date in March 2026.

In March 2024, we entered into a delayed-draw term loan facility in support of sustainable retrofit projects for large buildings using decarbonization solutions for $200 million which matures in March 2049.

In April 2024, we closed a four-tranche offering consisting of three-year senior notes, five-year senior notes, 10-year senior notes, and 30-year senior notes for an aggregate principal amount of US$3.5 billion, which mature in April 2027, April 2029, April 2034 and April 2054, respectively.

On May 15, 2024, we established an at-the-market equity issuance program (ATM Program) which provided us with additional flexibility to partially fund the Acquisitions. From May 15, 2024 to July 31, 2024, 51,298,629 common shares were issued on Canadian and US exchanges at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.5 billion. 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 PSNC Acquisition and to pay related fees and expenses.

In June 2024, we closed an offering consisting of a tranche of 30.75-year non-call 5.5-year fixed-to-fixed subordinated notes and a tranche of 30-year non-call 9.75-year fixed-to-fixed subordinated notes, for an aggregate principal amount of US$1.2 billion, which mature in March 2055 and June 2054, respectively.

In June 2024, we entered into a five-year, non-revolving term loan facility of US$250 million which matures in June 2029.

In July 2024, Algonquin closed an offering of 10-year senior notes for US$350 million which mature in July 2034.

In July 2024, Enbridge Gas Ontario extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.

In July 2024, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.

In July 2024, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2026, which includes a one-year term out provision from July 2025. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2029. Further, we extended the maturity dates of our three-year credit facilities to July 2027.

In August 2024, we closed a three-tranche offering consisting of 5.5-year medium-term notes, 10-year medium-term notes, and 30-year medium-term notes for an aggregate principal of $1.8 billion, which mature in February 2030, August 2034, and August 2054, respectively.

In October 2024, we increased our letter of credit facilities by $200 million.

These financing activities, in combination with the financing activities executed in 2023, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects and acquisitions without requiring access to the capital markets for the next 12 months, should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources.

As at September 30, 2024, after adjusting for the impact of floating-to-fixed interest rate swap hedges, less than 5% of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements - Note 10 - Risk Management and Financial Instruments for more information on our interest rate hedging program.

RESULTS OF OPERATIONS

(millions of Canadian dollars, except per share amounts)

1Non-GAAP financial measure. Refer to Non-GAAP and Other Financial Measures.

Change in Reportable Segments

Effective January 1, 2024, to better align how the chief operating decision-maker reviews operating performance and resource allocation across operating segments, we transferred our Canadian and US crude oil marketing businesses from the Energy Services segment to the Liquids Pipelines segment. As a result, the Energy Services segment ceased to exist and the remainder of the business, comprising natural gas and power marketing, are now reported in the Eliminations and Other segment. Beginning in the first quarter of 2024, prior period comparable results for segmented information have been recast to reflect the change in reportable segments. This segment reporting change does not have an impact on our consolidated results.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended September 30, 2024, compared with the three months ended September 30, 2023

Earnings attributable to common shareholders were positively impacted by $841 million due to certain infrequent or other non-operating factors, primarily explained by the following:

• a non-cash, net unrealized derivative fair value gain of $112 million ($92 million after-tax) in 2024, compared with a net unrealized loss of $782 million ($591 million after-tax) in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;
• the absence in 2024 of a provision adjustment of $124 million ($95 million after-tax) related to a litigation matter;
• a deferred tax recovery of $59 million in 2024 due to change in state apportionment as a result of the Acquisitions; and
• a non-cash, net unrealized gain of $14 million ($13 million after-tax) in 2024, compared with a net loss of $8 million ($7 million after-tax) in 2023, reflecting changes in the fair value of investments held by our captive insurance subsidiaries; partially offset by
• a non-cash revaluation loss of $18 million in 2024 ($13 million after-tax) to the gas inventory at our Aitken Creek Gas Storage Facility (Aitken Creek).

The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of our comprehensive economic hedging program to mitigate foreign exchange, interest rate and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.

After taking into consideration the factors above, the remaining $80 million decrease in earnings attributable to common shareholders is primarily explained by:

• higher interest expense primarily due to higher interest rates and higher average principal outstanding;
• higher depreciation and amortization expense mainly driven by the Acquisitions completed in 2024; and
• absence of contributions from our Gas Transmission segment due to the sale of our interests in the Alliance Pipeline and Aux Sable in April 2024; partially offset by
• full-quarter contributions from Enbridge Gas Ohio and Enbridge Gas Utah, and higher distribution charges resulting from increases in rates and customer base from Enbridge Gas Ontario in our Gas Distribution and Storage segment;
• higher contributions from our Gas Transmission segment primarily due to acquisitions completed after September 2023, favourable contracting, and lower operating costs in our US Gas Transmission assets; and
• higher contributions from our Liquids Pipelines segment driven by higher Mainline System tolls effective July 1, 2024 as a result of annual escalators and discontinuation of rate-regulated accounting of Southern Lights Pipeline as at December 31, 2023, net of lower Mainline System throughput in the third quarter of 2024.

Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023

Earnings attributable to common shareholders were positively impacted by $430 million due to certain infrequent or other non-operating factors, primarily explained by the following:

• a gain on sale of $1.1 billion ($765 million after-tax) related to the disposition of interests in the Alliance Pipeline, Aux Sable and NRGreen to Pembina;
• the absence in 2024 of a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, as foreign exchange risks inherent within the Competitive Toll Settlement (CTS) are not present in the Mainline Tolling Settlement (MTS);
• a deferred tax recovery of $141 million in 2024 due to change in state apportionment as a result of the Acquisitions;
• the absence in 2024 of a provision adjustment of $124 million ($95 million after-tax) related to a litigation matter; and
• a non-cash unrealized net gain of $35 million ($32 million after-tax) in 2024, compared with a net gain of $14 million ($12 million after-tax) in 2023, reflecting changes in the fair value of investments held by our captive insurance subsidiaries; partially offset by
• a non-cash, net unrealized derivative fair value loss of $773 million ($586 million after-tax) in 2024, compared with a net unrealized gain of $363 million ($277 million after-tax) in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;
• severance costs of $105 million ($79 million after-tax) as a result of a workforce reduction in February 2024;
• the absence in 2024 of the receipt of a litigation claim settlement of $68 million ($52 million after-tax);
• $55 million ($46 million after-tax) of integration and transaction costs incurred related to the Acquisitions in 2024, as compared to $21 million ($16 million after-tax) of transaction costs in 2023;
• a non-cash revaluation loss of $47 million in 2024 ($34 million after-tax) to the gas inventory at Aitken Creek; and
• a loss of $29 million ($23 million after-tax) as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV.

After taking into consideration the factors above, the remaining $17 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:

• contributions from Enbridge Gas Ohio and Enbridge Gas Utah, and higher distribution charges resulting from increases in rates and customer base from Enbridge Gas Ontario in our Gas Distribution and Storage segment;
• higher contributions from our Gas Transmission segment primarily due to favorable contracting and lower operating costs in our US Gas Transmission assets, and acquisitions completed after September 2023;
• higher investment income primarily due to pre-funding of the Acquisitions and timing of certain operating and administrative costs recoveries in our Eliminations and Other segment; and
• higher contributions from our Liquids Pipelines segment due to discontinuation of rate-regulated accounting of Southern Lights Pipeline as at December 31, 2023, higher volumes from the Gulf Coast and Mid-Continent System and the Bakken System.

The factors above were partially offset by:

• higher interest expense primarily due to higher interest rates and higher average principal outstanding;
• higher depreciation and amortization expense as a result of acquisitions and projects placed into service after September 2023;
• lower contributions from the Mainline System in our Liquids Pipelines segment driven by lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower Line 3 Replacement (L3R) surcharge;
• higher income tax expense largely driven by higher US minimum tax, changes to the state apportionment and the effects of rate-regulated accounting for income taxes;
• lower contributions from our Gas Transmission segment due to the sale of our interests in the Alliance Pipeline and Aux Sable in April 2024; and
• realized loss on foreign exchange hedge settlement in 2024 compared to a realized gain in 2023 in our Eliminations and Other segment.

BUSINESS SEGMENTS

LIQUIDS PIPELINES

Three months ended September 30, 2024, compared with the three months ended September 30, 2023

EBITDA was positively impacted by $117 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized gain of $26 million in 2024, compared with a net unrealized loss of $95 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.

After taking into consideration the factors above, the remaining $44 million increase is primarily explained by the following significant business factors:

• higher Mainline System tolls effective July 1, 2024 as a result of annual escalators;
• higher contributions from the Southern Lights Pipeline due primarily to the discontinuation of rate-regulated accounting as at December 31, 2023; and
• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, as compared to 2023; partially offset by
• lower Mainline System throughput in the third quarter of 2024 as compared to the same period in 2023; and
• lower contributions from Regional Oil Sands System primarily due to lower throughput.

Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023

EBITDA was positively impacted by $46 million due to certain infrequent or other non-operating factors, primarily explained by the following:

• a non-cash, net unrealized gain of $20 million in 2024, compared with a net unrealized gain of $555 million in 2023, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and
• the absence in 2024 of the receipt of a litigation claim settlement of $68 million; partially offset by
• the absence in 2024 of a realized loss of $638 million due to termination of foreign exchange hedges, as foreign exchange risks inherent within the CTS framework are not present in the MTS.

After taking into consideration the factors above, the remaining $189 million increase is primarily explained by the following significant business factors:

• higher contributions from the Southern Lights Pipeline due primarily to the discontinuation of rate-regulated accounting as at December 31, 2023;
• higher contributions from the Gulf Coast and Mid-Continent System due primarily to higher volumes on the Flanagan South Pipeline driven by the open season commitments that commenced in the first quarter of 2024, and the Enbridge Ingleside Energy Center due to higher demand;
• stronger Mainline System performance due to higher throughput and longer haul volumes;
• higher contributions from the Express-Platte System due primarily to longer haul volumes;
• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, as compared to 2023; and
• higher contributions from the Bakken System due to higher volumes; partially offset by
• lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower L3R surcharge.

GAS TRANSMISSION

Three months ended September 30, 2024, compared with the three months ended September 30, 2023

EBITDA was positively impacted by $111 million due to certain infrequent or other non-operating factors, primarily explained by:

• the absence in 2024 of a provision adjustment of $124 million related to a litigation matter; partially offset by
• a non-cash revaluation loss of $18 million to the gas inventory at Aitken Creek.

The remaining $62 million increase is primarily explained by the following significant business factors:

• favorable contracting and lower operating costs on our US Gas Transmission assets;
• contributions from the acquisitions of Aitken Creek in the fourth quarter of 2023, Tomorrow RNG in the first quarter of 2024, and Whistler Parent JV in the second quarter of 2024; and
• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, compared to the same period in 2023; partially offset by
• the absence of contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments to Pembina in April 2024.

Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023

EBITDA was positively impacted by $1,090 million due to certain infrequent or other non-operating factors, primarily explained by:

• a gain on sale of $1,063 million on the disposition of interests in the Alliance Pipeline and Aux Sable; and
• the absence in 2024 of a provision adjustment of $124 million related to a litigation matter; partially offset by
• a non-cash revaluation loss of $47 million to the gas inventory at Aitken Creek; and
• 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.

The remaining $196 million increase is primarily explained by the following significant business factors:

• favorable contracting and lower operating costs on our US Gas Transmission assets;
• contributions from the acquisitions of Tres Palacios in the second quarter of 2023, Aitken Creek in the fourth quarter of 2023, Tomorrow RNG in the first quarter of 2024 and Whistler Parent JV in the second quarter of 2024;
• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, compared to the same period in 2023; and
• higher first quarter earnings at Aux Sable due to favorable contracting; partially offset by
• lower contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments to Pembina in April 2024; and
• the absence in 2024 of recognition of revenues attributable to the Texas Eastern 2022 rate case settlement.

GAS DISTRIBUTION AND STORAGE

Three months ended September 30, 2024, compared with the three months ended September 30, 2023

EBITDA was positively impacted by $251 million primarily due to the following significant business factors:

• full-quarter contributions from Enbridge Gas Ohio and Enbridge Gas Utah; and
• higher distribution charges resulting from increases in rates and customer base, and higher demand in the contract market at Enbridge Gas Ontario.

Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023

EBITDA was positively impacted by $500 million primarily due to the following significant business factors:

• contributions from Enbridge Gas Ohio and Enbridge Gas Utah since their acquisitions in 2024; and
• higher distribution charges resulting from increases in rates and customer base, and higher demand in the contract market at Enbridge Gas Ontario; partially offset by
• warmer than normal weather in 2024, when compared with the normal weather forecast embedded in rates, which negatively impacted Enbridge Gas Ontario 2024 EBITDA by approximately $64 million period over period.

RENEWABLE POWER GENERATION

Three months ended September 30, 2024, compared with the three months ended September 30, 2023

EBITDA was positively impacted by $105 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized gain of $28 million in 2024, compared with a net unrealized loss of $83 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.

The remaining $33 million decrease is primarily explained by:

• the absence in 2024 of fees earned on certain wind and solar development contracts; partially offset by
• higher contributions from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities.

Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023

EBITDA was positively impacted by $80 million due to certain infrequent or other non-operating factors, primarily explained by:

• a non-cash, net unrealized loss of $8 million in 2024, compared with a net unrealized loss of $79 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and
• a gain on sale of $29 million related to disposition of our interest in NRGreen to Pembina.

The remaining $122 million increase is primarily explained by the following significant business factors:

• contributions from our investment in Fox Squirrel Solar as a result of the generation of investment tax credits;
• higher contributions from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities; and
• stronger wind resources at European offshore wind facilities; partially offset by
• the absence in 2024 of fees earned on certain wind and solar development contracts.

ELIMINATIONS AND OTHER

Eliminations and Other includes operating and administrative costs that are not allocated to business segments, and the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. Eliminations and Other also includes the impact of new business development activities, corporate investments, and natural gas and power marketing and logistical services to North American refiners, producers, and other customers.

Three months ended September 30, 2024, compared with the three months ended September 30, 2023

EBITDA was positively impacted by $897 million, primarily due to certain infrequent or non-operating factors, explained by:

• a non-cash, net unrealized gain of $206 million in 2024, compared with a net loss of $661 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk; and
• a non-cash, net unrealized gain of $15 million in 2024, compared with a net loss of $8 million in 2023, reflecting changes in the fair value of investments held by our captive insurance subsidiaries.

Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023

EBITDA was negatively impacted by $628 million due to certain infrequent or non-operating factors, primarily explained by:

• a non-cash, net unrealized loss of $745 million in 2024, compared with a net loss of $226 million in 2023, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk;
• severance costs of $105 million as a result of a workforce reduction in February 2024; and
• $55 million of integration and transaction costs incurred as a result of the Acquisitions in 2024, as compared to $21 million in 2023; partially offset by
• a non-cash net unrealized gain of $35 million in 2024, compared with a net gain of $14 million in 2023, reflecting changes in the fair value of investments held by our captive insurance subsidiaries.

After taking into consideration the non-operating factors above, the remaining $136 million increase is primarily explained by:

• higher investment income primarily from the pre-funding of the Acquisitions; and
• timing of certain operating and administrative cost recoveries from the business units; partially offset by
• realized foreign exchange loss on hedge settlements in 2024, compared to a gain in 2023.

GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS

The following table summarizes the status of our significant commercially secured projects, organized by business segment:

1These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.

2Expenditures to date and status of the project are determined as at September 30, 2024.

3Includes the US$37 million Gator Express Project placed into service in August 2023. Total estimated capital cost consists of the reversal and expansion of Texas Eastern's Line 40 expected to be completed in the fourth quarter of 2024.

4Our equity contribution is approximately US$893 million, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated prior to the 60% engineering milestone, at which point Enbridge's preferred return will be set.

5Previously approved PSNC projects that were acquired by Enbridge through the PSNC Acquisition.

6Our equity contribution is minimal after project refinancing was approved in the first quarter of 2024. The project is financed through non-recourse project level debt.

7Our equity contribution is $181 million, with the remainder financed through non-recourse project level debt.

8Includes three phases of the project. The first phase of the project commenced operations in December 2023, and the second phase commenced operations in the third quarter of 2024. The third phase is expected to enter service in the fourth quarter of 2024.

A full description of each of our projects is provided in our annual report on Form 10-K for the year ended December 31, 2023. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.

GAS TRANSMISSION

Canyon System Pipelines

Enbridge has sanctioned the construction of two new offshore pipelines in the US Gulf of Mexico to deliver natural gas and crude oil from BP Exploration & Production Company's Kaskida offshore project.

The development includes a new 24/26-inch oil pipeline which will connect to Shell Pipeline Company LP's Green Canyon 19 Platform, and a 12-inch gas pipeline connecting to Enbridge's Magnolia Gas Gathering System.

Tennessee Ridgeline Expansion

The Tennessee Ridgeline Expansion project is an expansion of the East Tennessee Natural Gas (ETNG) system which would provide additional natural gas for the Tennessee Valley Authority (TVA) to support the replacement of an existing coal-fired power plant as TVA continues to transition its generation mix towards lower-carbon fuels. The proposed scope includes the installation of approximately 125 miles of 30-inch pipeline looping, one electric-powered compressor station, and an 8-megawatt behind-the-meter solar array.

TVA published a Notice of Intent in the Federal Register on June 15, 2021, to initiate the environmental review process for its proposed action to retire the Kingston Coal-Fired Plant and to replace it with a natural gas plant. On April 2, 2024, TVA issued a Record of Decision (ROD) documenting its decision to adopt TVA's Preferred Alternative to replace the retiring coal generating units at the Kingston Coal-Fired Plant with a natural gas plant. The issuance of the ROD adopting its Preferred Alternative satisfied a key condition of TVA's Precedent Agreement with ETNG related to the ETNG Ridgeline Expansion project.

All necessary regulatory authorizations from the FERC and other federal and state agencies will be obtained before construction of the project commences. Pending the approval and receipt of all necessary permits, construction is expected to begin in 2025 with a target in-service date of late 2026.

GAS DISTRIBUTION AND STORAGE

Moriah Energy Center

Moriah Energy Center is a LNG facility that is under construction in Person County, North Carolina with 2 bcf storage capacity. The facility is required to ensure system reliability and address supply constraints due to customer growth, and will be designed with trucking capabilities to support other LNG facilities. The construction started in first quarter of 2024 and is expected to achieve completion in 2027.

T-15 Reliability Project

The T-15 Reliability Project includes the construction of 45 miles of transmission pipe, a compressor station and associated metering and regulation facilities in Rockingham, Caswell, and Person counties in North Carolina. The project is expected to start construction in 2026 and to achieve project completion in 2027.

RENEWABLE POWER GENERATION

Sequoia Solar Project

On November 1, 2024, Enbridge announced that it has sanctioned the Sequoia Solar Project, a 815-megawatt solar farm located approximately 150 miles west of Dallas, Texas. The two-phased project is expected to achieve project completion in 2025 and 2026.

LIQUIDITY AND CAPITAL RESOURCES

The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control, including but not limited to, financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to help ensure we maintain sufficient liquidity to meet routine operating and future capital requirements.

In the near term, we generally expect to utilize cash from operations together with commercial paper issuances and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures and acquisitions, fund debt retirements and pay common and preference share dividends. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.

We have signed capital obligation contracts for the purchase of services, pipe and other materials totaling approximately $2.6 billion, which are expected to be paid over the next five years.

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives.

CAPITAL MARKET ACCESS

We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuances of long-term debt, equity and other forms of long-term capital when market conditions are attractive.

Credit Facilities and Liquidity

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at September 30, 2024:

1Maturity date is inclusive of the one-year term out option for certain credit facilities.

2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

In March 2024, we entered into a delayed-draw term loan facility in support of sustainable retrofit projects for large buildings using decarbonization solutions for $200 million which matures in March 2049.

In June 2024, we entered into a five-year, non-revolving term loan facility of US$250 million which matures in June 2029.

In July 2024, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2026, which includes a one-year term out provision from July 2025. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2029. Further, we extended the maturity dates of our three-year credit facilities to July 2027.

In July 2024, Enbridge Gas Ontario extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.

In July 2024, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.

In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $859 million was unutilized as at September 30, 2024. As at December 31, 2023, we had $1.1 billion of uncommitted demand letter of credit facilities, of which $572 million was unutilized.

In October 2024, we increased our letter of credit facilities by $200 million.

As at September 30, 2024, our net available liquidity totaled $17.1 billion (December 31, 2023 - $23.0 billion), consisting of available credit facilities of $15.2 billion (December 31, 2023 - $17.1 billion) and unrestricted cash and cash equivalents of $1.9 billion (December 31, 2023 - $5.9 billion) as reported in the Consolidated Statements of Financial Position.

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, 2024, we were in compliance with all such debt covenant provisions.

LONG-TERM DEBT ISSUANCES

During the nine months ended September 30, 2024, we completed the following long-term debt issuances totaling US$5.1 billion and $1.8 billion:

1For the initial 5.5 years, the notes carry a fixed interest rate. On March 15, 2030, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.12%.

2For the initial 9.75 years, the notes carry a fixed interest rate. On June 27, 2034, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 2.97%.

LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2024, we completed the following long-term debt repayments totaling US$3.6 billion, $0.8 billion and €23 million:

1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 63 basis points.

2The notes carried an original maturity date in March 2026, and were callable in March 2024, which was one year after their issuance.

Strong internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA.

There are no material restrictions on our cash. Total restricted cash of $133 million, as reported in the Consolidated Statements of Financial Position, primarily includes reinsurance security, cash collateral, future pipeline abandonment costs collected and held in trust, amounts received in respect of specific shipper commitments and capital projects. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us.

Excluding current maturities of long-term debt, as at September 30, 2024 and December 31, 2023, we had negative and positive working capital positions of $0.1 billion and $3.0 billion, respectively. During the nine months ended September 30, 2024, the major contributing factor to the negative working capital position was a decrease in cash as a result of the Acquisitions, while during the year ended December 31, 2023, the major contributing factor to the positive working capital position was due to the increase in cash associated with pre-funding of the Acquisitions. We maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due.

SOURCES AND USES OF CASH

Significant sources and uses of cash for the nine months ended September 30, 2024 and 2023 are summarized below:

Operating Activities

The primary factors impacting cash provided by operating activities period-over-period include changes in our operating assets and liabilities in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments and cash receipts and payments generally. Cash provided by operating activities is also impacted by changes in earnings and certain infrequent or other non-operating factors, as discussed in Results of Operations, as well as Distributions from equity investments.

Investing Activities

Cash used in investing activities includes capital expenditures to execute our capital program, which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements. Cash used in investing activities is also impacted by acquisitions, dispositions and changes in contributions to, and distributions from, our equity investments. The increase in cash used in investing activities period-over-period was primarily due to the acquisitions of EOG, Questar, PSNC, and Tomorrow RNG, as well as our contributions to acquire an equity interest in the Whistler Parent JV, which were partially offset by proceeds received from the disposition of our interests in the Alliance Pipeline, Aux Sable and NRGreen.

Financing Activities

Cash provided by or used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, share redemptions and common share repurchases under our normal course issuer bid. Cash provided by or used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the increase in cash provided by financing activities period-over-period primarily include:

• net commercial paper and credit facility draws in 2024 when compared to net repayments during the same period in 2023;
• the ATM Program, resulting in the issuance of 51,298,629 common shares for aggregate net proceeds of $2.5 billion in 2024; and
• lower net repayments of short-term borrowings in 2024 when compared to the same period in 2023.

The factors above were partially offset by:

• higher long-term debt repayments and lower long-term debt issuances in 2024 when compared to the same period in 2023;
• the absence in 2024 of the public offering of common shares, which closed on September 8, 2023 for gross proceeds of $4.6 billion; and
• increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding.

SUMMARIZED FINANCIAL INFORMATION

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP) (together, the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes.

Consenting SEP notes and EEP notes under Guarantees

1As at September 30, 2024, the aggregate outstanding principal amount of SEP notes was approximately US$2.2 billion.

2As at September 30, 2024, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

Enbridge Notes under Guarantees

1As at September 30, 2024, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$17.0 billion.

2As at September 30, 2024, the aggregate outstanding principal amount of the Enbridge Canadian dollar-denominated notes was approximately $12.8 billion.

Rule 3-10 of the US SEC Regulation S-X provides an exemption from the reporting requirements of the Exchange Act for fully consolidated subsidiary issuers of guaranteed securities and subsidiary guarantors and allows for summarized financial information in lieu of filing separate financial statements for each of the Partnerships.

The following Summarized Combined Statement of Earnings and Summarized Combined Statements of Financial Position combines the balances of SEP, EEP, and Enbridge.

Summarized Combined Statement of Earnings

Summarized Combined Statements of Financial Position

The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-Guarantors.

Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee:

• received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;
• was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
• intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under US federal or state law.

Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.

Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:

• any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;
• the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;
• the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement;
• with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;
• with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or
• with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.

The guarantee obligations of Enbridge will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.

The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities.

LEGAL AND OTHER UPDATES

MICHIGAN LINE 5 DUAL PIPELINES - STRAITS OF MACKINAC EASEMENT

Michigan Attorney General Lawsuit

In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit Court (the Circuit Court) that requests the Circuit Court to declare the easement granted to Enbridge in 1953 for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits. On December 15, 2021, Enbridge removed the case to the US District Court in the Western District of Michigan (US District Court). The removal of the AG's case to federal court followed a November 16, 2021, ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force Line 5's shutdown raised important federal issues that should be heard in federal court. The AG subsequently filed various motions and appeals (opposed by Enbridge) to remand the case.

On June 17, 2024, the 6th Circuit Court of Appeals (6th Circuit) overturned the US District Court’s decision and remanded the AG's lawsuit against Enbridge back to the Circuit Court. On July 15, 2024, Enbridge filed a petition for rehearing, which was denied on August 16, 2024.

A decision on the merits of the AG's case is not anticipated in the next twelve months, as the matter is still in the pretrial motion stage of the case.

Enbridge Lawsuit

On November 24, 2020, Enbridge filed in the US District Court a Complaint for Declaratory and Injunctive Relief requesting that the US District Court enjoin the State of Michigan Officials from taking any action to prevent or impede the operation of Line 5. The Government of Canada has filed a supplemental brief reiterating that the 1977 Transit Pipelines Treaty between the US and Canada has been invoked and that the matter is of great importance to Canada. This matter remains in federal court.

In January 2022, the State of Michigan Officials filed a motion to dismiss Enbridge's Complaint and Enbridge filed a motion for Summary Judgment. On July 5, 2024, the US District Court issued an Order denying the Michigan officials' motion to dismiss Enbridge's Complaint, and the State of Michigan Officials filed for an immediate appeal to the 6th Circuit. On August 29, 2024, the US District Court issued an order staying the case, pending the 6th Circuit’s decision, which is expected in 2025.

DAKOTA ACCESS PIPELINE

We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of 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 DC District Court) contesting the lawfulness of the Army Corps easement for DAPL, including 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.

On June 14, 2017, the DC District Court found the Army Corps' environmental review to be deficient and ordered the Army Corps to conduct further study concerning spill risks from DAPL.

On March 25, 2020, in response to amended complaints from the Tribes, the DC District Court found that the Army Corps' subsequent environmental review completed in August 2018 was also deficient and ordered the Army Corps to prepare an Environmental Impact Statement (EIS) to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July 6, 2020, the DC District Court issued an order vacating the Army Corps' easement for DAPL and ordering that the pipeline be shut down by August 5, 2020. On that day, the US Court of Appeals for the District of Columbia Circuit stayed the DC District Court's July 6 order to shut down and empty the pipeline.

On January 26, 2021, the US Court of Appeals affirmed the DC District Court's decision, holding that the Army Corps is required to prepare an EIS and that the Army Corps' easement for DAPL is vacated. The US Supreme Court subsequently denied the request of Dakota Access, LLC to review the decision that an EIS is required. The US Court of Appeals also determined that, absent an injunction proceeding, the DC District Court could not order DAPL's operations to cease. While not an issue before, the US Court of Appeals also recognized that the Army Corps could consider whether to allow DAPL to continue to operate in the absence of an easement. The Army Corps earlier indicated that it did not intend to exercise its authority to bar DAPL's continued operation, notwithstanding the absence of an easement.

On September 8, 2023, the Army Corps issued its draft EIS, which assesses the impacts of DAPL under five alternative scenarios: denying the easement removing the pipeline; denying the easement and leaving the pipeline in place; granting the easement with the prior conditions (which allow for the ongoing operation, maintenance and ultimate removal of the pipeline and its related facilities); granting the easement with some new safety conditions; and rerouting the pipeline. The Army Corps did not identify a preferred alternative. The public comment period that commenced on the issuance of the draft EIS closed

on December 13, 2023. The pipeline remains operational while the environmental review process continues.

On October 15, 2024, the Standing Rock Sioux Tribe filed a complaint in the DC District Court against the Army Corps, among others, seeking a permanent injunction prohibiting the continued operation of DAPL. The main allegations of the complaint are that the Army Corps is unlawfully permitting DAPL to continue to operate without an easement and without a determination under the National Environmental Policy Act, and that the Army Corps has failed to require that a compliant Facility Response Plan be submitted. Several of the claims are similar to those in the litigation described above.

OTHER LITIGATION

We and our subsidiaries are subject to various other 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 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.

CHANGES IN ACCOUNTING POLICIES

Refer to Part I. Item 1. Financial Statements - Note 2. Changes in Accounting Policies.

Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our annual report on Form 10-K for the year ended December 31, 2023. We believe our exposure to market risk has not changed materially since then.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as at September 30, 2024, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

Changes in Internal Control over Financial Reporting

Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended September 30, 2024 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. Risk Factors of our annual report on Form 10-K for the year ended December 31, 2023, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors.