Enbridge Inc: Form 10-Q for the period ended Sep 30, 2023

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, 2022.

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

MAINLINE TOLLING AGREEMENT

Enbridge Inc. (Enbridge) has reached an agreement in principle on a negotiated settlement (the Settlement) with shippers for tolls on its Mainline pipeline system. The Settlement covers both the Canadian and US portions of the Mainline and would see the Mainline continuing to operate as a common carrier system available to all shippers on a monthly nomination basis. The Settlement is subject to regulatory and other approvals and the term is seven and a half years through the end of 2028, with new interim tolls effective on July 1, 2023.

The Settlement includes:

• an International Joint Toll (IJT), for heavy crude oil movements from Hardisty to Chicago, comprised of a Canadian Mainline Toll of $1.65 per barrel plus a Lakehead System Toll of US$2.57 per barrel, plus the applicable Line 3 Replacement surcharge;
• toll escalation for operation, administration, and power costs tied to US consumer price and power indices;
• tolls continue to be distance and commodity adjusted, and utilize a dual currency IJT; and
• a financial performance collar providing incentives for Enbridge to optimize throughput and cost, but also providing downside protection in the event of extreme supply or demand disruptions or unforeseen operating cost exposure. This performance collar is intended to ensure the Mainline earns 11% to 14.5% returns, on a deemed 50% equity capitalization, which is similar to the returns earned on average during the previous tolling agreement.

Approximately 70% of Mainline deliveries are tolled under this settlement, while approximately 30% of deliveries are tolled on a full path basis to markets downstream of the Mainline. The other continuing feature is that the Mainline toll flexes up or down US$0.035 per barrel for 50,000 barrel per day changes in throughput.

The expected financial outcome from this settlement is in line with previously reported financial results after taking into consideration the previously recognized provision, inflationary cost adjustments and increased volumes. Enbridge expects to file the Settlement with the Canada Energy Regulator (CER) by the end of the year.

On May 24, 2023, Enbridge filed an Offer of Settlement with the Federal Energy Regulatory Commission (FERC) for the Lakehead System. In addition to resolving litigation related to the Index portion of the Lakehead System rate, the Settlement also includes a depreciation truncation date of December 31, 2048 for the rate base applicable to the Index and Facilities Surcharge and agreement on the terms for future recovery through the Facilities Surcharge of costs related to two Line 5 projects: the Wisconsin Relocation Project and the Straits of Mackinac Tunnel. The Settlement Judge certified the Settlement on June 23, 2023 and the Settlement is awaiting approval by the FERC Commissioners. Lakehead System tolls will be updated to reflect the new Settlement pending approval by the FERC.

ACQUISITIONS

US Gas Utilities

On September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina, Incorporated, for an aggregate purchase price of $19.1 billion (US$14.0 billion), comprised of $12.8 billion (US$9.4 billion) of cash consideration and $6.3 billion (US$4.6 billion) of assumed debt, subject to customary closing adjustments (together, the Acquisitions). If completed, the Acquisitions will create North America's largest natural gas utility platform delivering over 9 billion cubic feet (bcf) per day to approximately 7 million customers across multiple regulatory jurisdictions. The Acquisitions are expected to close in 2024, subject to the satisfaction of customary closing conditions including the receipt of certain regulatory approvals, which are not cross conditional.

On September 8, 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions. Refer to Financing Update for further details on the debt issuances and credit facility obtained to support the Acquisitions.

Aitken Creek Gas Storage

On November 1, 2023, through a wholly-owned Canadian subsidiary, we acquired a 93.8% interest in Aitken Creek Gas Storage Facility and a 100% interest in Aitken Creek North Gas Storage Facility (collectively, Aitken Creek), located in British Columbia, Canada, for $400 million of cash plus payment for derivative contracts and gas inventory, subject to other customary closing adjustments.

Hohe See & Albatros

In November 2023, we signed a definitive agreement to acquire an additional 24.45% interest in the Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities (the Offshore Wind Facilities), through the acquisition of a 49% interest in Enbridge Renewable Infrastructure Investments S.à.r.l (ERII), for $391 million (€267 million) of cash and assumed debt of $524 million (€358 million), subject to customary closing adjustments, bringing our interest in the Offshore Wind Facilities to 49.9%. The Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities are located approximately 100 kilometers off the northern coast of Germany and came into service in 2019 and 2020, respectively.

Acquisition of RNG Facilities

In November 2023, Enbridge entered into a definitive agreement to acquire seven operating landfill gas-to-renewable natural gas (RNG) production facilities located in Texas and Arkansas for total consideration of $1.7 billion (US$1.2 billion), of which $0.7 billion (US$0.5 billion) is payable at close and $1.0 billion (US$0.7 billion) is payable within two years. Combined RNG production of the facilities is approximately 4.5 bcf per year. The transaction is expected to close in the first quarter of 2024, subject to the satisfaction of customary closing conditions.

GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS

Maritimes & Northeast Pipeline

The current toll settlement agreement for the Canadian portion of Maritimes & Northeast (M&N) Pipeline expires in December 2023. Settlement negotiations with M&N Pipeline shippers are ongoing with the objective of reaching a toll settlement which would be effective January 1, 2024. It is expected that a settlement agreement will be filed in the fourth quarter of 2023 with the CER for review and approval. A CER decision is expected in the first quarter of 2024.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

Incentive Regulation Rate Application

In October 2022, Enbridge Gas Inc. (Enbridge Gas) filed its application with the Ontario Energy Board (OEB) to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application initially sought approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term (2025–2028). A third phase (Phase 3) has been established with the OEB as part of the Phase 1 Partial Settlement Proposal (Settlement Proposal).

On August 17, 2023, the OEB approved the Settlement Proposal to support the determination of just and reasonable rates effective January 1, 2024. Items resolved in whole or in part include:

• additions to the rate base up to and including 2022;
• interest rates on debt and return on equity;
• deferral and variance accounts;
• Indigenous engagement; and
• rate implementation approach for 2024.

The Phase 1 hearing to examine issues not resolved as part of the Settlement Proposal has concluded. A decision from the OEB on the outstanding Phase 1 issues is expected in the fourth quarter of 2023. Phase 2 will establish and determine the 2025-2028 incentive rate mechanism, and gas cost and unregulated storage allocation issues. Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones.

Purchase Gas Variance

The Purchase Gas Variance Account (PGVA) captures the difference between actual and forecasted natural gas prices reflected in rates. Account balances are typically recovered or refunded over a prospective 12-month period through Quarterly Rate Adjustment Mechanism (QRAM) applications.

In March 2023, the April 1, 2023 QRAM application was filed and approved by the OEB, which included an adjustment to the prior rate mitigation approved as part of the July 1, 2022 QRAM. The recovery of the outstanding PGVA balance from the extended recovery period approved as part of the July 1, 2022 QRAM will now be completed by March 31, 2024. In June and September 2023, the July 1, 2023 and October 1, 2023 QRAM applications, respectively, were filed and approved by the OEB with no adjustments to the prior period rate mitigation plans and they did not include any additional rate mitigation measures.

As at September 30, 2023, Enbridge Gas' PGVA receivable balance was $266 million.

FINANCING UPDATE

In March 2023, we closed a two-tranche US debt offering consisting of three-year senior notes, callable at par after one year at our option, and 10-year sustainability-linked senior notes, for an aggregate principal amount of US$3.0 billion, which mature in March 2026 and March 2033, respectively.

In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion and in July 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024.

On April 15, 2023 call date, we redeemed at par all of the outstanding US$600 million five-year callable, 6.38% fixed-to-floating rate subordinated notes that carried an original maturity date of April 2078.

In May 2023, we closed a three-tranche debt offering consisting of five-year medium-term notes, 10-year sustainability-linked medium-term notes, and 30-year medium-term notes for an aggregate principal amount of $1.5 billion, which mature in May 2028, May 2033, and May 2053, respectively.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, we renewed approximately $6.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2025, which includes a one-year term out provision from July 2024. We also renewed approximately $7.6 billion of our five-year credit facilities, extending the maturity dates to July 2028. Further, we extended our three-year credit facilities, extending the maturity dates to July 2026.

In August 2023, Enbridge Pipelines Inc. closed an offering of $350 million 30-year medium-term notes which mature in August 2053.

In September 2023, we obtained commitments for a US$9.4 billion senior unsecured bridge term loan credit facility to support the Acquisitions. The commitment for this facility was subsequently reduced to US$3.4 billion as at September 30, 2023 as a result of the $4.6 billion equity offering and the September 2023 subordinated long-term debt issuances, discussed below.

In September 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions.

In September 2023, we closed two offerings, each consisting of a tranche of 60-year non-call five-year fixed-to-fixed subordinated notes and a tranche of 60-year non-call 10-year fixed-to-fixed subordinated notes, all of which mature in January 2084, for aggregate principal amounts of US$2.0 billion and $1.0 billion. The proceeds from the offerings are intended to finance a portion of the aggregate cash consideration payable for the Acquisitions.

In October 2023, Enbridge Gas closed a three-tranche offering consisting of five-year medium-term notes, 10-year medium-term notes, and 30-year medium-term notes, for an aggregate principal amount of $1.0 billion, which mature in October 2028, October 2033, and October 2053, respectively.

These financing activities, in combination with the financing activities executed in 2022, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects and other operating working capital requirements 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, 2023, after adjusting for the impact of floating-to-fixed interest rate swap hedges, none of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements - Note 8 - 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.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

Earnings attributable to common shareholders were negatively impacted by $655 million due to certain infrequent or other non-operating factors, primarily explained by the following:

• the absence in 2023 of a gain of $1,076 million ($732 million after-tax) on the closing of the joint venture merger transaction with Phillips 66 (P66) realigning our indirect economic interests in Gray Oak Pipeline LLC (Gray Oak) and DCP Midstream, LP (DCP);
• a non-cash, net unrealized loss of $66 million ($51 million after-tax) in 2023, compared to a net gain of $58 million ($44 million after-tax) in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, and exposure to movements in commodity prices;
• a provision adjustment of $124 million ($95 million after-tax) related to a litigation matter;
• the absence in 2023 of a deferred tax benefit of $95 million recognized as a result of the reduced Pennsylvania state corporate income tax;
• the absence in 2023 of a net positive adjustment of $85 million ($75 million after-tax) due to the release of reserves associated with our enterprise insurance strategy; and
• transaction costs of $21 million ($16 million after-tax) incurred during the quarter ended September 30, 2023 as a result of the Acquisitions.

The factors above were partially offset by a non-cash, net unrealized derivative fair value loss of $732 million ($552 million after-tax) in 2023, compared with a net unrealized loss of $1,334 million ($1,021 million after-tax) in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.

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 $92 million decrease in earnings attributable to common shareholders is primarily explained by:

• lower contributions from our Liquids Pipelines segment as a result of new Mainline System interim tolls effective July 1, 2023 and lower volumes on the Flanagan South Pipeline due to decreased demand;
• a reduction in earnings from our Gas Transmission and Midstream segment primarily due to our decreased interest in DCP as a result of a joint venture merger transaction with P66 that closed in the third quarter of 2022;
• lower commodity prices impacting the DCP and Aux Sable joint ventures in our Gas Transmission and Midstream segment;
• higher storage demand and transportation costs in our Gas Distribution and Storage segment which represents a partial reversal of previously favorable timing of recognition of these costs; and
• higher interest expense primarily due to higher interest rates and higher average principal; partially offset by
• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; and
• higher contributions from our Liquids Pipelines segment due to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and higher volumes from the Enbridge Ingleside Energy Center (EIEC) due to higher demand.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

Earnings attributable to common shareholders were positively impacted by $498 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 $376 million ($287 million after-tax) in 2023, compared with a net unrealized loss of $1,751 million ($1,340 million after-tax) in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate, and commodity price risks;
• a net positive adjustment to crude oil and natural gas inventories in our Energy Services business segment of $4 million ($3 million after-tax) in 2023, compared with a net negative adjustment of $67 million ($50 million after-tax) in 2022;
• the receipt of a litigation claim settlement of $68 million ($52 million after-tax) in 2023;
• a net unrealized gain of $14 million ($12 million after-tax) in 2023, compared with a net loss of $39 million ($33 million after-tax) in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries;
• the absence in 2023 of an impairment of $44 million ($34 million after-tax) for lease assets due to office relocation plans;
• the absence in 2023 of an asset impairment loss of $40 million ($30 million after-tax) relating to the MacKay River line within our Alberta Regional Oil Sands System; and
• a non-cash, net positive equity earnings adjustment of $5 million ($4 million after-tax) in 2023, compared to a net negative adjustment of $30 million ($22 million after-tax) in 2022 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable.

The factors above were partially offset by:

• the absence in 2023 of a gain of $1,076 million ($732 million after-tax) on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP;
• 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) framework are not present in the negotiated Mainline tolling agreement;
• a provision adjustment of $124 million ($95 million after-tax) related to a litigation matter;
• the absence in 2023 of a deferred tax benefit of $95 million recognized as a result of the reduced Pennsylvania state corporate income tax;
• a non-cash, net unrealized loss of $13 million ($10 million after-tax) in 2023, compared to a net gain of $22 million ($17 million after-tax) in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices; and
• transaction costs of $21 million ($16 million after-tax) incurred during the quarter ended September 30, 2023 as a result of the Acquisitions.

After taking into consideration the factors above, the remaining $41 million decrease in earnings attributable to common shareholders is primarily explained by the following significant business factors:

• a reduction in earnings from our Gas Transmission and Midstream segment primarily due to our decreased interest in DCP as a result of a joint venture merger transaction with P66 that closed in the third quarter of 2022;
• higher operating and administrative costs in our Gas Transmission and Midstream and Gas Distribution and Storage segments;
• lower commodity prices impacting the DCP and Aux Sable joint ventures in our Gas Transmission and Midstream segment;
• higher interest expense primarily due to higher interest rates and higher average principal; and
• higher depreciation and amortization due to assets placed into service in the second half of 2022; partially offset by
• higher contributions from the Mainline System in our Liquids Pipelines segment driven by increased volumes due to increased crude demand, net of a lower Line 3 Replacement (L3R) surcharge and lower Mainline System tolls as a result of new interim tolls effective July 1, 2023;
• higher contributions from our Liquids Pipelines segment due to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and the EIEC due to higher demand;
• the recognition of revenues in our Gas Transmission and Midstream segment attributable to the Texas Eastern Transmission, LP (Texas Eastern) rate case settlement;
• higher distribution charges at our Gas Distribution and Storage segment resulting from increases in rates and customer base as well as higher demand in the contract market;
• higher contributions from our Energy Services segment primarily due to the expiration of transportation commitments and favorable margins due to less pronounced market structure backwardation; and
• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022.

BUSINESS SEGMENTS

LIQUIDS PIPELINES

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was positively impacted by $245 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized loss of $38 million in 2023, compared with a net unrealized loss of $290 million in 2022, 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 $56 million increase is primarily explained by the following significant business factors:

• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; and
• higher contributions from the Gulf Coast and Mid-Continent System due primarily to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and higher volumes from the EIEC due to higher demand; partially offset by
• lower Mainline System tolls as a result of new interim tolls effective July 1, 2023 and a lower L3R surcharge; and
• lower volumes on the Flanagan South Pipeline.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was positively impacted by $399 million due to certain infrequent or other non-operating factors, primarily explained by the following:

• a non-cash, net unrealized gain of $592 million in 2023, compared with a net unrealized loss of $364 million in 2022, 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;
• the receipt of a litigation claim settlement of $68 million in 2023;
• the absence in 2023 of an asset impairment loss of $40 million relating to MacKay River line within our Alberta Regional Oil Sands System; partially offset by
• 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 negotiated Mainline tolling agreement.

After taking into consideration the factors above, the remaining $569 million increase is primarily explained by the following significant business factors:

• higher Mainline System ex-Gretna average throughput of 3.0 mmbpd in 2023 as compared to 2.9 mmbpd in 2022, net of a lower L3R surcharge and lower Mainline System tolls as a result of new interim tolls effective July 1, 2023;
• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; and
• higher contributions from the Gulf Coast and Mid-Continent System due primarily to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and the EIEC due to higher demand; partially offset by
• higher power costs as a result of increased volumes and power prices.

GAS TRANSMISSION AND MIDSTREAM

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was negatively impacted by $1,212 million due to certain infrequent or other non-operating factors, primarily explained by:

• the absence in 2023 of a gain of $1,076 million on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP; and
• a provision adjustment of $124 million related to a litigation matter.

The remaining $66 million decrease is primarily explained by the following significant business factors:

• lower commodity prices impacting our DCP and Aux Sable joint ventures;
• a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with P66 that closed during the third quarter of 2022; and
• lower AECO-Chicago basis differential impacting our investment in Alliance Pipeline; partially offset by
• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; and
• contributions from the acquisition of Tres Palacios Holdings LLC (Tres Palacios) in the second quarter of 2023.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was negatively impacted by $1,178 million due to certain infrequent or other non-operating factors, primarily explained by:

• the absence in 2023 of a gain of $1,076 million on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP; and
• a provision adjustment of $124 million related to a litigation matter; partially offset by
• a non-cash, net positive equity earnings adjustment of $5 million in 2023, compared to a net negative adjustment of $30 million in 2022 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable.

The remaining $14 million increase is primarily explained by the following significant business factors:

• the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022;
• the recognition of revenues attributable to the Texas Eastern rate case settlement effective for 2023;
• favorable contracting on our US Gas Transmission and Storage assets; and
• contributions from the Tres Palacios acquisition in the second quarter of 2023; partially offset by
• a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with P66 that closed during the third quarter of 2022;
• lower commodity prices impacting our DCP and Aux Sable joint ventures;
• higher operating and administrative costs; and
• lower AECO-Chicago basis differential impacting our investment in Alliance Pipeline.

GAS DISTRIBUTION AND STORAGE

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was negatively impacted by $15 million primarily due to the following significant business factors:

• higher storage demand and transportation costs of $35 million which represents a partial reversal of previously favorable timing of recognition of these costs; partially offset by
• higher distribution charges resulting from increases in rates and customer base.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was negatively impacted by $14 million primarily due to the following significant business factors:

• when compared with the normal weather forecast embedded in rates, warmer weather in 2023 and colder weather in 2022 negatively impacted EBITDA by approximately $68 million year over year; and
• higher operating and administrative costs primarily due to higher costs for line locates, higher integrity spend and higher pension related costs; partially offset by
• higher distribution charges resulting from increases in rates and customer base as well as higher demand in the contract market.

RENEWABLE POWER GENERATION

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was negatively impacted by $81 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized loss of $83 million in 2023, compared with a net unrealized gain of $2 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks.

The remaining $6 million increase is primarily explained by the following significant business factors:

• fees earned on certain wind and solar development contracts; partially offset by
• weaker wind resources and lower energy pricing at European offshore wind facilities.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was negatively impacted by $84 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized loss of $79 million in 2023, compared with a net unrealized gain of $6 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks.

The remaining $10 million decrease is primarily explained by the following significant business factors:

• weaker wind resources at North American and European wind facilities; and
• lower energy pricing at European offshore wind facilities; partially offset by
• fees earned on certain wind and solar development contracts; and
• contributions from the Saint-Nazaire Offshore Wind Project, which reached full operating capacity in December 2022.

ENERGY SERVICES

EBITDA from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was negatively impacted by $130 million due to certain non-operating factors, primarily explained by a non-cash, net unrealized loss of $66 million in 2023, compared with a net gain of $58 million in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as to manage the exposure to movements in commodity prices.

After taking into consideration the factors above, the remaining $94 million increase is primarily explained by:

• expiration of transportation commitments;
• favorable margins realized on facilities where we hold capacity obligations and storage opportunities; and
• less pronounced market structure backwardation as compared to the same period of 2022.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was positively impacted by $37 million due to certain non-operating factors, primarily explained by:

• a net positive adjustment to crude oil and natural gas inventories of $4 million in 2023, compared with a net negative adjustment of $67 million in 2022; partially offset by
• a non-cash, unrealized loss of $13 million in 2023, compared with an unrealized gain of $22 million in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices.

After taking into consideration the factors above, the remaining $228 million increase is primarily explained by the same significant business factors as discussed in the three months ended September 30, 2023 results.

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 and corporate investments.

Three months ended September 30, 2023, compared with the three months ended September 30, 2022

EBITDA was positively impacted by $311 million due to certain infrequent or non-operating factors, primarily explained by:

• a non-cash, net unrealized loss of $652 million in 2023, compared with a net loss of $1,046 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk; partially offset by
• the absence in 2023 of a net positive adjustment of $85 million due to the release of reserves associated with our enterprise insurance strategy; and
• transaction costs of $21 million incurred during the quarter ended September 30, 2023 as a result of the Acquisitions.

After taking into consideration the non-operating factors above, the remaining $45 million increase is primarily explained by higher investment income and higher realized foreign exchange gains on hedge settlements in 2023.

Nine months ended September 30, 2023, compared with the nine months ended September 30, 2022

EBITDA was positively impacted by $1,279 million due to certain infrequent or non-operating factors, primarily explained by:

• a non-cash, unrealized loss of $250 million in 2023, compared with an unrealized loss of $1,393 million in 2022, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;
• a net unrealized gain of $14 million in 2023, compared with a net loss of $39 million in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries; and
• the absence in 2023 of an impairment of $44 million for lease assets due to office relocation plans; partially offset by
• transaction costs of $21 million incurred during the quarter ended September 30, 2023 as a result of the Acquisitions.

After taking into consideration the non-operating factors above, the remaining $39 million decrease is primarily explained by lower realized foreign exchange gains on hedge settlements in 2023, as well as the timing of certain operating and administrative cost recoveries from the business units.

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, 2023.

3Includes the $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 2024.

4Capital cost estimates will be updated prior to filing the regulatory applications.

5Rio Grande LNG has reached a final investment decision for three liquefaction trains. Current estimated capital cost is based on two liquefaction trains and an update to the estimated capital cost is expected to be provided in 2024.

6Our 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.

7Our equity contribution is $103 million, with the remainder financed through non-recourse project level debt.

8Our equity contribution is $181 million, with the remainder financed through non-recourse project level debt.

A full description of each of our projects is provided in our annual report on Form 10-K for the year ended December 31, 2022. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.

GAS TRANSMISSION AND MIDSTREAM

Rio Bravo Pipeline

In July 2023, the Rio Grande LNG export facility, owned by NextDecade Corporation (NextDecade), reached a final investment decision. As a result, the construction on our previously announced Rio Bravo Pipeline project is anticipated to proceed after obtaining necessary regulatory approvals. The first phase of the Rio Bravo Pipeline is designed to transport 2.6 bcf per day of natural gas feedstock to NextDecade's Rio Grande LNG export facility in the Port of Brownsville, Texas. The project is expected to achieve commercial operations in 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 $1.2 billion, which are expected to be paid over the next four 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. Our current financing plan does not include any issuances of additional common equity.

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, 2023:

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 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion and in July 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, we renewed approximately $6.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2025, which includes a one-year term out provision from July 2024. We also renewed approximately $7.6 billion of our five-year credit facilities, extending the maturity dates to July 2028. Further, we extended our three-year credit facilities, extending the maturity dates to July 2026.

In September 2023, we obtained commitments for a US$9.4 billion senior unsecured bridge term loan credit facility to support the Acquisitions. The commitment for this facility was subsequently reduced to US$3.4 billion as at September 30, 2023 as a result of the $4.6 billion equity offering and the September 2023 subordinated long-term debt issuances.

In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $712 million was unutilized as at September 30, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized.

As at September 30, 2023, our net available liquidity totaled $20.4 billion (December 31, 2022 - $10.0 billion), consisting of available credit facilities of $17.8 billion (December 31, 2022 - $9.1 billion) and unrestricted cash and cash equivalents of $2.6 billion (December 31, 2022 - $861 million) 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, 2023, we were in compliance with all covenant provisions.

LONG-TERM DEBT ISSUANCES

During the nine months ended September 30, 2023, we completed the following long-term debt issuances totaling US$5.0 billion and $2.9 billion:

1The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on September 8, 2031, the interest rate will be set to equal 5.70% plus 50 basis points.

2We have the option to call the notes at par after one year from issuance. Refer to Part 1. Item 1. Financial Statements - Note 8 - Risk Management and Financial Instruments.

3The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on November 26, 2031, the interest rate will be set to equal 5.36% plus 50 basis points.

4For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.43%. Subsequent to year 10, every five years, the Five-year US treasury rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.18%

5For the initialfive years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 3.79%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 4.04%. Subsequent to year 10, every five years, the Five-Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.79%.

6For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.96%. Subsequent to year 10, every five years, the Government of Canada bond yield rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.71%.

7For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.30%. At year 10, the interest rate will be reset to equal the Five-Year Government of Canada bond yield plus a margin of 4.55%. Subsequent to year 10, every five years, the Five-Year Government of Canada bond yield is reset. At year 25, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.30%.

In October 2023, Enbridge Gas closed a three-tranche offering consisting of five-year medium-term notes, 10-year medium-term notes, and 30-year medium-term notes, for an aggregate principal amount of $1.0 billion, which mature in October 2028, October 2033, and October 2053, respectively.

LONG-TERM DEBT REPAYMENTS

During the nine months ended September 30, 2023, we completed the following long-term debt repayments totaling US$1.2 billion and $1.3 billion:

1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 40 basis points.

2The five-year callable notes, with an original maturity date of April 2078, were all redeemed at par.

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 $39 million, as reported on 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, 2023 and December 31, 2022, we had positive and negative working capital positions of $1.5 billion and $2.1 billion, respectively. During the nine months ended September 30, 2023, the major contributing factor to the positive working capital position was due to settlement of current liabilities, while during the year ended December 31, 2022, the negative working capital position was due to current liabilities associated with our growth capital program. 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, 2023 and 2022 are summarized below:

Operating Activities

Typically, 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.

Changes in operating assets and liabilities increased period-over-period primarily due to a decline in gas inventory balances in 2023 compared to an increase in 2022 and the timing of natural gas cost recovery through rates, in Enbridge Gas.

Investing Activities

Cash used in investing activities primarily relates to 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 and changes in contributions to, and distributions from, our equity investments. Factors impacting the increase in cash used in investing activities period-over-period primarily include:

• the absence in 2023 of the proceeds received from the completion of a joint venture merger transaction for DCP Midstream, LLC on August 17, 2022; and
• our acquisition of Tres Palacios on April 3, 2023.

The factors above were partially offset by higher equity distributions in 2023 mainly related to our investment in NEXUS Gas Transmission, LLC.

Financing Activities

Cash 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 (NCIB). Cash used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the increase in cash used in financing activities period-over-period primarily include:

• net repayments of short-term borrowings and commercial paper and credit facilities in 2023 when compared to net draws during the same period in 2022;
• higher long-term debt repayments in 2023 when compared to the same period in 2022; and
• increase in common share dividend payments due to the increase in the common share dividend rate.

The factors above were partially offset by:

• higher long-term debt issuances in 2023 when compared to the same period in 2022;
• our public offering of common shares, which closed on September 8, 2023, resulting in the issuance of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion, which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions; and
• the absence in 2023 of the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022, respectively.

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) (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 Guarantee

1As at September 30, 2023, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.

2As at September 30, 2023, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

Enbridge Notes under Guarantees

1As at September 30, 2023, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$13.5 billion.

2As at September 30, 2023, the aggregate outstanding principal amount of the Enbridge Canadian dollar-denominated notes was approximately $11.0 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 EEP, SEP 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

Line 5 Easement (Bad River Band)

On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a complaint in the US District Court for the Western District of Wisconsin (the Court) over our Line 5 pipeline and right-of-way across the Bad River Reservation (the Reservation). Only a small portion of the total easements across 12 miles of the Reservation are at issue. The Band alleges that our continued use of Line 5 to transport crude oil and related liquids across the Reservation is a public nuisance under federal and state law and that the pipeline is in trespass on certain tracts of land in which the Band possesses ownership interests. The complaint seeks an Order prohibiting us from using Line 5 to transport crude oil and related liquids across the Reservation and requiring removal of the pipeline from the Reservation. Subsequently amended versions of the complaint also seek recovery of profits-based damages based on an unjust enrichment theory. Enbridge has responded to each claim in the initial and amended complaints with an answer, defenses and counterclaims.

On August 29, 2022, the Government of Canada released a statement formally invoking the dispute settlement provisions of the 1977 Transit Pipelines Treaty in respect of this litigation; reiterating its concerns about the uninterrupted transmission of hydrocarbons through Line 5. On September 7, 2022, the Court issued a decision on cross-motions for summary judgment. The Court determined that the Band's nuisance claim raised factual issues that could not be resolved on summary judgment. The Court further determined that Enbridge is in trespass on 12 parcels on the Reservation and that the Band is entitled to some measure of profits-based damages and to an injunction, with the level of damages and scope of the injunction to be determined at trial, which occurred October 24 through November 1, 2022.

On May 9, 2023, the Band filed an Emergency Motion for Injunctive Relief asking the Court to require Enbridge to purge and shutdown Line 5 on the Reservation due to significant erosion at the Meander. Enbridge responded and a hearing was held on May 18, 2023 in front of Judge Conley who indicated that he did not find the Band had proven imminence but his final ruling on all issues would be provided soon.

On June 26, 2023, the Court issued its Final Order ruling that (1) Enbridge shall adopt and implement its 2022 Monitoring and Shutdown Plan with the Court's modifications by July 5, 2023; (2) Enbridge owes the Band $5,151,668 for past trespass on the 12 allotted parcels; (3) Enbridge must continue to pay money on a quarterly basis using the formula set in its Order as long as Line 5 operates in trespass on the 12 allotted parcels (approximately $400,000 per year); (4) Enbridge must cease operation of Line 5 on any parcel within the Band's tribal territory without a valid right of way by June 16, 2026 and thereafter arrange prompt, reasonable remediation at those sites; and (5) The Court declined to allow for the Relocation to be completed prior to having to cease operations. The Final Judgment was entered on June 29, 2023. Enbridge filed its Notice of Appeal on June 30, 2023 and the Band filed its Notice of Cross Appeal on July 27, 2023. The 7th Circuit Court of Appeals (7th Circuit) issued a Notice of Telephonic Mediation for July 21, 2023, which occurred as scheduled. On July 31, 2023, the Court entered the parties agreed upon briefing schedule. According to that schedule, briefing should be complete on or before December 11, 2023, with oral argument and a decision expected in 2024.

Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement

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 in 1953 that we have 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), where it was assigned to Judge Janet T. Neff. 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. On December 21, 2021, the AG made a request to file a motion to remand the 2019 case, which the US District Court allowed on January 5, 2022. However, after full briefing, on August 18, 2022, Judge Neff denied the AG's motion to remand. On August 30, 2022, the AG filed a motion to certify the August 18 Order to pursue an appeal on the jurisdictional issue, which Enbridge opposed. On February 21, 2023, that motion was granted and shortly after, on March 2, 2023, the AG filed her Petition for Permission to Appeal in the 6th Circuit Court of Appeals (6th Circuit).

On July 21, 2023, the 6th Circuit granted the AG's Petition for Permission to appeal the US District Court's August 18 Order denying remand to state court. The 6th Circuit's briefing schedule has briefing being complete by the end of 2023. Once briefing concludes, the 6th Circuit will schedule an oral argument date. We anticipate a decision in 2024.

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 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 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 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 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 District Court's July 6 order to shut down and empty the pipeline.

On January 26, 2021, the US Court of Appeals affirmed the 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 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. A public comment period commenced on the issuance of the draft EIS, with comments due by November 13, 2023. The pipeline will remain operational while the environmental review process continues.

Aux Sable

On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim.

On November 27, 2019, the counterparty filed an amended amended claim providing further particulars of its claim against Aux Sable, increasing its damages claimed, and adding defendants Aux Sable Liquid Products Inc. and Aux Sable Extraction LLC (general partners of the previously existing defendants). Aux Sable filed an amended Statement of Defence responding to the amended amended claim on January 31, 2020.

During the third quarter of 2023, a provision was recognized in relation to the claim impacting Enbridge's share of earnings from Aux Sable. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on our consolidated financial position or results of operations.

OTHER LITIGATION

We and our subsidiaries are involved in 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.

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, 2022. 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, 2023, 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, 2023 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, 2022, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors, other than as set forth below.

RISKS RELATING TO THE ACQUISITIONS

One or all of the Acquisitions may not occur on the terms contemplated in the applicable Purchase and Sale Agreement or at all, or may not occur within the expected time frame, which may negatively affect the benefits we expect to obtain from the Acquisitions.

We cannot provide any assurance that the Acquisitions will be completed in the manner, on the terms and on the time frame currently anticipated, or at all. Completion of each of the Acquisitions is subject to the satisfaction or waiver of a number of conditions as set forth in the applicable Purchase and Sale Agreement that are beyond our control and may prevent, delay or otherwise materially adversely affect its completion.

The success of the Acquisitions will depend on, among other things, our ability to integrate the Gas Utilities into our business in a manner that facilitates growth opportunities and achieves anticipated benefits of the Acquisitions. There is a significant degree of difficulty and management distraction inherent in the process of integrating an acquisition, including challenges consolidating certain operations and functions (including regulatory functions), integrating technologies, organizations, procedures, policies and operations, addressing differences in the business cultures of Enbridge and the Gas Utilities and retaining key personnel. The integration may be complex and time consuming and involve delays or additional and unforeseen expenses. The integration process and other disruptions resulting from the Acquisitions may also disrupt our ongoing business.

Any failure to realize the anticipated benefits of the Acquisitions, additional unanticipated costs or other factors could negatively impact our earnings or cash flows, decrease or delay any beneficial effects of the Acquisitions and negatively impact our business, financial condition and results of operations.