EX-99.1 2 ei-ex991newsreleasexdocume.htm EX-99.1
NEWS RELEASE
Enbridge Reports Strong Third Quarter 2023 Financial Results and Reaffirms Financial Guidance and Outlook
CALGARY, AB, November 3, 2023 /CNW/ - Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) today reported third quarter 2023 financial results, reaffirmed its 2023 financial outlook and provided a quarterly business update.
Highlights
(All financial figures are unaudited and in Canadian dollars unless otherwise noted. * identifies non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.)
•Third quarter GAAP earnings of $0.5 billion or $0.26 per common share, compared with GAAP earnings of $1.3 billion or $0.63 per common share in 2022
•Adjusted earnings* of $1.3 billion or $0.62 per common share*, compared with $1.4 billion or $0.67 per common share in 2022
•Adjusted earnings before interest, income taxes and depreciation and amortization (EBITDA)* of $3.9 billion, an increase of 3%, compared with $3.8 billion in 2022
•Cash provided by operating activities of $3.1 billion, compared with $2.1 billion in 2022
•Distributable cash flow (DCF)* of $2.6 billion, an increase of $0.1 billion, compared with $2.5 billion in 2022
•Reaffirmed 2023 full year financial guidance for EBITDA and DCF inclusive of the recent share offering dilution
•Enbridge entered into definitive agreements (the "Acquisitions") with Dominion Energy, Inc. ("Dominion") 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 US$14 billion (CDN$19 billion)
•Enbridge has filed applications for all key federal and state required regulatory approvals to complete the pending Acquisitions and approximately 75% of the financing for the aggregate purchase price has been secured
•Signed an agreement to increase ownership in Hohe See Offshore Wind Farm and Albatros Offshore Wind Farm by a further 24.45%, bringing Enbridge's interest to 49.89%, for €625 million (including €358 million of assumed debt)
•Signed a definitive agreement to acquire seven operating landfill-to-renewable natural gas (RNG) assets located in Texas and Arkansas for US$1.2 billion with staggered consideration
•Upsized and relaunched the Flanagan South Pipeline (FSP) binding open season for US Gulf Coast delivery service
•Closed the acquisition of Aitken Creek Gas Storage on November 1
•Debt-to-EBITDA expected to exit the year below the target range of 4.5x to 5.0x reflecting substantial equity pre-funding prior to closing the Acquisitions
1

CEO COMMENT
"Despite ongoing market volatility, Enbridge's four businesses delivered another solid quarter of financial performance. We saw high utilization across our systems delivering reliable, affordable, and sustainable energy for our customers while upholding industry leading safety standards. We're tracking to plan and expect to achieve our 2023 EBITDA and DCF per share guidance for the 18th consecutive year.
"During the quarter, we announced the strategic acquisition of three U.S. gas utilities, and post closings, Enbridge will have created North America’s largest gas utility platform, with approximately 7,000 employees proudly serving some 7 million customers. This was a rare and unprecedented opportunity to acquire large, growing natural gas utilities located in supportive regulatory regimes at a historically attractive valuation. The utilities are accretive to Enbridge’s value proposition offering reliable cash flows, enhancing our low-risk growth profile and further diversifying our asset base. We are confident these Acquisitions will strengthen our ongoing dividend growth profile and deliver strong total shareholder returns.
"We’re on track to close the Acquisitions in 2024 and have filed all applications for required approvals in the states with jurisdiction for regulating the utilities. Since announcement, we have secured approximately 75% of the required financing and have flexibility to use various alternatives including bonds, our ongoing capital recycling program, reinstatement of our dividend reinvestment and share purchase plan (DRIP), or at-the-market (ATM) equity issuances, to fund the remaining balance. We have established a dedicated integration team which will ensure a seamless transition of the gas utilities' businesses into Enbridge’s operations while continuing to deliver the service our existing and new customers expect.
“In our Liquids business, we continue to see record utilization across the system, including the Mainline. Interim tolls took effect on July 1 st and the Mainline Tolling Settlement is expected to be filed with the Canada Energy Regulator by year end. At Ingleside, we exported record volumes underscoring the growing global demand and our competitive advantage in providing customers with the most cost-effective path from the Permian to tidewater. Lastly, based on customer feedback, we upsized and relaunched our Flanagan South open season, plan to initiate an open season for Gray Oak in the fourth quarter and will offer full-path service via exports through Enbridge Ingleside Energy Center (EIEC).
"In Gas Transmission, we are continuing to expand our existing infrastructure to support the growing demand for safe, reliable and affordable natural gas. We are currently holding an open season on Algonquin which will provide much needed supply in New England and will help to stabilize energy prices. In addition, we closed the acquisition of Aitken Creek on November 1 st which will further enhance our Western Canadian LNG export strategy.
“In our Gas Distribution business in Ontario, we are expecting another strong year of customer growth, and the OEB has approved a partial settlement proposal on the first phase of our rebasing application in Ontario. We expect the OEB to issue a final decision on the remaining issues for 2024 rates by the end of the year.
“In Renewables, we're adding to our existing European portfolio by almost doubling our economic interest in the Hohe See and Albatros German offshore wind projects. This acquisition is expected to be immediately accretive to DCF per share and will be complementary to both our growth outlook and energy transition ambitions.
“We are also excited to announce that Enbridge is acquiring seven operating landfill-to-renewable natural gas assets located in Texas and Arkansas from Morrow Renewables. This transaction represents a uniquely de-risked portfolio of operating and scalable RNG assets. These fully contracted landfill gas-to-RNG facilities are immediately accretive to DCF per share and will accelerate progress toward our energy transition goals. I am pleased to welcome the Morrow Renewables team members to the Enbridge family.
"We continue to exercise capital allocation discipline and each investment will earn attractive risk-adjusted returns. Year to date, we have executed over $3 billion of accretive tuck-in M&A and are on track to place approximately $3 billion of capital into service by year end. Our balance sheet continues to be strong and the funding requirements for all of the newly announced projects were contemplated at the time of the gas utilities acquisitions. We exited the quarter with Debt-to-EBITDA at the lower end of our target range, even prior to accounting for the beneficial impact of pre-funding the Acquisitions.”
2

FINANCIAL RESULTS SUMMARY
Financial results for the three and nine months ended September 30, 2023 and 2022 are summarized in the table below:

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars, except per share amounts; number of shares in millions) |  |  |  |  |
GAAP Earnings attributable to common shareholders | 532 |  | 1,279 |  |  | 4,113 |  | 3,656 |
GAAP Earnings per common share | 0.26 |  | 0.63 |  |  | 2.02 |  | 1.80 |
Cash provided by operating activities | 3,084 |  | 2,144 |  |  | 10,389 |  | 7,617 |
Adjusted EBITDA 1 | 3,871 |  | 3,758 |  |  | 12,347 |  | 11,620 |
Adjusted Earnings 1 | 1,274 |  | 1,366 |  |  | 4,380 |  | 4,421 |
Adjusted Earnings per common share 1 | 0.62 |  | 0.67 |  |  | 2.15 |  | 2.18 |
Distributable Cash Flow 1 | 2,573 |  | 2,501 |  |  | 8,535 |  | 8,320 |
Weighted average common shares outstanding | 2,048 |  | 2,025 |  |  | 2,033 |  | 2,026 |

1 Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.
GAAP earnings attributable to common shareholders for the third quarter of 2023 decreased by $747 million or $0.37 per share compared with the same period in 2022, primarily due to certain non-operating factors including 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 realigning our indirect economic interests in Gray Oak Pipeline LLC, (Gray Oak) and DCP Midstream, LP (DCP) and 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 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 period-over-period comparability of GAAP earnings attributable to common shareholders is impacted by certain unusual, infrequent factors or other non-operating factors which are noted in the reconciliation schedule included in Appendix A of this news release. Refer to the Company's Management's Discussion & Analysis for the third quarter of 2023 filed in conjunction with the third quarter financial statements for a detailed discussion of GAAP financial results.
Adjusted EBITDA in the third quarter of 2023 increased by $113 million compared with the same period in 2022. This was primarily driven by contributions from increased economic interests in the Gray Oak Pipeline and the Cactus II Pipeline during the second half of 2022 and early 2023, and higher volumes on the Mainline, the Gray Oak Pipeline and at EIEC. These factors were partially offset by a decrease in earnings from our reduced interest in DCP, lower commodity prices impacting DCP and Aux Sable, a lower Mainline toll and the timing of Gas Distribution storage demand and transportation costs.
Adjusted earnings in the third quarter of 2023 decreased by $92 million, or $0.05 per share, primarily due to higher financing costs due to higher interest rates, higher depreciation expense from assets placed into service last year, and higher earnings attributable to non-controlling interests from the sale of an 11.57% non-operating interest in seven Enbridge-operated pipelines to Athabasca Indigenous Investments in Q3, 2022, partially offset by higher Adjusted EBITDA contributions discussed above.
3

DCF for the third quarter of 2023 increased by $72 million, primarily due to higher Adjusted EBITDA contributions discussed above, as well as higher cash distributions in excess of equity earnings from Gray Oak Pipelines and DCP, partially offset by higher financing costs due to higher interest rates, the timing of maintenance capital spend and higher distributions to noncontrolling interests as noted above.
Detailed financial information and analysis can be found below under Third Quarter 2023 Financial Results.
FINANCIAL OUTLOOK
The Company reaffirms its 2023 financial guidance for EBITDA and DCF. Results for the first nine months of 2023 are in line with the Company's expectations and the Company anticipates that its businesses will continue to experience strong capacity utilization and operating performance through the balance of the year with normal course seasonality.
Strong operational performance in the first nine months of the year is expected to be offset by higher financing costs, due to increased interest rates, pre-funding of the U.S. gas utilities acquisitions and a lower toll on the Mainline.
FINANCING UPDATE
Pre-Funding the Acquisitions
Since the announcement of the Acquisitions, Enbridge has pre-funded approximately $8.3 billion of the $12.8 billion (US$9.4 billion) cash consideration, significantly de-risking the execution of the Company’s funding plan.
This pre-funding included the issuance of 102.9 million common shares (the "Offering") for gross proceeds of approximately CDN$4.6 billion inclusive of underwriters’ 15% over-allotment. The Company also issued US$2.0 billion of 60-year hybrid subordinated notes in the U.S. and $1.0 billion of 60-year hybrid subordinated notes in Canada (together “the Hybrid Issuances”) which will receive partial equity treatment from rating agencies. These debt offerings were substantially hedged at favorable rates relative to the market at the time of issuance.
Enbridge intends to use the aggregate net proceeds from the Offering and the Hybrid Issuances to pay down existing indebtedness in the near-term and ultimately will finance a portion of the aggregate cash consideration payable for the Acquisitions. The remaining funding requirements can be readily satisfied over the coming year through a variety of alternate sources, including the issuance of senior unsecured notes, the Company’s ongoing capital recycling program, the potential reinstatement of Enbridge’s Dividend Reinvestment and Share Purchase Plan, or initiating ATM common share issuances.
General
On August 17 th, 2023, Enbridge Pipelines Inc., a wholly-owned subsidiary of Enbridge, issued $350 million of 30-year senior notes. This debt offering was entirely hedged at attractive rates.
On October 4 th, 2023, Enbridge Gas Inc., a wholly-owned subsidiary of Enbridge, issued $1 billion of senior notes consisting of $250 million of 5-year senior notes, $400 million of 10-year senior notes, and $350 million of 30-year senior notes. These debt offerings were partially hedged at rates favorable to the market.
Proceeds from these offerings were used to repay short-term debt, for capital expenditures and for general corporate purposes.
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Enbridge anticipates exiting 2023 with its Debt-to-EBITDA metric below the bottom end of its 4.5x to 5.0x target range due to pre-funding of the Acquisitions.
SECURED GROWTH PROJECT EXECUTION UPDATE
During the third quarter, the Company added approximately $5 billion of growth capital to its secured capital program, predominantly from the U.S. Gas Utility growth program (assuming successful closings of the Acquisitions).
The Company's current secured growth program is now approximately $24 billion through 2028. The Company expects to place approximately $3 billion into service in 2023 inclusive of the Gas Transmission's Modernization and Gas Distribution's Utility Growth Capital programs. The secured growth program is underpinned by commercial frameworks consistent with Enbridge's low-risk model.
BUSINESS UPDATES
Enbridge's Acquisition of Gas Utilities from Dominion
On September 5, 2023, Enbridge 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 for an aggregate purchase price of US$14.0 billion, comprised of US$9.4 billion of cash consideration and US$4.6 billion of assumed debt, subject to customary closing adjustments. The Acquisitions continue to be expected to close in 2024, subject to the satisfaction of customary closing conditions, including the receipt of required U.S. federal and state regulatory approvals. To date, the Company has significantly de-risked the Acquisitions funding plan, and retains considerable optionality around the remaining unfunded amount.
In the weeks following the announcement of the Acquisitions, Enbridge established a dedicated integration team to ensure a seamless transition of the gas utilities into the Company's existing operations. Enbridge and Dominion's regulatory teams are in the process of securing the required U.S. federal and state regulatory approvals to complete the Acquisitions. The waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act expired on November 1.
Increasing European Offshore Wind Footprint in Germany
Enbridge, through its wholly owned subsidiary, has signed a definitive agreement with a wholly owned subsidiary of Canada Pension Plan Investment Board (CPP Investments) to purchase its interests in the Hohe See Offshore Wind Farm and Albatros Offshore Wind Farm for total consideration of €625 million, comprised of €267 million of cash and €358 million of assumed debt. Together, the wind farms produce a combined 2.5 million megawatt hours of electricity, supplying energy to more than 700,000 households. This acquisition will add accretive, government-backed distributable cash flow to Enbridge's regionally diversified and growing renewable portfolio. Enbridge will indirectly own 49.89% of Hohe See and Albatros (25.44% prior to closing of the acquisition).
5

Acquiring High Quality Operating Landfill-to-RNG Facilities
Enbridge has agreed to acquire seven operating landfill-to-renewable natural gas assets located in Texas and Arkansas from Morrow Renewables, reflecting our commitment to become an industry leader in RNG. The Morrow assets collect, compress, and treat pipeline-quality RNG from landfills, all located in regions with growing demographics and supportive municipal partnerships. In aggregate, the projects produce over 4bcf of RNG per year and will generate D3 Renewable Identification Numbers (RINs). Aggregate consideration is expected to total US$1.2 billion. The assets will add immediate EBITDA and are expected to be accretive in their first full year of ownership. The transaction is expected to close in early 2024, with approximately 60% of the consideration to be staggered over the following two years.
Enbridge Gas Inc 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.
Enbridge relaunches Flanagan South Open Season
Based on market feedback, the Company upsized and relaunched an open season for long-term contracted service on Flanagan South Pipeline. FSP provides service from the Enbridge Mainline originating at Enbridge's Flanagan Terminal in Illinois and delivers near Houston, Texas through the Seaway Pipeline. If the open season is successful, FSP will approach 90% term-contracted on its 720 kbpd capacity, reinforcing strong utilization on the full pathway, including FSP and through the Mainline.
Mainline Tolling Agreement
In the second quarter, Enbridge 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 U.S. portions of the Mainline and sees the Mainline continuing to operate as a common carrier system available to all shippers on a monthly nomination basis. Enbridge expects to file the settlement, which will be subject to regulatory and other approvals, with the Canada Energy Regulator by year end.
6

THIRD QUARTER 2023 FINANCIAL RESULTS
GAAP Segment EBITDA and Cash Flow from Operations

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Liquids Pipelines | 2,247 |  | 1,946 |  |  | 7,061 |  | 6,093 |
Gas Transmission and Midstream | 973 |  | 2,251 |  |  | 3,220 |  | 4,384 |
Gas Distribution and Storage | 271 |  | 286 |  |  | 1,354 |  | 1,368 |
Renewable Power Generation | 30 |  | 105 |  |  | 295 |  | 389 |
Energy Services | (106) |  | (70) |  |  | (83) |  | (348) |
Eliminations and Other | (579) |  | (935) |  |  | (44) |  | (1,284) |
EBITDA 1 | 2,836 |  | 3,583 |  |  | 11,803 |  | 10,602 |
Earnings attributable to common shareholders | 532 |  | 1,279 |  |  | 4,113 |  | 3,656 |
Cash provided by operating activities | 3,084 |  | 2,144 |  |  | 10,389 |  | 7,617 |

1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
For purposes of evaluating performance, the Company makes adjustments to GAAP reported earnings, segment EBITDA and cash flow provided by operating activities for unusual, infrequent or other non-operating factors, which allow Management and investors to more accurately compare the Company’s performance across periods, normalizing for factors that are not indicative of underlying business performance. Tables incorporating these adjustments follow below. Schedules reconciling EBITDA, adjusted EBITDA, adjusted EBITDA by segment, adjusted earnings, adjusted earnings per share and DCF to their closest GAAP equivalent are provided in the Appendices to this news release.
Adjusted EBITDA By Segment
Adjusted EBITDA generated from U.S. dollar denominated businesses was translated to Canadian dollars a t a higher a verage exchange rate (C$1.34/US$) in the third quarter of 2023 when compared with the same quarter in 2022 (C$1.31/US$). A significant portion of U.S. dollar earnings are hedged under the Company's enterprise-wide financial risk management program. The hedge settlements are reported within Eliminations and Other.
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Liquids Pipelines

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Mainline System | 1,306 |  | 1,271 |  |  | 4,096 |  | 3,778 |
Regional Oil Sands System | 246 |  | 236 |  |  | 726 |  | 694 |
Gulf Coast and Mid-Continent Systems 1 | 396 |  | 375 |  |  | 1,244 |  | 1,006 |
Other Systems 2 | 377 |  | 387 |  |  | 1,084 |  | 1,103 |
Adjusted EBITDA 3 | 2,325 |  | 2,269 |  |  | 7,150 |  | 6,581 |
Operating Data (average deliveries – thousands of bpd) |  |  |  |  |
Mainline System volume 4 | 2,998 |  | 2,966 |  |  | 3,066 |  | 2,917 |
Canadian International Joint Tariff 5 ($C) | $1.65 |  | $— |  |  | $1.65 |  | $— |
U.S. International Joint Tariff 5 ($US) | $2.57 |  | $— |  |  | $2.57 |  | $— |
Competitive Tolling Settlement IJT and surcharges 6 | $— |  | $4.53 |  |  | $— |  | $4.53 |
Line 3 Replacement Surcharge ($US)6,7 | $0.76 |  | $0.85 |  |  | $0.79 |  | $0.91 |

1 Consists of Flanagan South Pipeline, Seaway Pipeline, Gray Oak Pipeline, Cactus II Pipeline, Enbridge Ingleside Energy Center, and others.
2 Other consists of Southern Lights Pipeline, Express-Platte System, Bakken System, and others.
3 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
4 Mainline System throughput volume represents Mainline System deliveries ex-Gretna, Manitoba which is made up of U.S. and Eastern Canada deliveries originating from Western Canada.
5 Interim tariff tolls in effect, per barrel, for heavy crude oil movements from Hardisty, AB to Chicago, IL. Effective July 1, 2023 the Company is collecting a dual currency, international joint tariff in line with the agreement in principle on a negotiated settlement for tolls on the Mainline pipeline system. Excludes abandonment surcharge.
6 Includes the IJT benchmark toll, for heavy crude oil movements from Hardisty, AB to Chicago, IL, and its components are set in U.S. dollars and Competitive Tolling Settlement Surcharges which were in effect on an interim basis from July 1, 2021 until June 30, 2023. Effective July 1, 2023 the Company is collecting a new dual currency, international joint tariff in line with the agreement in principle on a negotiated settlement for tolls on the Mainline pipeline system.
7 Effective July 1, 2022, the Line 3 Replacement Surcharge (L3R), exclusive of the receipt terminalling surcharge, will be determined on a monthly basis by a volume ratchet based on the 9-month rolling average of ex-Gretna volumes. Each 50 kbpd volume ratchet above 2,835 kbpd (up to 3,085 kbpd) applies a US$0.035/bbl discount whereas each 50 kbpd volume ratchet below 2,350 kbpd (down to 2,050 kbpd) adds a US$0.04/bbl charge. Refer to Enbridge’s Application for a Toll Order respecting the implementation of the L3R Surcharges and CER Order TO-003-2021 for further details.
Liquids Pipelines adjusted EBITDA increased $56 million compared with the third quarter of 2022, primarily related to:
•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;
•higher volumes from Gray Oak Pipeline and Enbridge Ingleside Energy Center; and
•the favorable effect of translating U.S. dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; partially offset by
•lower Mainline System tolls as a result of new interim tolls effective July 1, 2023 and a lower L3R surcharge, net of higher Mainline volume throughput; and
•lower volumes on FSP.
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Gas Transmission And Midstream

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
U.S. Gas Transmission | 864 | 853 |  |  | 2,600 |  | 2,372 |
Canadian Gas Transmission | 136 | 157 |  |  | 458 |  | 485 |
Midstream | 45 | 114 |  |  | 114 |  | 334 |
Other | 47 | 34 |  |  | 142 |  | 109 |
Adjusted EBITDA 1 | 1,092 |  | 1,158 |  |  | 3,314 |  | 3,300 |

1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
•
Gas Transmission and Midstream adjusted EBITDA decreased $66 million compared with the third quarter of 2022, primarily related to:
•lower Midstream contributions from lower commodity prices impacting our DCP and Aux Sable joint ventures;
•lower Midstream contributions from a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with Phillips 66 that closed during the third quarter in 2022; and
•lower contributions from Enbridge's investment in the Alliance Pipeline due to lower AECO-Chicago basis differential; partially offset by
•the favorable effect of translating U.S. dollar earnings at a higher average exchange rate in 2023, compared to the same period in 2022; and
•contributions from the Tres Palacios acquisition in the second quarter of 2023.
Gas Distribution And Storage

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Enbridge Gas Inc. (EGI) | 265 |  | 285 |  |  | 1,322 |  | 1,358 |
Other | 6 |  | 8 |  |  | 32 |  | 31 |
Adjusted EBITDA 1 | 271 |  | 293 |  |  | 1,354 |  | 1,389 |
Operating Data |  |  |  |  |
EGI |  |  |  |  |
Volumes (billions of cubic feet) | 405 |  | 349 |  |  | 1,598 |  | 1,556 |
Number of active customers 2 (millions) | 3.9 |  | 3.8 |  |  | 3.9 |  | 3.8 |
Heating degree days 3 |  |  |  |  |
Actual | 61 |  | 79 |  |  | 2,266 |  | 2,602 |
Forecast based on normal weather 4 | 88 |  | 91 |  |  | 2,495 |  | 2,535 |

1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
2 Number of active customers is the number of natural gas consuming customers at the end of the reported period.
3 Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in EGI's distribution franchise areas.
4 Normal weather is the weather forecast by EGI in its legacy rate zones, using the forecasting methodologies approved by the Ontario Energy Board.
Gas Distribution and Storage adjusted EBITDA will typically follow a seasonal profile. It is generally highest in the first and fourth quarters of the year reflecting greater volumetric demand during the heating season. The magnitude of the seasonal EBITDA fluctuations will vary from year-to-year reflecting the impact of colder or warmer than normal weather on distribution volumes.
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Adjusted EBITDA for the third quarter was negatively impacted by $22 million primarily explained by 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.
When compared with the normal weather forecast embedded in rates, the impact of weather was negligible for the third quarter of 2023 and 2022.
Renewable Power Generation

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA 1 | 119 |  | 113 |  |  | 390 |  | 400 |

1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
Renewable Power Generation adjusted EBITDA increased $6 million compared with the third quarter of 2022 primarily related to:
•fees earned on certain wind and solar development contracts; partially offset by
•weaker wind resources and lower energy pricing at European offshore wind facilities.
Energy Services

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA 1 | (38) |  | (132) |  |  | (74) |  | (302) |

1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
Adjusted 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.
Energy Services adjusted EBITDA increased $94 million compared with the third quarter of 2022 primarily related to:
•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.
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Eliminations and Other

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Operating and administrative recoveries | 57 |  | 22 |  |  | 135 |  | 107 |
Realized foreign exchange hedge settlement gains | 45 |  | 35 |  |  | 78 |  | 145 |
Adjusted EBITDA 1 | 102 |  | 57 |  |  | 213 |  | 252 |

1 Non-GAAP financial measure. Please refer to Non-GAAP Reconciliations Appendices.
Operating and administrative recoveries captured in this segment reflect the cost of centrally delivered services (including depreciation of corporate assets) inclusive of amounts recovered from business units for the provision of those services. U.S. dollar denominated earnings within operating segment results are translated at average foreign exchange rates during the quarter, and the impact of settlements made under the Company's enterprise foreign exchange hedging program are captured in this corporate segment.
Eliminations and Other adjusted EBITDA increased $45 million compared with the third quarter of 2022 due to the timing of O&A recoveries and higher realized foreign exchange gains on hedge settlements.
Distributable Cash Flow

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars; number of shares in millions) |  |  |  |  |
Liquids Pipelines | 2,325 |  | 2,269 |  |  | 7,150 |  | 6,581 |
Gas Transmission and Midstream | 1,092 |  | 1,158 |  |  | 3,314 |  | 3,300 |
Gas Distribution and Storage | 271 |  | 293 |  |  | 1,354 |  | 1,389 |
Renewable Power Generation | 119 |  | 113 |  |  | 390 |  | 400 |
Energy Services | (38) |  | (132) |  |  | (74) |  | (302) |
Eliminations and Other | 102 |  | 57 |  |  | 213 |  | 252 |
Adjusted EBITDA 1,3 | 3,871 |  | 3,758 |  |  | 12,347 |  | 11,620 |
Maintenance capital | (249) |  | (215) |  |  | (648) |  | (466) |
Interest expense 1 | (912) |  | (837) |  |  | (2,759) |  | (2,357) |
Current income tax 1 | (131) |  | (129) |  |  | (395) |  | (391) |
Distributions to noncontrolling interests 1 | (87) |  | (60) |  |  | (282) |  | (184) |
Cash distributions in excess of equity earnings 1 | 112 |  | 9 |  |  | 315 |  | 153 |
Preference share dividends 1 | (89) |  | (81) |  |  | (260) |  | (254) |
Other receipts of cash not recognized in revenue 2 | 50 |  | 48 |  |  | 173 |  | 173 |
Other non-cash adjustments | 8 |  | 8 |  |  | 44 |  | 26 |
DCF 3 | 2,573 |  | 2,501 |  |  | 8,535 |  | 8,320 |
Weighted average common shares outstanding | 2,048 |  | 2,025 |  |  | 2,033 |  | 2,026 |

1 Presented net of adjusting items.
2 Consists of cash received, net of revenue recognized, for contracts under make-up rights and similar deferred revenue arrangements.
3 Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.
Third quarter 2023 DCF increased $72 million compared with the same period of 2022 primarily due to operational factors discussed above contributing to higher Adjusted EBITDA, as well as:
•higher cash distributions in excess of equity earnings from Gray Oak Pipeline and DCP; partially offset by
•higher interest rates primarily impacting floating-rate debt;
•delayed timing of maintenance capital spend in prior year; and
11

•higher distributions to noncontrolling interests from the sale of 11.57% non-operating interest in seven Enbridge-operated pipelines to Athabasca Indigenous Investments in Q3, 2022.
Adjusted Earnings

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Adjusted EBITDA 1,2 | 3,871 |  | 3,758 |  |  | 12,347 |  | 11,620 |
Depreciation and amortization | (1,200) |  | (1,104) |  |  | (3,554) |  | (3,272) |
Interest expense 2 | (900) |  | (826) |  |  | (2,743) |  | (2,324) |
Income taxes 2 | (363) |  | (360) |  |  | (1,252) |  | (1,274) |
Noncontrolling interests 2 | (45) |  | (20) |  |  | (158) |  | (58) |
Preference share dividends | (89) |  | (82) |  |  | (260) |  | (271) |
Adjusted earnings 1 | 1,274 |  | 1,366 |  |  | 4,380 |  | 4,421 |
Adjusted earnings per common share 1 | 0.62 |  | 0.67 |  |  | 2.15 |  | 2.18 |

1 Non-GAAP financial measures. Please refer to Non-GAAP Reconciliations Appendices.
2 Presented net of adjusting items.
Adjusted earnings decreased $92 million and adjusted earnings per share decreased by $0.05 when compared with the third quarter in 2022 primarily due to operational factors discussed above contributing to higher Adjusted EBITDA, offset by:
•higher depreciation from assets place into service in 2022;
•higher interest expense due to higher interest rates impacting floating-rate debt; and
•higher earnings attributable to noncontrolling interests from the sale of 11.57% non-operating interest in seven Enbridge-operated pipelines to Athabasca Indigenous Investments in Q3, 2022.
CONFERENCE CALL
Enbridge will host a conference call and webcast on November 3, 2023 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to provide a business update and review 2023 third quarter results. Analysts, members of the media and other interested parties can access the call toll free at 1-800-606-3040. The call will be audio webcast live at https://app.webinar.net/9kl65EWmGK z. It is recommended that participants dial in or join the audio webcast fifteen minutes prior to the scheduled start time. A webcast replay will be available soon after the conclusion of the event and a transcript will be posted to the website. The replay will be available for seven days after the call toll-free 1-(800)-606-3040 (conference ID: 9581867).
The conference call format will include prepared remarks from the executive team followed by a question and answer session for the analyst and investor community only. Enbridge’s media and investor relations teams will be available after the call for any additional questions.
12

DIVIDEND DECLARATION
On October 31, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2023 to shareholders of record on November 15, 2023.

| Dividend per share |
Common Shares | $0.88750 |  |
Preference Shares, Series A | $0.34375 |  |
Preference Shares, Series B | $0.32513 |  |
Preference Shares, Series D | $0.33825 |  |
Preference Shares, Series F | $0.34613 |  |
Preference Shares, Series G 1 | $0.47245 |  |
Preference Shares, Series H 2 | $0.38200 |  |
Preference Shares, Series I 3 | $0.44814 |  |
Preference Shares, Series L | US$0.36612 |  |
Preference Shares, Series N | $0.31788 |  |
Preference Shares, Series P | $0.27369 |  |
Preference Shares, Series R | $0.25456 |  |
Preference Shares, Series 1 | US$0.41898 |  |
Preference Shares, Series 3 | $0.23356 |  |
Preference Shares, Series 5 | US$0.33596 |  |
Preference Shares, Series 7 | $0.27806 |  |
Preference Shares, Series 9 | $0.25606 |  |
Preference Shares, Series 11 | $0.24613 |  |
Preference Shares, Series 13 | $0.19019 |  |
Preference Shares, Series 15 | $0.18644 |  |
Preference Shares, Series 19 | $0.38825 |  |

1 On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. The quarterly dividend per share paid on Preference Shares, Series G was increased to $0.47245 from $0.43858 on September 1, 2023 due to reset on a quarterly basis following the date of issuance.
2 The quarterly dividend per share paid on Preference Shares, Series H was increased to $0.38200 from $0.27350 on September 1, 2023, due to reset of the annual dividend on September 1, 2023.
3 On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series
I. The first quarterly dividend on Preference Shares, Series I will be paid on December 1, 2023.
13

FORWARD-LOOKING INFORMATION
Forward-looking information, or forward-looking statements, have been included in this news release to provide information about Enbridge and its subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: Enbridge’s corporate vision and strategy, including our strategic priorities and outlook; 2023 financial guidance and near and medium term outlooks, including projected DCF per share and adjusted EBITDA and expected growth thereof; expected dividends, dividend growth and dividend policy; the acquisitions of three gas utilities from Dominion Energy, Inc. (the Acquisitions), including the characteristics, anticipated benefits, expected timing of closing and integration thereof; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas liquids (NGL), liquified natural gas (LNG) and renewable energy; energy transition and low carbon energy and our approach thereto; anticipated utilization of our assets; expected EBITDA and expected adjusted EBITDA; expected earnings/(loss) and adjusted earnings/(loss); expected DCF and DCF per share; expected future cash flows; expected shareholder returns and asset returns; expected performance of the Company’s businesses; financial strength and flexibility; financing costs and plans, including with respect to the Acquisitions; expectations on leverage, including debt-to EBITDA ratio; sources of liquidity and sufficiency of financial resources; expected in-service dates and costs related to announced projects and projects under construction; capital allocation framework and priorities; impact of weather and seasonality; expected future growth and expansion opportunities, including secured growth program, development opportunities, customer growth and low carbon opportunities and strategy, including with respect to the landfill-to-RNG assets ; Flanagan South Pipeline open season; expected closings, benefits and timing of transactions, including with respect to the Acquisitions; expected future actions and decisions of regulators and courts and the timing and impact thereof; and toll and rate case discussions and filings, including with respect to the Mainline settlement in principle and Gas Distribution's rate rebasing application, and anticipated timing and impact therefrom.
Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, NGL, LNG and renewable energy; prices of crude oil, natural gas, NGL, LNG and renewable energy; anticipated utilization of our assets; exchange rates; inflation; interest rates; availability and price of labour and construction materials; the stability of our supply chain; operational reliability and performance; maintenance of support and regulatory approvals for our projects, transactions and rate applications, including the Acquisitions; anticipated in-service dates; weather; announced and potential acquisition, disposition and other corporate transactions and projects and the timing and benefits thereof, including with respect to the Acquisitions; governmental legislation; litigation; credit ratings; hedging program; expected EBITDA and expected adjusted EBITDA; expected earnings/(loss) and adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected future DCF and DCF per share; estimated future dividends; financial strength and flexibility; debt and equity market conditions; and general economic and competitive conditions. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL, LNG and renewable energy and the prices of these commodities are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs and are therefore inherent in all forward-looking statements. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of
14

labour and construction materials; the stability of our supply chain; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather; the timing and closing of acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; and customer, government, court and regulatory approvals on construction and in-service schedules.
Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities; operating performance; regulatory parameters; litigation; acquisitions and dispositions and other transactions, and the realization of anticipated benefits therefrom; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; global geopolitical conditions; political decisions; public opinion; dividend policy; changes in tax laws and tax rates; exchange rates; interest rates; inflation; commodity prices; and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this news release and in Enbridge’s other filings with Canadian and U.S. securities regulators. The impact of any one assumption, risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty, as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statement made in this news release or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.
15

ABOUT ENBRIDGE INC.
At Enbridge, we safely connect millions of people to the energy they rely on every day, fueling quality of life through our North American natural gas, oil or renewable power networks and our growing European offshore wind portfolio. We're investing in modern energy delivery infrastructure to sustain access to secure, affordable energy and building on two decades of experience in renewable energy to advance new technologies including wind and solar power, hydrogen, renewable natural gas and carbon capture and storage. We're committed to reducing the carbon footprint of the energy we deliver, and to achieving net zero greenhouse gas emissions by 2050. Headquartered in Calgary, Alberta, Enbridge's common shares trade under the symbol ENB on the Toronto (TSX) and New York (NYSE) stock exchanges. To learn more, visit us at enbridge.com
None of the information contained in, or connected to, Enbridge’s website is incorporated in or otherwise forms part of this news release.

FOR FURTHER INFORMATION PLEASE CONTACT: |  |
Enbridge Inc. – Media |  | Enbridge Inc. – Investment Community
Jesse Semko |  | Rebecca Morley
Toll Free: (888) 992-0997 |  | Toll Free: (800) 481-2804
Email: media@enbridge.com |  | Email: investor.relations@enbridge.com

16

NON-GAAP RECONCILIATIONS APPENDICES
This news release contains references to EBITDA, adjusted EBITDA, adjusted earnings, adjusted earnings per common share and DCF. Management believes the presentation of these metrics gives useful information to investors and shareholders, as they provide increased transparency and insight into the performance of the Company.
EBITDA represents earnings before interest, tax, depreciation and amortization.
Adjusted EBITDA represents EBITDA adjusted for unusual, infrequent or other non-operating factors on both a consolidated and segmented basis. Management uses EBITDA and adjusted EBITDA to set targets and to assess the performance of the Company and its business units.
Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, infrequent or other non-operating factors included in adjusted EBITDA, as well as adjustments for unusual, infrequent or other non-operating factors in respect of depreciation and amortization expense, interest expense, income taxes and noncontrolling interests on a consolidated basis. Management uses adjusted earnings as another measure of the Company’s ability to generate earnings.
DCF is defined as cash flow provided by operating activities before the impact of changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests, preference share dividends and maintenance capital expenditures and further adjusted for unusual, infrequent or other non-operating factors. Management also uses DCF to assess the performance of the Company and to set its dividend payout target.
This news release also contains references to Debt-to-EBITDA, a non-GAAP ratio which utilizes adjusted EBITDA as one of its components. Debt-to-EBITDA is used as a liquidity measure to indicate the amount of adjusted earnings to pay debt, as calculated on the basis of generally accepted accounting principles in the United States of America (U.S. GAAP), before covering interest, tax, depreciation and amortization.
Reconciliations of forward-looking non-GAAP financial measures and non-GAAP ratios to comparable
GAAP measures are not available due to the challenges and impracticability of estimating certain items, particularly certain contingent liabilities and non-cash unrealized derivative fair value losses and gains subject to market variability. Because of those challenges, a reconciliation of forward-looking non-GAAP financial measures and non-GAAP ratios is not available without unreasonable effort.
Our non-GAAP financial measures and non-GAAP ratios described above are not measures that have standardized meaning prescribed by U.S. GAAP and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers.
The tables below provide a reconciliation of the non-GAAP measures to comparable GAAP measures.
17

APPENDIX A
NON-GAAP RECONCILIATIONS – ADJUSTED EBITDA AND ADJUSTED EARNINGS
CONSOLIDATED EARNINGS

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Liquids Pipelines | 2,247 | 1,946 |  |  | 7,061 |  | 6,093 |
Gas Transmission and Midstream | 973 | 2,251 |  |  | 3,220 |  | 4,384 |
Gas Distribution and Storage | 271 | 286 |  |  | 1,354 |  | 1,368 |
Renewable Power Generation | 30 | 105 |  |  | 295 |  | 389 |
Energy Services | (106) | (70) |  |  | (83) |  | (348) |
Eliminations and Other | (579) | (935) |  |  | (44) |  | (1,284) |
EBITDA | 2,836 |  | 3,583 |  |  | 11,803 |  | 10,602 |
Depreciation and amortization | (1,164) |  | (1,076) |  |  | (3,447) |  | (3,195) |
Interest expense | (921) |  | (806) |  |  | (2,709) |  | (2,316) |
Income tax expense | (128) |  | (318) |  |  | (1,157) |  | (1,044) |
Earnings attributable to noncontrolling interests | (2) |  | (21) |  |  | (117) |  | (61) |
Preference share dividends | (89) |  | (83) |  |  | (260) |  | (330) |
Earnings attributable to common shareholders | 532 |  | 1,279 |  |  | 4,113 |  | 3,656 |

ADJUSTED EBITDA TO ADJUSTED EARNINGS

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Liquids Pipelines | 2,325 |  | 2,269 |  |  | 7,150 |  | 6,581 |
Gas Transmission and Midstream | 1,092 |  | 1,158 |  |  | 3,314 |  | 3,300 |
Gas Distribution and Storage | 271 |  | 293 |  |  | 1,354 |  | 1,389 |
Renewable Power Generation | 119 |  | 113 |  |  | 390 |  | 400 |
Energy Services | (38) |  | (132) |  |  | (74) |  | (302) |
Eliminations and Other | 102 |  | 57 |  |  | 213 |  | 252 |
Adjusted EBITDA | 3,871 |  | 3,758 |  |  | 12,347 |  | 11,620 |
Depreciation and amortization | (1,200) |  | (1,104) |  |  | (3,554) |  | (3,272) |
Interest expense | (900) |  | (826) |  |  | (2,743) |  | (2,324) |
Income tax expense | (363) |  | (360) |  |  | (1,252) |  | (1,274) |
Earnings attributable to noncontrolling interests | (45) |  | (20) |  |  | (158) |  | (58) |
Preference share dividends | (89) |  | (82) |  |  | (260) |  | (271) |
Adjusted earnings | 1,274 |  | 1,366 |  |  | 4,380 |  | 4,421 |
Adjusted earnings per common share | 0.62 |  | 0.67 |  |  | 2.15 |  | 2.18 |

18

EBITDA TO ADJUSTED EARNINGS

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
EBITDA | 2,836 |  | 3,583 |  |  | 11,803 |  | 10,602 |
Adjusting items: |  |  |  |  |
Change in unrealized derivative fair value (gain)/loss | 839 |  | 1,276 |  |  | (250) |  | 1,729 |
CTS realized hedge loss | — |  | — |  |  | 638 |  | — |
Litigation provisions and settlements | 124 |  | — |  |  | 56 |  | — |
Net inventory adjustment | 2 |  | (4) |  |  | (4) |  | 68 |
Assets impairment | — |  | 15 |  |  | — |  | 106 |
Gain on joint venture merger transaction | — |  | (1,076) |  |  | — |  | (1,076) |
Enterprise insurance strategy restructuring | — |  | (85) |  |  | — |  | 15 |
Transaction costs | 21 |  | — |  |  | 21 |  | — |
Other | 49 |  | 49 |  |  | 83 |  | 176 |
Total adjusting items | 1,035 |  | 175 |  |  | 544 |  | 1,018 |
Adjusted EBITDA | 3,871 |  | 3,758 |  |  | 12,347 |  | 11,620 |
Depreciation and amortization | (1,164) |  | (1,076) |  |  | (3,447) |  | (3,195) |
Interest expense | (921) |  | (806) |  |  | (2,709) |  | (2,316) |
Income tax expense | (128) |  | (318) |  |  | (1,157) |  | (1,044) |
Earnings attributable to noncontrolling interests | (2) |  | (21) |  |  | (117) |  | (61) |
Preference share dividends | (89) |  | (83) |  |  | (260) |  | (330) |
Adjusting items in respect of: |  |  |  |  |
Depreciation and amortization | (36) |  | (28) |  |  | (107) |  | (77) |
Interest expense | 21 |  | (20) |  |  | (34) |  | (8) |
Income tax expense | (235) |  | (42) |  |  | (95) |  | (230) |
Earnings attributable to noncontrolling interests | (43) |  | 1 |  |  | (41) |  | 3 |
Preference share dividends | — |  | 1 |  |  | — |  | 59 |
Adjusted earnings | 1,274 |  | 1,366 |  |  | 4,380 |  | 4,421 |
Adjusted earnings per common share | 0.62 |  | 0.67 |  |  | 2.15 |  | 2.18 |

19

APPENDIX B
NON-GAAP RECONCILIATION – ADJUSTED EBITDA TO SEGMENTED EBITDA
LIQUIDS PIPELINES

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 2,325 |  | 2,269 |  |  | 7,150 |  | 6,581 |
Change in unrealized derivative fair value gain/(loss)1 | (38) |  | (290) |  |  | 592 |  | (364) |
CTS realized hedge loss | — |  | — |  |  | (638) |  | — |
Assets impairment | — |  | (8) |  |  | — |  | (55) |
Litigation settlement gain | — |  | — |  |  | 68 |  | — |
Other | (40) |  | (25) |  |  | (111) |  | (69) |
Total adjustments | (78) |  | (323) |  |  | (89) |  | (488) |
EBITDA | 2,247 |  | 1,946 |  |  | 7,061 |  | 6,093 |

1 Related to derivative financial instruments used to manage foreign exchange and commodity price risks.
GAS TRANSMISSION AND MIDSTREAM

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 1,092 |  | 1,158 |  |  | 3,314 |  | 3,300 |
Litigation provision | (124) |  | — |  |  | (124) |  | — |
Gain from joint venture merger transaction | — |  | 1,076 |  |  | — |  | 1,076 |
Other | 5 |  | 17 |  |  | 30 |  | 8 |
Total adjustments | (119) |  | 1,093 |  |  | (94) |  | 1,084 |
EBITDA | 973 |  | 2,251 |  |  | 3,220 |  | 4,384 |

GAS DISTRIBUTION AND STORAGE

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 271 |  | 293 |  |  | 1,354 |  | 1,389 |
Other | — |  | (7) |  |  | — |  | (21) |
Total adjustments | — |  | (7) |  |  | — |  | (21) |
EBITDA | 271 |  | 286 |  |  | 1,354 |  | 1,368 |

20

RENEWABLE POWER GENERATION

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 119 |  | 113 |  |  | 390 |  | 400 |
Change in unrealized derivative fair value gain/(loss) - Foreign exchange | 1 |  | 2 |  |  | 5 |  | 6 |
Change in unrealized derivative fair value gain/(loss) - Commodity prices | (84) |  | — |  |  | (84) |  | — |
Other | (6) |  | (10) |  |  | (16) |  | (17) |
Total adjustments | (89) |  | (8) |  |  | (95) |  | (11) |
EBITDA | 30 |  | 105 |  |  | 295 |  | 389 |

ENERGY SERVICES

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | (38) |  | (132) |  |  | (74) |  | (302) |
Change in unrealized derivative fair value gain/(loss) - Commodity prices | (66) |  | 58 |  |  | (13) |  | 22 |
Net inventory adjustment | (2) |  | 4 |  |  | 4 |  | (68) |
Total adjustments | (68) |  | 62 |  |  | (9) |  | (46) |
EBITDA | (106) |  | (70) |  |  | (83) |  | (348) |

ELIMINATIONS AND OTHER

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Adjusted EBITDA | 102 |  | 57 |  |  | 213 |  | 252 |
Change in unrealized derivative fair value gain/(loss) - Foreign exchange | (652) |  | (1,046) |  |  | (250) |  | (1,393) |
Impairment of lease assets | — |  | (7) |  |  | — |  | (51) |
Enterprise insurance strategy restructuring | — |  | 85 |  |  | — |  | (15) |
Transaction costs | (21) |  | — |  |  | (21) |  | — |
Other | (8) |  | (24) |  |  | 14 |  | (77) |
Total adjustments | (681) |  | (992) |  |  | (257) |  | (1,536) |
EBITDA | (579) |  | (935) |  |  | (44) |  | (1,284) |

21

APPENDIX C
NON-GAAP RECONCILIATION – CASH PROVIDED BY OPERATING ACTIVITIES TO DCF

| Three months ended September 30, |  | Nine months ended September 30,
| 2023 | 2022 |  | 2023 | 2022
(unaudited; millions of Canadian dollars) |  |  |  |  |
Cash provided by operating activities | 3,084 |  | 2,144 |  |  | 10,389 |  | 7,617 |
Adjusted for changes in operating assets and liabilities 1 | (233) |  | 464 |  |  | (1,461) |  | 602 |
| 2,851 |  | 2,608 |  |  | 8,928 |  | 8,219 |
Distributions to noncontrolling interests 2 | (87) |  | (60) |  |  | (282) |  | (184) |
Preference share dividends | (89) |  | (81) |  |  | (260) |  | (254) |
Maintenance capital 3 | (249) |  | (215) |  |  | (648) |  | (466) |
Significant adjusting items: |  |  |  |  |
Other receipts of cash not recognized in revenue 4 | 50 |  | 48 |  |  | 173 |  | 173 |
Distributions from equity investments in excess of cumulative earnings 2 | 148 |  | 148 |  |  | 343 |  | 474 |
CTS realized hedge loss, net of tax | — |  | — |  |  | 479 |  | — |
Litigation settlement gain | — |  | — |  |  | (68) |  | — |
Enterprise insurance strategy restructuring expenses | — |  | — |  |  | — |  | 100 |
Other items | (51) |  | 53 |  |  | (130) |  | 258 |
DCF | 2,573 |  | 2,501 |  |  | 8,535 |  | 8,320 |

1 Changes in operating assets and liabilities, net of recoveries.
2 Presented net of adjusting items.
3 Maintenance capital includes expenditures that are required for the ongoing support and maintenance of the existing pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete or completing their useful lives). For the purpose of DCF, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets. Maintenance capital also excludes emissions reduction projects and large-scale asset modernization programs that facilitate high operational reliability.
4 Consists of cash received, net of revenue recognized, for contracts under make-up rights and similar deferred revenue arrangements.
22