enb-20240630

Entire Document

Enbridge Inc. filed this Form 10-Q on 8/2/2024

enb-20240630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM			10-Q


☒						QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2024


☐						TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-15254

_______________________________


ENBRIDGE INC.
(Exact Name of Registrant as Specified in Its Charter)


Canada						98-0377957
(State or Other Jurisdiction of Incorporation or Organization)						(I.R.S. Employer Identification No.)

200, 425 - 1st Street S.W.

Calgary, Alberta, Canada T2P 3L8

(Address of Principal Executive Offices) (Zip Code)

(403) 231-3900

(Registrant’s Telephone Number, Including Area Code)

_______________________________

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Shares

ENB

New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x

The registrant had 2,177,417,976 common shares outstanding as at July 26, 2024.


	PART I	PAGE

Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	64
Item 4.	Controls and Procedures	65

	PART II

Item 1.	Legal Proceedings	66
Item 1A.	Risk Factors	66
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66
Item 3.	Defaults Upon Senior Securities	66
Item 4.	Mine Safety Disclosures	66
Item 5.	Other Information	67
Item 6.	Exhibits	67
	Signatures	68

GLOSSARY


"we", "our", "us" and "Enbridge"			Enbridge Inc.
AG			Attorney General
Aitken Creek			Aitken Creek Gas Storage Facility
AOCI			Accumulated other comprehensive income/(loss)



CER			Canada Energy Regulator



EBITDA			Earnings before interest, income taxes and depreciation and amortization

EEP			Enbridge Energy Partners, L.P.





Enbridge Gas Ontario			Enbridge Gas Inc.

EOG			The East Ohio Gas Company

Exchange Act			United States Securities Exchange Act of 1934, as amended




LNG			Liquefied natural gas








MPLX			MPLX LP




NRGreen			NRGreen Power Limited Partnership
OCI			Other comprehensive income/(loss)

OEB			Ontario Energy Board
OPEB			Other postretirement benefits



Pembina			Pembina Pipeline Corporation
Phase 1 Decision			The Ontario Energy Board's Decision and Order on December 21, 2023, on Phase 1 of Enbridge Gas Inc.'s application to establish a 2024 through 2028 Incentive Regulation rate setting framework
Questar			Questar Gas Company

SEP			Spectra Energy Partners, LP
Texas Eastern			Texas Eastern Transmission, LP





the Acquisitions			Enbridge Inc.'s acquisitions of three US gas utilities from Dominion Energy, Inc.
the ATM Program			The at-the-market equity issuance program





the EOG Acquisition			Enbridge Inc.'s acquisition of all of the outstanding shares of capital stock of The East Ohio Gas Company on March 6, 2024

the Partnerships			Spectra Energy Partners, LP and Enbridge Energy Partners, L.P.
the Questar Acquisition			Enbridge Inc.'s acquisition of all of the membership interests of Fall West Holdco LLC which owns 100% of Questar Gas Company and its related Wexpro companies on May 31, 2024


the Whistler Parent JV			The joint venture formed by Enbridge Inc., WhiteWater/I Squared Capital and MPLX LP on May 29, 2024
Tomorrow RNG			Six Morrow Renewables operating landfill gas-to-renewable natural gas production facilities

US			United States of America

Wexpro			Wexpro Company and its consolidated subsidiaries

CONVENTIONS

The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge.

Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to "dollars" or "$" are to Canadian dollars and all references to "US$" are to United States (US) dollars. All amounts are provided on a before-tax basis, unless otherwise stated.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this quarterly report on Form 10-Q to provide information about us and our subsidiaries and affiliates, including management’s assessment of our and our 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", "believe", "estimate", "expect", "forecast", "intend", "likely", "plan", "project", "target" 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: our corporate vision and strategy, including strategic priorities and enablers; expected supply of, demand for, exports of and prices of crude oil, natural gas, natural gas liquids (NGL), liquefied natural gas (LNG), renewable natural gas (RNG) and renewable energy; energy transition and lower-carbon energy, and our approach thereto; environmental, social and governance goals, practices and performance; industry and market conditions; anticipated utilization of our assets; dividend growth and payout policy; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected strategic priorities and performance of the Liquids Pipelines, Gas Transmission, Gas Distribution and Storage and Renewable Power Generation businesses; the characteristics, anticipated benefits, financing and timing of our acquisitions and other transactions, including the acquisitions of three US gas utilities (Gas Utilities) from Dominion Energy, Inc. (the Acquisitions); expected costs, benefits and in-service dates related to announced projects and projects under construction; expected capital expenditures; investable capacity and capital allocation priorities; expected equity funding requirements for our commercially secured growth program; expected future growth, development and expansion opportunities; expected optimization and efficiency opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; our ability to complete the remaining acquisition of Public Service Company of North Carolina, Incorporated (the PSNC Acquisition) and successfully integrate the Gas Utilities; expected closing of other acquisitions and dispositions and the timing thereof, including the remaining PSNC Acquisition; expected future actions of regulators and courts, and the timing and impact thereof; toll and rate cases discussions and proceedings and anticipated timeline and impact therefrom, including those relating to the Gas Transmission and Gas Distribution and Storage businesses; operational, industry, regulatory, climate change and other risks associated with our businesses; and our assessment of the potential impact of the various risk factors identified herein.

Although we believe 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, demand for, export of and prices of crude oil, natural gas, NGL, LNG, RNG and renewable energy; anticipated utilization of assets; exchange rates; inflation; interest rates; availability and price of labor and construction materials; the stability of our supply chain; operational reliability; maintenance of support and regulatory approvals for our projects and transactions; anticipated in-service dates; weather; the timing, terms and closing of acquisitions and dispositions, including the remaining PSNC Acquisition; the realization of anticipated benefits of transactions, including the Acquisitions; governmental legislation; litigation; estimated future dividends and impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; hedging program; expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected future cash flows; and expected distributable cash flow. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL, LNG, RNG 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 labor and construction materials; the stability of our supply chain; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities; operating performance; legislative and regulatory parameters; litigation; acquisitions (including the Acquisitions), dispositions and other transactions and the realization of anticipated benefits therefrom; operational dependence on third parties; dividend policy; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; public opinion; changes in tax laws and tax rates; exchange rates; inflation; interest rates; commodity prices; access to and cost of capital; political decisions; global geopolitical conditions; and the supply of, demand for and prices of commodities and other alternative energy, including but not limited to, those risks and uncertainties discussed in this quarterly report on Form 10-Q and in our other filings with Canadian and US 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 quarterly report on Form 10-Q 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.

NON-GAAP AND OTHER FINANCIAL MEASURES

Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this quarterly report on Form 10-Q makes reference to non-GAAP and other financial measures, including EBITDA. EBITDA is defined as earnings before interest, income taxes and depreciation and amortization. Management uses EBITDA to assess performance of Enbridge and to set targets. Management believes the presentation of EBITDA gives useful information to investors as it provides increased transparency and insight into the performance of Enbridge.

The non-GAAP and other financial measures are not measures that have a standardized meaning prescribed by the accounting principles generally accepted in the United States of America (US GAAP) and are not US GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. A reconciliation of historical non-GAAP and other financial measures to the most directly comparable GAAP measures is set out in this MD&A and is available on our website. Additional information on non-GAAP and other financial measures may be found on our website, www.sedarplus.ca or www.sec.gov.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	5,291	4,679	9,436	9,462
Gas distribution sales	780	792	2,479	3,071
Transportation and other services	5,265	4,961	10,459	9,974
Total operating revenues (Note 3)	11,336	10,432	22,374	22,507
Operating expenses
Commodity costs	5,173	4,549	9,179	9,185
Gas distribution costs	309	368	1,303	1,962
Operating and administrative	2,308	2,028	4,442	4,065
Depreciation and amortization	1,273	1,137	2,466	2,283

Total operating expenses	9,063	8,082	17,390	17,495
Operating income	2,273	2,350	4,984	5,012
Income from equity investments	489	478	1,185	995

Gain on disposition of equity investments (Note 6)	1,091	—	1,091	—
Other income/(expense) (Note 12)	(31)	575	(582)	677
Interest expense	(1,082)	(883)	(1,987)	(1,788)
Earnings before income taxes	2,740	2,520	4,691	4,896
Income tax expense	(739)	(519)	(1,125)	(1,029)
Earnings	2,001	2,001	3,566	3,867
Earnings attributable to noncontrolling interests	(58)	(66)	(111)	(115)
Earnings attributable to controlling interests	1,943	1,935	3,455	3,752
Preference share dividends	(95)	(87)	(188)	(171)
Earnings attributable to common shareholders	1,848	1,848	3,267	3,581
Earnings per common share attributable to common shareholders (Note 5)	0.86	0.91	1.53	1.77
Diluted earnings per common share attributable to common shareholders (Note 5)	0.86	0.91	1.53	1.77

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(unaudited; millions of Canadian dollars)
Earnings	2,001	2,001	3,566	3,867
Other comprehensive income/(loss), net of tax
Change in unrealized gain on cash flow hedges	12	166	128	121
Change in unrealized gain/(loss) on net investment hedges	(161)	385	(538)	400
Other comprehensive income from equity investees	2	—	1	—
Excluded components of fair value hedges	—	2	4	9
Reclassification to earnings of loss on cash flow hedges	9	12	9	19
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(5)	(4)	(9)	(8)

Foreign currency translation adjustments	727	(1,458)	2,385	(1,517)
Other comprehensive income/(loss), net of tax	584	(897)	1,980	(976)
Comprehensive income	2,585	1,104	5,546	2,891
Comprehensive income attributable to noncontrolling interests	(72)	(34)	(160)	(98)
Comprehensive income attributable to controlling interests	2,513	1,070	5,386	2,793
Preference share dividends	(95)	(87)	(188)	(171)
Comprehensive income attributable to common shareholders	2,418	983	5,198	2,622

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares


Balance at beginning and end of period	6,818	6,818	6,818	6,818
Common shares
Balance at beginning of period	69,201	64,774	69,180	64,760
Shares issued, net of issue costs (Note 8)	2,489	—	2,489	—
Shares issued on exercise of stock options	1	—	5	2
Shares issued on vesting of restricted stock units (RSU), net of tax	7	—	24	12
Share repurchases at stated value	—	(80)	—	(80)

Balance at end of period	71,698	64,694	71,698	64,694
Additional paid-in capital
Balance at beginning of period	274	274	268	275
Stock-based compensation	21	18	53	38
Stock options exercised	(1)	(1)	(5)	(2)
Vested RSUs	(22)	—	(44)	(20)


Balance at end of period	272	291	272	291
Deficit
Balance at beginning of period	(15,696)	(13,753)	(17,115)	(15,486)
Earnings attributable to controlling interests	1,943	1,935	3,455	3,752
Preference share dividends	(95)	(87)	(188)	(171)
Common share dividends declared	(1,946)	(1,796)	(1,946)	(1,796)

Share repurchases in excess of stated value	—	(45)	—	(45)

Balance at end of period	(15,794)	(13,746)	(15,794)	(13,746)
Accumulated other comprehensive income (Note 9)
Balance at beginning of period	3,664	3,426	2,303	3,520
Other comprehensive income/(loss) attributable to common shareholders, net of tax	570	(865)	1,931	(959)
Balance at end of period	4,234	2,561	4,234	2,561




Total Enbridge Inc. shareholders’ equity	67,228	60,618	67,228	60,618
Noncontrolling interests
Balance at beginning of period	3,042	3,486	3,029	3,511
Earnings attributable to noncontrolling interests	58	66	111	115
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain on cash flow hedges	2	1	8	18
Foreign currency translation adjustments	12	(33)	41	(35)
	14	(32)	49	(17)
Comprehensive income attributable to noncontrolling interests	72	34	160	98
Distributions	(89)	(103)	(167)	(195)
Contributions	—	4	2	8

Other	—	(1)	1	(2)
Balance at end of period	3,025	3,420	3,025	3,420
Total equity	70,253	64,038	70,253	64,038
Dividends paid per common share	0.92	0.89	1.84	1.78

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six months ended June 30,
	2024	2023
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	3,566	3,867
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	2,466	2,283
Deferred income tax expense	613	919
Unrealized derivative fair value loss/(gain), net (Note 10)	923	(1,135)
Income from equity investments	(1,185)	(995)
Distributions from equity investments	1,037	1,066


Gain on disposition of equity investments	(1,091)	—

Other	143	72
Changes in operating assets and liabilities	(507)	1,228
Net cash provided by operating activities	5,965	7,305
Investing activities
Capital expenditures	(2,533)	(2,093)
Long-term, restricted and other investments	(1,294)	(472)
Distributions from equity investments in excess of cumulative earnings	463	752
Additions to intangible assets	(93)	(104)
Acquisitions	(10,454)	(487)
Proceeds from disposition of equity investments	2,724	—

Net change in affiliate loans	—	71
Other	(43)	—
Net cash used in investing activities	(11,230)	(2,333)
Financing activities
Net change in short-term borrowings	(200)	(1,148)
Net change in commercial paper and credit facility draws	2,963	(2,847)
Debenture and term note issues, net of issue costs	6,348	5,598
Debenture and term note repayments	(4,561)	(2,281)
Contributions from noncontrolling interests	2	8
Distributions to noncontrolling interests	(167)	(195)
Common shares issued, net of issue costs	2,485	—
Common shares repurchased	—	(125)
Preference share dividends	(188)	(171)
Common share dividends	(3,890)	(3,595)

Net change in affiliate loans	15	50
Other	(20)	(64)
Net cash provided by/(used in) financing activities	2,787	(4,770)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	192	(19)
Net change in cash and cash equivalents and restricted cash	(2,286)	183
Cash and cash equivalents and restricted cash at beginning of period	5,985	907
Cash and cash equivalents and restricted cash at end of period	3,699	1,090

The accompanying notes are an integral part of these interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION


	June 30, 2024	December 31, 2023
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	3,586	5,901
Restricted cash	113	84
Trade receivables and unbilled revenues	4,714	4,410
Other current assets	2,586	2,440
Accounts receivable from affiliates	138	85
Inventory	1,362	1,479
	12,499	14,399
Property, plant and equipment, net	120,288	104,641
Long-term investments	18,228	16,793
Restricted long-term investments	756	717
Deferred amounts and other assets	10,204	8,041
Intangible assets, net	4,505	3,537
Goodwill	34,316	31,848
Deferred income taxes	467	341
Total assets	201,263	180,317

Liabilities and equity
Current liabilities
Short-term borrowings	200	400
Trade payables and accrued liabilities	4,568	4,308
Other current liabilities	3,752	5,659
Accounts payable to affiliates	17	26
Interest payable	1,082	958
Current portion of long-term debt	6,711	6,084
	16,330	17,435
Long-term debt	85,181	74,715
Other long-term liabilities	11,586	8,653
Deferred income taxes	17,913	15,031
	131,010	115,834
Contingencies (Note 13)
Equity
Share capital
Preference shares	6,818	6,818
Common shares (2,177 and 2,125 outstanding at June 30, 2024 and December 31, 2023, respectively)	71,698	69,180
Additional paid-in capital	272	268
Deficit	(15,794)	(17,115)
Accumulated other comprehensive income (Note 9)	4,234	2,303

Total Enbridge Inc. shareholders’ equity	67,228	61,454
Noncontrolling interests	3,025	3,029
	70,253	64,483
Total liabilities and equity	201,263	180,317

The accompanying notes are an integral part of these interim consolidated financial statements.

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2023. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2023. Amounts are stated in Canadian dollars unless otherwise noted.

Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as supply of and demand for crude oil and natural gas, and may not be indicative of annual results. Our current year earnings are also impacted by the effect of acquisitions and dispositions, if any, occurring during the remaining six months period ending December 31, 2023.

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

2. CHANGES IN ACCOUNTING POLICIES

FUTURE ACCOUNTING POLICY CHANGES

Segment Reporting

Accounting Standards Update (ASU) 2023-07 was issued in November 2023 to improve reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and to require in interim period financial statements all disclosures about a reportable segment's profit or loss and assets that are currently required annually. The new ASU requires entities to disclose the title and position of the individual or the name of the group or committee identified as the chief operating decision-maker (CODM). ASU 2023-07 is effective January 1, 2024, with interim period disclosure requirements effective after January 1, 2025 and should be applied retrospectively to all prior periods presented in the financial statements. We are currently assessing the impact of the new standard on our annual disclosures for the year ending December 31, 2024 and on our interim financial statement disclosures beginning in 2025.

Income Tax Disclosures

ASU 2023-09 was issued in December 2023 to improve income tax disclosures by requiring specified categories in the annual rate reconciliation that meet quantitative thresholds and further disaggregation on income taxes paid by jurisdiction. ASU 2023-09 is effective January 1, 2025 and should be applied prospectively, with retrospective application being permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

3. REVENUE

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services


Three months ended June 30, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	2,986	1,290	469	—	—	4,745
Storage and other revenue	65	135	127	—	—	327

Gas distribution revenue	—	—	773	—	—	773
Electricity revenue	—	—	—	44	—	44
Commodity sales	—	38	—	—	—	38
Total revenue from contracts with customers	3,051	1,463	1,369	44	—	5,927
Commodity sales	5,036	11	—	—	206	5,253
Other revenue1,2	71	13	13	59	—	156
Intersegment revenue	—	5	2	3	(10)	—
Total revenue	8,158	1,492	1,384	106	196	11,336


Three months ended June 30, 2023	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	3,002	1,290	169	—	—	4,461
Storage and other revenue	62	113	85	—	—	260

Gas distribution revenue	—	—	796	—	—	796
Electricity revenue	—	—	—	75	—	75

Total revenue from contracts with customers	3,064	1,403	1,050	75	—	5,592
Commodity sales	4,404	—	—	—	275	4,679
Other revenue1,2	79	7	(1)	76	—	161
Intersegment revenue	—	—	1	(1)	—	—
Total revenue	7,547	1,410	1,050	150	275	10,432


Six months ended June 30, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	6,010	2,631	820	—	—	9,461
Storage and other revenue	127	273	226	—	—	626

Gas distribution revenue	—	—	2,439	—	—	2,439
Electricity revenue	—	—	—	101	—	101
Commodity sales	—	78	—	—	—	78
Total revenue from contracts with customers	6,137	2,982	3,485	101	—	12,705
Commodity sales	8,769	52	—	—	537	9,358
Other revenue1,2	134	19	26	132	—	311
Intersegment revenue	—	11	4	4	(19)	—
Total revenue	15,040	3,064	3,515	237	518	22,374

Six months ended June 30, 2023	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other	Consolidated
(millions of Canadian dollars)
Transportation revenue	5,944	2,674	445	—	—	9,063
Storage and other revenue	126	208	184	—	—	518

Gas distribution revenue	—	—	3,083	—	—	3,083
Electricity revenue	—	—	—	141	—	141

Total revenue from contracts with customers	6,070	2,882	3,712	141	—	12,805
Commodity sales	8,666	—	—	—	796	9,462
Other revenue1,2	109	18	(41)	154	—	240
Intersegment revenue	—	1	4	(1)	(4)	—
Total revenue	14,845	2,901	3,675	294	792	22,507

1Includes realized and unrealized gains and losses from our hedging program which for the three months ended June 30, 2024 were a net $17 million loss (2023 - $3 million gain) and for the six months ended June 30, 2024 were a net $39 million loss (2023 - $52 million loss).

2Includes revenues from lease contracts for the three months ended June 30, 2024 and 2023 of $142 million and $136 million, respectively, and for the six months ended June 30, 2024 and 2023 of $282 million and $280 million, respectively.

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

Contract Balances


	Contract Receivables	Contract Assets	Contract Liabilities
(millions of Canadian dollars)
Balance as at June 30, 2024	2,190	333	2,620
Balance as at December 31, 2023	2,802	400	2,591

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

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

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenues. Revenue recognized during the three and six months ended June 30, 2024 included in contract liabilities at the beginning of the period were $82 million and $233 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and six months ended June 30, 2024 were $149 million and $266 million, respectively.

Performance Obligations

There were no material revenues recognized in the three and six months ended June 30, 2024 from performance obligations satisfied in previous periods.

Revenues to be Recognized from Unfulfilled Performance Obligations

Total revenues from performance obligations expected to be fulfilled in future periods is $59.7 billion, of which $4.1 billion and $8.2 billion are expected to be recognized during the remaining six months ending December 31, 2024 and the year ending December 31, 2025, respectively.

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

Mainline Tolling Agreement

On March 4, 2024, the Canada Energy Regulator (CER) approved the negotiated Mainline tolling settlement. The new tolls are finalized and were in effect on an interim basis on July 1, 2023, and the overall agreement is retroactively effective as of July 1, 2021.

Recognition and Measurement of Revenues


Three months ended June 30, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	38	33	—	71
Revenues from products and services transferred over time1	3,051	1,425	1,336	44	5,856
Total revenue from contracts with customers	3,051	1,463	1,369	44	5,927

Three months ended June 30, 2023	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	37	—	37
Revenues from products and services transferred over time1	3,064	1,403	1,013	75	5,555
Total revenue from contracts with customers	3,064	1,403	1,050	75	5,592

Six months ended June 30, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	78	62	—	140
Revenues from products and services transferred over time1	6,137	2,904	3,423	101	12,565
Total revenue from contracts with customers	6,137	2,982	3,485	101	12,705

Six months ended June 30, 2023	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time	—	—	67	—	67
Revenues from products and services transferred over time1	6,070	2,882	3,645	141	12,738
Total revenue from contracts with customers	6,070	2,882	3,712	141	12,805

1Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

4. SEGMENTED INFORMATION

Change in Reportable Segments

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


Three months ended June 30, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other1	Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)	8,158	1,492	1,384	106	196	11,336
Commodity and gas distribution costs	(4,909)	(41)	(312)	2	(222)	(5,482)
Operating and administrative	(1,100)	(604)	(528)	(71)	(5)	(2,308)


Income/(loss) from equity investments	284	164	1	45	(5)	489

Gain on disposition of equity investments (Note 6)	—	1,063	—	28	—	1,091
Other income/(expense) (Note 12)	17	21	22	28	(119)	(31)
Earnings/(loss) before interest, income taxes and depreciation and amortization	2,450	2,095	567	138	(155)	5,095
Depreciation and amortization						(1,273)
Interest expense						(1,082)
Income tax expense						(739)
Earnings						2,001
Capital expenditures2	209	666	433	48	8	1,364


Three months ended June 30, 2023	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other1	Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)	7,547	1,410	1,050	150	275	10,432
Commodity and gas distribution costs	(4,295)	—	(371)	(2)	(249)	(4,917)
Operating and administrative	(1,092)	(588)	(325)	(62)	39	(2,028)


Income/(loss) from equity investments	253	199	1	27	(2)	478


Other income (Note 12)	14	21	12	16	512	575
Earnings before interest, income taxes and depreciation and amortization	2,427	1,042	367	129	575	4,540
Depreciation and amortization						(1,137)
Interest expense						(883)
Income tax expense						(519)
Earnings						2,001
Capital expenditures2	237	343	346	23	27	976


Six months ended June 30, 2024	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other1	Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)	15,040	3,064	3,515	237	518	22,374
Commodity and gas distribution costs	(8,544)	(88)	(1,316)	(1)	(533)	(10,482)
Operating and administrative	(2,207)	(1,165)	(907)	(140)	(23)	(4,442)


Income/(loss) from equity investments	537	429	1	226	(8)	1,185

Gain on disposition of equity investments (Note 6)	—	1,063	—	28	—	1,091
Other income/(expense) (Note 12)	28	57	39	45	(751)	(582)
Earnings/(loss) before interest, income taxes and depreciation and amortization	4,854	3,360	1,332	395	(797)	9,144
Depreciation and amortization						(2,466)
Interest expense						(1,987)
Income tax expense						(1,125)
Earnings						3,566
Capital expenditures2	498	1,161	737	117	51	2,564


Six months ended June 30, 2023	Liquids Pipelines	Gas Transmission	Gas Distribution and Storage	Renewable Power Generation	Eliminations and Other1	Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)	14,845	2,901	3,675	294	792	22,507
Commodity and gas distribution costs	(8,427)	—	(1,983)	(6)	(731)	(11,147)
Operating and administrative	(2,227)	(1,137)	(634)	(115)	48	(4,065)


Income/(loss) from equity investments	501	437	1	62	(6)	995


Other income (Note 12)	88	46	24	30	489	677
Earnings before interest, income taxes and depreciation and amortization	4,780	2,247	1,083	265	592	8,967
Depreciation and amortization						(2,283)
Interest expense						(1,788)
Income tax expense						(1,029)
Earnings						3,867
Capital expenditures2	517	870	610	68	52	2,117

1Includes operating revenues and commodity costs from our natural gas and power marketing subsidiaries for the three months ended June 30, 2024 of $205 million (2023 - $276 million) and $222 million (2023 - $251 million), respectively, and for the six months ended June 30, 2024 of $537 million (2023 - $796 million) and $544 million (2023 - $750 million), respectively.

2Includes the equity component of the allowance for funds used during construction.

5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

BASIC

Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding.

DILUTED

The treasury stock method is used to determine the dilutive impact of stock options and share-settled RSUs. This method assumes any proceeds from the exercise of stock options and vesting of share-settled RSUs would be used to purchase common shares at the average market price during the period.

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


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(number of shares in millions)
Weighted average shares outstanding	2,137	2,024	2,131	2,025
Effect of dilutive options and RSUs	2	3	2	3
Diluted weighted average shares outstanding	2,139	2,027	2,133	2,028

For the three months ended June 30, 2024 and 2023, 18.0 million and 16.3 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $54.55 and $55.46, respectively, were

excluded from the diluted earnings per common share calculation.

For the six months ended June 30, 2024 and 2023, 20.5 million and 16.5 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $53.66 and $55.54, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

On July 29, 2024, our Board of Directors declared the following quarterly dividends. All dividends are payable on September 1, 2024 to shareholders of record on August 15, 2024.


			Dividend per share
Common Shares			$0.91500
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 G1			$0.46817
Preference Shares, Series H			$0.38200
Preference Shares, Series I2			$0.44366
Preference Shares, Series L			US$0.36612
Preference Shares, Series N			$0.41850
Preference Shares, Series P			$0.36988
Preference Shares, Series R3			$0.39463
Preference Shares, Series 1			US$0.41898
Preference Shares, Series 3			$0.23356
Preference Shares, Series 5			US$0.41769
Preference Shares, Series 7			$0.37425
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

1The quarterly dividend per share paid on Preference Shares, Series G was decreased to $0.46817 from $0.47383 on June 1, 2024 due to reset on a quarterly basis.

2The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.44366 from $0.44932 on June 1, 2024 due to reset on a quarterly basis.

3The quarterly dividend per share paid on Preference Shares, Series R was increased to $0.39463 from $0.25456 on June 3, 2024 due to reset of the annual dividend on June 3, 2024.

6. ACQUISITIONS AND DISPOSITIONS

BUSINESS COMBINATIONS

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

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

Questar Gas Company

On May 31, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall West Holdco LLC which owns 100% of Questar Gas Company (Questar) and its related Wexpro companies (Wexpro) for cash consideration of $4.1 billion (US$3.0 billion) (the Questar Acquisition). Questar is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Utah, southwestern Wyoming and southeastern Idaho. The Public Utilities Commissions of Utah, Wyoming and Idaho have granted Questar the necessary regulatory approvals to serve these areas. Wexpro develops and produces cost-of-service gas reserves for Questar and operates under agreements with the states of Utah and Wyoming. The Questar Acquisition further diversifies, and is complementary to, our existing gas distribution operations in the US.

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


			May 31, 2024
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)			464
Property, plant and equipment (b)			5,921
Long-term assets (c)			191
Current liabilities			407
Long-term debt (d)			1,343
Other long-term liabilities (e)			948
Deferred income tax liabilities			522
Goodwill (f)			751
Purchase price:
Cash			4,107

a) Current assets consist primarily of cash, trade and other accounts receivable and inventory. The fair value of trade receivables from customers approximates their carrying value of $201 million due to the short period to maturity. A provision for credit and recovery risk associated with accounts receivable has been made through the expected credit loss, which totaled $9 million.

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

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

d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar yield, credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $301 million with no corresponding regulatory offset.

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

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

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

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


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(unaudited; millions of Canadian dollars)
Operating revenues	11,619	10,788	23,589	23,845
Earnings attributable to common shareholders1	1,871	1,828	3,402	3,652

1 Includes adjustment for pro forma interest expense on debt financing for the Questar Acquisition of $26 million and $52 million (after-tax of $19 million and $38 million) for the three and six months ended June 30, 2023, respectively.

The East Ohio Gas Company

On March 6, 2024, through a wholly-owned US subsidiary, we acquired all of the outstanding shares of capital stock of The East Ohio Gas Company (EOG) for cash consideration of $5.8 billion (US$4.3 billion) (the EOG Acquisition). EOG is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Ohio and is regulated by the Public Utilities Commission of Ohio. The EOG Acquisition is complementary to our other operations in Ohio.

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


			March 6, 2024
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)			641
Property, plant and equipment (b)			7,253
Long-term assets (c)			1,647
Current liabilities			670
Long-term debt (d)			2,612
Other long-term liabilities (e)			993
Deferred income tax liabilities			1,036
Goodwill (f)			1,608
Purchase price:
Cash			5,838

a) Current assets consist primarily of cash, trade and other accounts receivable, prepaid expenses, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $376 million due to the short period to maturity. A provision for credit and recovery risk associated with accounts receivable has been made through the expected credit loss, which totaled $3 million.

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

c) Long-term assets consist primarily of overfunded pension plan assets of $395 million and $1.2 billion of regulatory assets expected to be recovered from customers in future periods through rates.

Pension plan assets attributable to the workforce acquired from EOG were transferred in cash to an Enbridge-sponsored pension plan based on their fair value as at December 31, 2023, subject to closing adjustments. The fair value of plan assets was determined using unadjusted quoted market prices for identical investments.

d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar yield, credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $478 million with no corresponding regulatory offset.

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

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

Upon completion of the EOG Acquisition, we began consolidating EOG. For the period beginning March 6, 2024 through to June 30, 2024, EOG generated $439 million of operating revenues and $83 million of earnings attributable to common shareholders.

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


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(unaudited; millions of Canadian dollars)
Operating revenues	11,340	10,748	22,686	23,244
Earnings attributable to common shareholders1	1,842	1,871	3,318	3,641

1 Includes adjustment for pro forma interest expense on debt financing for the EOG Acquisition of $33 million and $74 million (after-tax of $24 million and $57 million) for the three and six months ended June 30, 2023, respectively.

The purchase price allocations for the Questar Acquisition and EOG Acquisition were prepared on a preliminary basis and are subject to change as additional information becomes available concerning the fair values of the pension, ARO and regulatory balances and their tax bases. Any adjustments to the purchase price allocations will be made as soon as practicable, but no later than one year from the dates of acquisitions.

Acquisition of RNG Facilities

On January 2, 2024, through a wholly-owned US subsidiary, we acquired six Morrow Renewables operating landfill gas-to-renewable natural gas (RNG) production facilities (Tomorrow RNG) located in Texas and Arkansas for total consideration of $1.3 billion (US$1.0 billion), of which $584 million (US$439 million) was paid at close and an additional deferred consideration is payable within two years with a fair value of $757 million (US$568 million) (the RNG Facilities Acquisition). The acquired assets align with and advance our low-carbon strategy.

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


			January 2, 2024
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets			31
Intangible assets (a)			925
Property, plant and equipment (b)			174
Current liabilities			5
Goodwill (c)			223
Purchase price:
Cash			584
Deferred consideration (d):
Current portion of long-term debt			550
Long-term debt			207
Other adjustments			7
			1,348

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

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

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

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

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

ASSET ACQUISITION

Tres Palacios Holdings LLC

On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for $451 million (US$335 million) of cash. Tres Palacios is a natural gas storage facility located in the US Gulf Coast and its infrastructure serves Texas gas-fired power generation and liquefied natural gas (LNG) exports, as well as Mexico pipeline exports.

We allocated assets with a fair value of $790 million (US$588 million) to Property, plant and equipment, net, of which $254 million (US$189 million) relates to storage cavern right-of-use assets, and recorded the related lease liabilities of $7 million (US$5 million) and $248 million (US$184 million) to Current portion of long-term debt and Long-term debt, respectively, in the Consolidated Statements of Financial Position. The acquired assets are included in our Gas Transmission segment.

DISPOSITION

Disposition of Alliance Pipeline and Aux Sable Interests

On April 1, 2024, we closed the sale of our 50.0% interest in the Alliance Pipeline, our interest in Aux Sable (includes a 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a 50.0% interest in Aux Sable Canada LP) and our interest in NRGreen Power Limited Partnership (NRGreen) to Pembina Pipeline Corporation for $3.1 billion, including $327 million of non-recourse debt, subject to customary closing adjustments. A gain on disposal of $1.1 billion before tax, which is net of $1.0 billion of the goodwill from our Gas Transmission segment allocated to the disposal group, is included in Gain on disposition of equity investments in the Consolidated Statements of Earnings for the three and six months ended June 30, 2024. Our equity investments in the Alliance Pipeline and Aux Sable were previously included in our Gas Transmission segment. Our equity investment in NRGreen was previously included in our Renewable Power Generation segment.

EQUITY INVESTMENT TRANSACTION

Joint Venture with WhiteWater/I Squared and MPLX

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

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

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

7. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at June 30, 2024:


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2025-2049	8,671	4,263	4,408
Enbridge (U.S.) Inc.	2025-2028	8,689	2,221	6,468
Enbridge Pipelines Inc.	2025	2,000	754	1,246
Enbridge Gas Inc.	2025	2,500	200	2,300
Total committed credit facilities		21,860	7,438	14,422

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

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

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

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

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

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

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

In addition to the committed credit facilities noted above, we maintain $1.2 billion of uncommitted demand letter of credit facilities, of which $820 million was unutilized as at June 30, 2024. As at December 31, 2023, we had $1.1 billion of uncommitted demand letter of credit facilities, of which $572 million was unutilized.

Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2025 to 2049.

As at June 30, 2024 and December 31, 2023, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $6.5 billion and $3.8 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.

ACQUISITIONS

As a result of the EOG Acquisition, RNG Facilities Acquisition and Questar Acquisition our debt increased by US$1.9 billion, US$568 million and US$1.0 billion, respectively, on each acquisition date. Refer to Note 6 - Acquisitions and Dispositions for further details.

LONG-TERM DEBT ISSUANCES

During the six months ended June 30, 2024, we completed the following long-term debt issuances totaling US$4.7 billion:

Company

Issue Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

April 2024

5.25%

senior notes due April 2027

US$750

April 2024

5.30%

senior notes due April 2029

US$750

April 2024

5.63%

senior notes due April 2034

US$1,200

April 2024

5.95%

senior notes due April 2054

US$800

June 2024

7.38%

fixed-to-fixed subordinated notes due March 20551

US$500

June 2024

7.20%

fixed-to-fixed subordinated notes due June 20542

US$700

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

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

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

LONG-TERM DEBT REPAYMENTS

During the six months ended June 30, 2024, we completed the following long-term debt repayments totaling US$3.2 billion, $0.2 billion and €23 million:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

February 2024

Floating rate notes1

US$600

February 2024

2.15%

senior notes

US$400

March 2024

5.97%

senior notes2

US$700

June 2024

3.50%

senior notes

US$500

Enbridge Pipelines (Southern Lights) L.L.C.

June 2024

3.98%

senior notes

US$42

Enbridge Pipelines Inc.

February 2024

8.20%

debentures

$200

Enbridge Southern Lights LP

January 2024

4.01%

senior notes

$10

Spectra Energy Partners, LP

March 2024

4.75%

senior notes

US$1,000

Blauracke GmbH

April 2024

2.10%

senior notes

€23

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

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

SUBORDINATED TERM NOTES

As at June 30, 2024 and December 31, 2023, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $15.0 billion and $13.0 billion, respectively.

FAIR VALUE ADJUSTMENT

As at June 30, 2024 and December 31, 2023, the fair value adjustments to increase total debt assumed in a historical acquisition were $491 million and $514 million, respectively. As a result of the EOG and Questar Acquisitions, there were additional fair value adjustments of $469 million and $302 million, respectively, to decrease total debt as at June 30, 2024.

Amortization of the fair value adjustment is recorded to Interest expense in the Consolidated Statements of Earnings:


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)



(Increase)/decrease to Interest expense	(10)	11	2	22

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at June 30, 2024, we were in compliance with all such debt covenant provisions.

8. SHARE CAPITAL

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

During the period from May 15, 2024 to June 30, 2024, 51,298,629 common shares were issued and sold under the ATM Program at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.50 billion ($2.48 billion, net of aggregate commissions paid of $16.3 million and other issuance costs). On August 1, 2024, we terminated the ATM Program. Net proceeds from sales of common shares under the ATM Program were used to partially fund the Questar Acquisition and will be used to fund a portion of the purchase price for the acquisition of Public Service Company of North Carolina, Incorporated and any adjustments thereto and to pay related fees and expenses.

9. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

Changes in Accumulated other comprehensive income (AOCI) attributable to our common shareholders for the six months ended June 30, 2024 and 2023 are as follows:


	Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2024	320	(23)	(728)	2,653	11	70	2,303
Other comprehensive income/(loss) retained in AOCI	156	(26)	(538)	2,344	1	—	1,937
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	12	—	—	—	—	—	12
Commodity contracts2	(1)	—	—	—	—	—	(1)
Foreign exchange contracts3	—	31	—	—	—	—	31

Amortization of pension and OPEB actuarial gain4	—	—	—	—	—	(11)	(11)

	167	5	(538)	2,344	1	(11)	1,968
Tax impact
Income tax on amounts retained in AOCI	(36)	6	—	—	—	—	(30)
Income tax on amounts reclassified to earnings	(2)	(7)	—	—	—	2	(7)
	(38)	(1)	—	—	—	2	(37)

Balance as at June 30, 2024	449	(19)	(1,266)	4,997	12	61	4,234


	Cash Flow Hedges	Excluded Components of Fair Value Hedges	Net Investment Hedges	Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2023	121	(35)	(1,137)	4,348	5	218	3,520
Other comprehensive income/(loss) retained in AOCI	126	9	400	(1,482)	—	—	(947)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	23	—	—	—	—	—	23
Commodity contracts2	(1)	—	—	—	—	—	(1)

Other contracts5	1	—	—	—	—	—	1
Amortization of pension and OPEB actuarial gain4	—	—	—	—	—	(10)	(10)

	149	9	400	(1,482)	—	(10)	(934)
Tax impact
Income tax on amounts retained in AOCI	(23)	—	—	—	—	—	(23)
Income tax on amounts reclassified to earnings	(4)	—	—	—	—	2	(2)
	(27)	—	—	—	—	2	(25)

Balance as at June 30, 2023	243	(26)	(737)	2,866	5	210	2,561

1Reported within Interest expense in the Consolidated Statements of Earnings.

2Reported within Transportation and other services revenues in the Consolidated Statements of Earnings.

3Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.

4These components are included in the computation of net periodic benefit credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

5Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

10. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

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

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

Foreign Exchange Risk

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

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

Interest Rate Risk

Our earnings, cash flows and OCI are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We have a policy of limiting the maximum floating rate debt to 30% of total debt outstanding. To ensure compliance with our policy, we monitor and adjust our debt portfolio mix of fixed and variable rate debt instruments in conjunction with the use of hedging instruments. We have implemented a hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps and costless collars. These swaps have an average fixed rate of 4.0%.

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

Commodity Price Risk

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

Equity Price Risk

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

TOTAL DERIVATIVE INSTRUMENTS

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

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


June 30, 2024	Derivative Instruments Used as Cash Flow Hedges	Derivative Instruments Used as Fair Value Hedges	Non- Qualifying Derivative Instruments	Total Gross Derivative Instruments as Presented	Amounts Available for Offset	Total Net Derivative Instruments
(millions of Canadian dollars)
Other current assets
Foreign exchange contracts	—	39	53	92	(22)	70
Interest rate contracts	49	—	58	107	(54)	53
Commodity contracts	—	—	270	270	(163)	107

	49	39	381	469	(239)	230
Deferred amounts and other assets
Foreign exchange contracts	—	—	118	118	(98)	20
Interest rate contracts	23	—	43	66	(10)	56
Commodity contracts	—	—	100	100	(51)	49

	23	—	261	284	(159)	125
Other current liabilities
Foreign exchange contracts	—	(130)	(285)	(415)	22	(393)
Interest rate contracts	(85)	—	(8)	(93)	54	(39)
Commodity contracts	(2)	—	(348)	(350)	163	(187)

	(87)	(130)	(641)	(858)	239	(619)
Other long-term liabilities
Foreign exchange contracts	—	—	(972)	(972)	98	(874)
Interest rate contracts	(4)	—	(25)	(29)	10	(19)
Commodity contracts	(1)	—	(219)	(220)	51	(169)

	(5)	—	(1,216)	(1,221)	159	(1,062)
Total net derivative asset/(liability)
Foreign exchange contracts	—	(91)	(1,086)	(1,177)	—	(1,177)
Interest rate contracts	(17)	—	68	51	—	51
Commodity contracts	(3)	—	(197)	(200)	—	(200)

	(20)	(91)	(1,215)	(1,326)	—	(1,326)


December 31, 2023	Derivative Instruments Used as Cash Flow Hedges	Derivative Instruments Used as Fair Value Hedges	Non- Qualifying Derivative Instruments	Total Gross Derivative Instruments as Presented	Amounts Available for Offset	Total Net Derivative Instruments
(millions of Canadian dollars)
Other current assets
Foreign exchange contracts	—	41	98	139	(32)	107
Interest rate contracts	31	—	34	65	(32)	33
Commodity contracts	—	—	418	418	(270)	148
Other contracts	—	—	1	1	(1)	—
	31	41	551	623	(335)	288
Deferred amounts and other assets
Foreign exchange contracts	—	16	319	335	(122)	213
Interest rate contracts	51	—	2	53	(21)	32
Commodity contracts	—	—	75	75	(41)	34

	51	16	396	463	(184)	279
Other current liabilities
Foreign exchange contracts	—	(44)	(84)	(128)	32	(96)
Interest rate contracts	(183)	—	(3)	(186)	32	(154)
Commodity contracts	(11)	—	(412)	(423)	270	(153)
Other contracts	—	—	(1)	(1)	1	—
	(194)	(44)	(500)	(738)	335	(403)
Other long-term liabilities
Foreign exchange contracts	—	(17)	(481)	(498)	122	(376)
Interest rate contracts	(3)	—	(85)	(88)	21	(67)
Commodity contracts	(7)	—	(159)	(166)	41	(125)

	(10)	(17)	(725)	(752)	184	(568)
Total net derivative liability
Foreign exchange contracts	—	(4)	(148)	(152)	—	(152)
Interest rate contracts	(104)	—	(52)	(156)	—	(156)
Commodity contracts	(18)	—	(78)	(96)	—	(96)
Other contracts	—	—	—	—	—	—
	(122)	(4)	(278)	(404)	—	(404)

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


June 30, 2024	2024	2025	2026	2027	2028	Thereafter	Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)	804	500	—	—	—	—	1,304
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)	3,828	5,327	4,697	4,091	3,162	888	21,993

Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	15	30	28	32	—	—	105

Foreign exchange contracts - Euro forwards - sell (millions of Euro)	69	126	121	81	67	195	659
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	—	84,800	—	—	—	—	84,800
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)	3,473	1,960	1,133	75	25	13	6,679
Interest rate contracts - short-term receive fixed rate (millions of Canadian dollars)	476	958	181	—	—	—	1,615
Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars)1	3,000	1,205	—	—	—	—	4,205
Interest rate contracts - costless collar (millions of Canadian dollars)	—	1,588	62	—	—	—	1,650

Commodity contracts - natural gas (billions of cubic feet)2	26	61	46	24	6	3	166
Commodity contracts - crude oil (millions of barrels)2	(6)	36	20	1	1	2	54

Commodity contracts - power (megawatt per hour (MW/H))	160	1	(5)	(51)	(49)	(30)	(10)	3

1Represents the notional amount of long-term debt issuances hedged.

2Represents the notional amount of net purchase/(sale).

3Total is an average net purchase/(sale) of power.

Derivatives Designated as Fair Value Hedges

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


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)
Unrealized loss on derivative	(29)	(131)	(92)	(142)
Unrealized gain on hedged item	26	130	100	141
Realized gain/(loss) on derivative	(12)	(12)	47	(23)
Realized loss on hedged item	—	—	(79)	—

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

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


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges

Interest rate contracts	10	215	148	110
Commodity contracts	3	2	15	36
Other contracts	—	—	1	(2)
Fair value hedges
Foreign exchange contracts	(11)	2	(26)	9


	2	219	138	153
Amount of (income)/loss reclassified from AOCI to earnings
Foreign exchange contracts1	12	—	31	—
Interest rate contracts2	12	15	12	23
Commodity contracts3	(1)	(1)	(1)	(1)
Other contracts4	—	—	—	1
	23	14	42	23

1Reported within Other income/(expense) in the Consolidated Statements of Earnings.

2Reported within Interest expense in the Consolidated Statements of Earnings.

3Reported within Transportation and other services in the Consolidated Statements of Earnings.

4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

We estimate that a loss of $4 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is two years as at June 30, 2024.

Non-Qualifying Derivatives

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


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)
Foreign exchange contracts1	(209)	509	(939)	1,065
Interest rate contracts2	17	45	122	55
Commodity contracts3	(38)	62	(105)	23
Other contracts4	—	(1)	(1)	(8)
Total unrealized derivative fair value gain/(loss), net	(230)	615	(923)	1,135

1For the respective six months ended periods, reported within Transportation and other services revenues (2024 - nil; 2023 - $645 million gain) and Other income/(expense) (2024 - $939 million loss; 2023 - $420 million gain) in the Consolidated Statements of Earnings.

2Reported within Interest expense in the Consolidated Statements of Earnings.

3For the respective six months ended periods, reported within Transportation and other services revenues (2024 - $60 million loss; 2023 - $8 million gain), Commodity sales (2024 - $2 million loss; 2023 - $96 million gain), Commodity costs (2024 - $20 million loss; 2023 - $51 million loss) and Operating and administrative expense (2024 - $23 million loss; 2023 - $30 million loss) in the Consolidated Statements of Earnings.

4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

LIQUIDITY RISK

Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. Our shelf prospectuses with securities regulators enable ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at June 30, 2024. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities. We also identify a variety of other potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.

CREDIT RISK

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

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


	June 30, 2024	December 31, 2023
(millions of Canadian dollars)
Canadian financial institutions	361	457
US financial institutions	87	252
European financial institutions	78	107
Asian financial institutions	47	121
Other1	147	125
	720	1,062

1Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.

As at June 30, 2024, we did not provide any letters of credit in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on derivative asset exposures as at June 30, 2024 and December 31, 2023.

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

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

FAIR VALUE MEASUREMENTS

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

FAIR VALUE OF FINANCIAL INSTRUMENTS

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

Level 1

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

Level 2

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

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

Level 3

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

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

Fair Value of Derivatives

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


June 30, 2024	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	92	—	92
Interest rate contracts	—	107	—	107
Commodity contracts	23	78	169	270

	23	277	169	469
Long-term derivative assets
Foreign exchange contracts	—	118	—	118
Interest rate contracts	—	66	—	66
Commodity contracts	—	17	83	100

	—	201	83	284
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(415)	—	(415)
Interest rate contracts	—	(93)	—	(93)
Commodity contracts	(49)	(93)	(208)	(350)

	(49)	(601)	(208)	(858)
Long-term derivative liabilities
Foreign exchange contracts	—	(972)	—	(972)
Interest rate contracts	—	(29)	—	(29)
Commodity contracts	—	(27)	(193)	(220)

	—	(1,028)	(193)	(1,221)
Total net financial asset/(liability)
Foreign exchange contracts	—	(1,177)	—	(1,177)
Interest rate contracts	—	51	—	51
Commodity contracts	(26)	(25)	(149)	(200)

	(26)	(1,151)	(149)	(1,326)


December 31, 2023	Level 1	Level 2	Level 3	Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—	139	—	139
Interest rate contracts	—	65	—	65
Commodity contracts	142	103	173	418
Other contracts	—	1	—	1
	142	308	173	623
Long-term derivative assets
Foreign exchange contracts	—	335	—	335
Interest rate contracts	—	53	—	53
Commodity contracts	—	24	51	75

	—	412	51	463
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—	(128)	—	(128)
Interest rate contracts	—	(186)	—	(186)
Commodity contracts	(136)	(76)	(211)	(423)
Other contracts	—	(1)	—	(1)
	(136)	(391)	(211)	(738)
Long-term derivative liabilities
Foreign exchange contracts	—	(498)	—	(498)
Interest rate contracts	—	(88)	—	(88)
Commodity contracts	—	(22)	(144)	(166)

	—	(608)	(144)	(752)
Total net financial asset/(liability)
Foreign exchange contracts	—	(152)	—	(152)
Interest rate contracts	—	(156)	—	(156)
Commodity contracts	6	29	(131)	(96)
Other contracts	—	—	—	—
	6	(279)	(131)	(404)

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


June 30, 2024	Fair Value	Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(5)	Forward gas price	2.51	9.48	3.43	$/mmbtu2
Crude	9	Forward crude price	81.65	111.75	102.76	$/barrel

Power	(73)	Forward power price	26.34	166.75	62.98	$/MW/H
Commodity contracts - physical1
Natural gas	13	Forward gas price	0.28	10.14	3.43	$/mmbtu2
Crude	6	Forward crude price	80.73	114.94	104.81	$/barrel

Power	(99)	Forward power price	18.86	194.97	66.91	$/MW/H
	(149)

1Financial and physical forward commodity contracts are valued using a market approach valuation technique.

2One million British thermal units (mmbtu).

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

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


	Six months ended June 30,
	2024	2023
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(131)	(136)
Total gain/(loss), unrealized
Included in earnings1	(38)	11
Included in OCI	15	35
Settlements	5	3
Level 3 net derivative liability at end of period	(149)	(87)

1Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

There were no transfers into or out of Level 3 as at June 30, 2024 or December 31, 2023.

Net Investment Hedges

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

During the six months ended June 30, 2024 and 2023, we recognized unrealized foreign exchange losses of $425 million and gains of $444 million, respectively, on the translation of US dollar-denominated debt, in OCI. During the six months ended June 30, 2024 and 2023, we recognized realized losses of $113 million and $44 million, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.

Fair Value of Other Financial Instruments

Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $180 million and $173 million as at June 30, 2024 and December 31, 2023, respectively.

As at June 30, 2024, we had investments with a fair value of $756 million included in Restricted long-term investments in the Consolidated Statements of Financial Position (December 31, 2023 - $717 million). These securities are classified as available-for-sale and represent restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements.

We had restricted long-term investments held in trust totaling $302 million as at June 30, 2024 which are classified as Level 1 in the fair value hierarchy (December 31, 2023 - $263 million). We also had restricted long-term investments held in trust totaling $454 million (cost basis - $501 million) and $454 million (cost basis - $486 million) as at June 30, 2024 and December 31, 2023, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding gains and losses of $12 million and $1 million on these investments for the three and six months ended June 30, 2024, respectively (2023 - gains of $3 million and $37 million, respectively).

We have wholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. As at June 30, 2024, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was $321 million and $281 million, respectively (December 31, 2023 - $287 million and $284 million, respectively). Our investments in debt securities had a cost basis of $274 million as at June 30, 2024 (December 31, 2023 - $279 million). These investments in equity funds and debt securities are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, respectively, and are recorded in Other current assets and Long-term investments in the Consolidated Statements of Financial Position. There were unrealized holding gains of $5 million and $21 million for the three and six months ended June 30, 2024, (2023 - gains of $7 million and $22 million, respectively).

As at June 30, 2024 and December 31, 2023, our long-term debt including finance lease liabilities had a carrying value of $92.3 billion and $81.2 billion, respectively, before debt issuance costs and a fair value of $88.7 billion and $78.1 billion, respectively.

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

11. INCOME TAXES

The effective income tax rates for the three months ended June 30, 2024 and 2023 were 27.0% and 20.6%, respectively, and for the six months ended June 30, 2024 and 2023 were 24.0% and 21.0%, respectively.

The period-over-period increases in the effective income tax rates are due to higher US minimum tax, the tax effect of the write-down of non-deductible goodwill in the Gas Transmission segment (Note 6), and the effects of rate-regulated accounting for income taxes, partially offset by a state apportionment income tax rate change due to the Questar Acquisition and EOG Acquisition (Note 6), and the non-taxable portion of the gain on disposition of the interests in Alliance Pipeline, Aux Sable and NRGreen equity investments (Note 6) relative to the change in earnings over the comparative periods.

On June 20, 2024, Bill C-69, Budget Implementation Act, 2024 No.1 received Royal Assent and the Excessive Interest and Financing Expenses Limitation (EIFEL) rules, along with the Global Minimum Tax (GMT) Act, were enacted. While the effects of the EIFEL rules and GMT Act have been factored into tax expense for the three and six months ended June 30, 2024, we do not expect either to have a material impact on our consolidated tax expense.

12. OTHER INCOME/(EXPENSE)


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)

Realized foreign currency gain/(loss)	(8)	1	114	146
Unrealized foreign currency gain/(loss)	(213)	492	(1,071)	304
Net defined pension and OPEB credit	48	34	89	67
Other	142	48	286	160
	(31)	575	(582)	677

13. CONTINGENCIES

LITIGATION

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

TAX MATTERS

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

INSURANCE

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

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

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

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

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

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

RECENT DEVELOPMENTS

AT-THE-MARKET EQUITY ISSUANCE PROGRAM

During the period from May 15, 2024 to June 30, 2024, 51,298,629 common shares were issued and sold under the ATM Program at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.50 billion ($2.48 billion, net of aggregate commissions paid of $16.3 million and other issuance costs). On August 1, 2024, we terminated the ATM Program. Net proceeds from sales of common shares under the ATM Program were used to partially fund the acquisition of Questar Gas Company (Questar) and its related Wexpro companies (Wexpro) and will be used to fund a portion of the purchase price for the acquisition of Public Service Company of North Carolina, Incorporated (PSNC) and any adjustments thereto and to pay related fees and expenses.

ACQUISITIONS

US Gas Utilities

On September 5, 2023, Enbridge entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company (EOG), Questar and Wexpro, and PSNC 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 (the Acquisitions).

On May 31, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall West Holdco LLC which owns 100% of Questar and Wexpro for cash consideration of $4.1 billion (US$3.0 billion) (the Questar Acquisition). Questar is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Utah, southwestern Wyoming and southeastern Idaho. The Public Utilities Commissions of Utah, Wyoming and Idaho have granted Questar the necessary regulatory approvals to serve these areas. Wexpro develops and produces cost-of-service gas reserves for Questar and operates under agreements with the states of Utah and Wyoming. The Questar Acquisition further diversifies, and is complementary to, our existing gas distribution operations in the US. Going forward, Questar will conduct business as Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho in those respective states.

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

We continue to expect that our acquisition of PSNC will close in 2024, subject to the satisfaction of customary closing conditions, including the receipt of required US federal and state regulatory approvals.

Joint Venture with WhiteWater/I Squared and MPLX

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

The Whistler Parent JV is owned by WhiteWater/I Squared (50.6%), MPLX (30.4%), and Enbridge (19.0%) and owns the following assets:

•100% interest in the Whistler pipeline, a 450-mile intrastate pipeline transporting natural gas from the Waha Header in the Permian Basin to Agua Dulce, Texas;

•100% interest in the Rio Bravo Pipeline project, two new parallel 137-mile pipelines transporting natural gas from the Agua Dulce supply area to NextDecade's Rio Grande LNG project in Brownsville, Texas;

•70% interest in the ADCC pipeline, a new 40-mile pipeline which was placed into service in July 2024, and is designed to transport 1.7 billion cubic feet per day (bcf/d) of natural gas from the terminus of the Whistler pipeline in Agua Dulce, Texas to Cheniere's Corpus Christi LNG export facility; and

•50% interest in Waha Gas Storage, a 2.0 bcf gas storage cavern facility connecting to key Permian egress pipelines including the Whistler pipeline.

ASSET MONETIZATION

Disposition of Alliance Pipeline and Aux Sable Interests

On April 1, 2024, we closed the sale of our 50.0% interest in the Alliance Pipeline, our interest in Aux Sable (includes a 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a 50.0% interest in Aux Sable Canada LP) and our interest in NRGreen Power Limited Partnership (NRGreen) to Pembina Pipeline Corporation (Pembina) for $3.1 billion, including $327 million of non-recourse debt, subject to customary closing adjustments. A gain on disposal of $1.1 billion before tax, which is net of $1.0 billion of the goodwill from our Gas Transmission segment allocated to the disposal group, is included in Gain on disposition of equity investments in the Consolidated Statements of Earnings for the three and six months ended June 30, 2024.

GAS TRANSMISSION RATE PROCEEDINGS

Texas Eastern

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

Algonquin

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

Maritimes & Northeast Pipeline

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

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

Incentive Regulation Rate Application

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

On December 21, 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). Enbridge Gas Ontario filed a Notice of Appeal with the Ontario Divisional Court on January 22, 2024 regarding various aspects of the Phase 1 Decision. On January 29, 2024, Enbridge Gas Ontario also filed a Notice of Motion with the OEB requesting the OEB to review and vary various aspects of the Phase 1 Decision which was subsequently amended on May 29, 2024. The Amended Motion focuses on two aspects of the Phase 1 Decision: asset class average useful lives for depreciation purposes and the recoverability of integration capital. The outcome and timing of these proceedings is uncertain.

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

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

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

FINANCING UPDATE

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

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

On May 15, 2024, we established ATM Program which provides us with additional flexibility to partially fund the Acquisitions. From May 15, 2024 to June 30, 2024, 51,298,629 common shares were issued on Canadian and US exchanges at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.50 billion. Refer to At-the-Market Equity Issuance Program for more information.

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

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

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

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

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

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

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

Credit Rating Action

In June 2024, Standard & Poor's Global revised Enbridge's and Enbridge Energy Partners, L.P.'s (EEP) outlooks from negative to stable.

On June 28, 2024, Morningstar DBRS (DBRS) upgraded Enbridge's credit ratings for our senior unsecured debt ratings to A (low) from BBB (high). DBRS also updated the credit rating of EEP to A (low) with a stable trend.

RESULTS OF OPERATIONS


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines	2,450	2,427	4,854	4,780
Gas Transmission	2,095	1,042	3,360	2,247
Gas Distribution and Storage	567	367	1,332	1,083
Renewable Power Generation	138	129	395	265
Eliminations and Other	(155)	575	(797)	592
Earnings before interest, income taxes and depreciation and amortization1	5,095	4,540	9,144	8,967
Depreciation and amortization	(1,273)	(1,137)	(2,466)	(2,283)
Interest expense	(1,082)	(883)	(1,987)	(1,788)
Income tax expense	(739)	(519)	(1,125)	(1,029)
Earnings attributable to noncontrolling interests	(58)	(66)	(111)	(115)
Preference share dividends	(95)	(87)	(188)	(171)
Earnings attributable to common shareholders	1,848	1,848	3,267	3,581
Earnings per common share attributable to common shareholders	0.86	0.91	1.53	1.77
Diluted earnings per common share attributable to common shareholders	0.86	0.91	1.53	1.77

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

Change in Reportable Segments

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

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

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

Earnings attributable to common shareholders were positively impacted by $134 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a gain on sale of $1.1 billion ($765 million after-tax) related to the disposition of interests in the Alliance Pipeline, Aux Sable and NRGreen to Pembina; partially offset by

•a non-cash, net unrealized derivative fair value loss of $208 million ($160 million after-tax) in 2024, compared with a net unrealized gain of $595 million ($456 million after-tax) in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;

•a non-cash revaluation loss of $29 million ($21 million after-tax) to the gas inventory at the Aitken Creek Gas Storage Facility (Aitken Creek);

•a loss of $25 million ($19 million after-tax) as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV; and

•$16 million ($13 million after-tax) of integration and transaction costs incurred related to the Acquisitions.

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 $134 million decrease in earnings attributable to common shareholders is primarily explained by:

•lower contributions from the Mainline System in our Liquids Pipelines segment driven by lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower Line 3 Replacement (L3R) surcharge, net of stronger performance due to higher Mainline System throughput and longer haul volumes;

•higher interest expense primarily due to higher interest rates and higher average principal outstanding;

•higher income tax expense largely driven by higher US minimum tax, changes to the state apportionment and the effects of rate-regulated accounting for income taxes;

•higher depreciation and amortization expense as a result of acquisitions and projects placed into service after June 2023; and

•absence of contributions from our Gas Transmission segment due to the sale of our interests in the Alliance Pipeline and Aux Sable in April 2024.

The factors above were partially offset by:

•contributions from the Acquisitions completed in 2024 and higher distribution charges resulting from increases in rates and customer base in our Gas Distribution and Storage segment;

•higher contributions from our Liquids Pipelines segment due to higher volumes on the Flanagan South Pipeline and certain Feeder pipelines, greater long-haul deliveries from the Express-Platte System, and discontinuation of rate-regulated accounting of Southern Lights Pipeline as at December 31, 2023;

•higher investment income primarily due to pre-funding of the Acquisitions in our Eliminations and Other segment; and

•higher contributions from our Gas Transmission segment primarily due to acquisitions completed after June 2023, and lower operating costs in our US Gas Transmission assets.

Six months ended June 30, 2024, compared with the six months ended June 30, 2023

Earnings attributable to common shareholders were negatively impacted by $409 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized derivative fair value loss of $885 million ($678 million after-tax) in 2024, compared with a net unrealized gain of $1.1 billion ($868 million after-tax) in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;

•severance costs of $105 million ($79 million after-tax) as a result of a workforce reduction in February 2024;

•the absence in 2024 of the receipt of a litigation claim settlement of $68 million ($52 million after-tax);

•$30 million ($23 million after-tax) of integration and transaction costs incurred related to the Acquisitions;

•a non-cash revaluation loss of $29 million ($21 million after-tax) to the gas inventory at Aitken Creek; and

•a loss of $25 million ($19 million after-tax) as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV; partially offset by

•a gain on sale of $1.1 billion ($765 million after-tax) related to the disposition of interests in the Alliance Pipeline, Aux Sable and NRGreen to Pembina; and

•the absence in 2024 of a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, as foreign exchange risks inherent within the Competitive Toll Settlement (CTS) are not present in the Mainline Tolling Settlement (MTS).

After taking into consideration the factors above, the remaining $95 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:

•higher contributions from our Liquids Pipelines segment due to higher volumes on the Flanagan South Pipeline, from the Enbridge Ingleside Energy Center (EIEC), and certain Feeder pipelines, greater long-haul deliveries from the Express-Platte System, and discontinuation of rate-regulated accounting of Southern Lights Pipeline as at December 31, 2023;

•contributions from the Acquisitions completed in 2024 and higher distribution charges resulting from increases in rates and customer base in our Gas Distribution and Storage segment;

•higher investment income primarily due to pre-funding of the Acquisitions in our Eliminations and Other segment; and

•higher contributions from our Gas Transmission segment primarily due to favorable contracting and lower operating costs in our US Gas Transmission assets, and acquisitions completed after June 2023.

The factors above were partially offset by:

•lower contributions from the Mainline System in our Liquids Pipelines segment driven by lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower L3R surcharge, net of stronger performance due to higher Mainline System throughput and longer haul volumes;

•higher interest expense primarily due to higher interest rates and higher average principal outstanding;

•higher income tax expense largely driven by higher US minimum tax, changes to the state apportionment and the effects of rate-regulated accounting for income taxes;

•higher depreciation and amortization expense as a result of acquisitions and projects placed into service after June 2023;

•lower contributions from our Gas Transmission segment due to the sale of our interests in the Alliance Pipeline and Aux Sable and the absence of revenues attributable to the Texas Eastern 2022 rate case settlement in 2024;

•negative impact on earnings due to warmer than normal weather in Enbridge Gas Ontario of our Gas Distribution and Storage segment; and

•realized loss on foreign exchange hedge settlement in 2024 compared to a realized gain in 2023 in our Eliminations and Other segment.

BUSINESS SEGMENTS

LIQUIDS PIPELINES


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	2,450	2,427	4,854	4,780

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

EBITDA was negatively impacted by $4 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized gain of $29 million in 2024, compared with a net unrealized gain of $35 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.

After taking into consideration the factors above, the remaining $27 million increase is primarily explained by the following significant business factors:

•stronger Mainline System performance due to higher Mainline System throughput and longer haul volumes;

•higher contributions from the Gulf Coast and Mid-Continent System due primarily to higher volumes on the Flanagan South Pipeline driven by the open season commitments that commenced in the first quarter of 2024;

•higher contributions from certain Feeder pipelines due to higher volumes including Southern Access Extension (SAX) and Toledo pipelines;

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, as compared to 2023;

•higher contributions from Southern Lights Pipeline due primarily to the discontinuation of rate-regulated accounting as at December 31, 2023; and

•higher contributions from the Express-Platte System due primarily to greater long-haul deliveries; partially offset by

•lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower L3R surcharge.

Six months ended June 30, 2024, compared with the six months ended June 30, 2023

EBITDA was negatively impacted by $71 million due to certain infrequent or other non-operating factors, primarily explained by the following:

•a non-cash, net unrealized loss of $6 million in 2024, compared with a net unrealized gain of $650 million in 2023, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and

•the absence in 2024 of the receipt of a litigation claim settlement of $68 million; partially offset by

•the absence in 2024 of a realized loss of $638 million due to termination of foreign exchange hedges, as foreign exchange risks inherent within the CTS framework are not present in the MTS.

After taking into consideration the factors above, the remaining $145 million increase is primarily explained by the following significant business factors:

•stronger Mainline System performance due to higher Mainline System throughput and longer haul volumes;

•higher contributions from Southern Lights Pipeline due primarily to the discontinuation of rate-regulated accounting as at December 31, 2023;

•higher contributions from the Express-Platte System due primarily to greater long-haul deliveries;

•higher contributions from certain Feeder pipelines due to higher volumes including SAX and Toledo pipelines; and

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, as compared to 2023; partially offset by

•lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower L3R surcharge.

GAS TRANSMISSION


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	2,095	1,042	3,360	2,247

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

EBITDA was positively impacted by $1,004 million due to certain infrequent or other non-operating factors, primarily explained by:

•a gain on sale of $1,063 million on the disposition of interests in the Alliance Pipeline and Aux Sable; partially offset by

•a non-cash revaluation loss of $29 million to the gas inventory at Aitken Creek; and

•a loss of $25 million as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV.

The remaining $49 million increase is primarily explained by the following significant business factors:

•lower operating costs on our US Gas Transmission assets;

•contributions from the acquisitions of Aitken Creek in the fourth quarter of 2023 and Tomorrow RNG in the first quarter of 2024; and

•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, compared to the same period in 2023; partially offset by

•absence of contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments to Pembina in April 2024.

Six months ended June 30, 2024, compared with the six months ended June 30, 2023

EBITDA was positively impacted by $979 million due to certain infrequent or other non-operating factors, primarily explained by:

•a gain on sale of $1,063 million on the disposition of interests in the Alliance Pipeline and Aux Sable; partially offset by

•a non-cash revaluation loss of $29 million to the gas inventory at Aitken Creek;

•a loss of $25 million as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV; and

•a non-cash, net unrealized loss of $17 million in 2024 reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks.

The remaining $134 million increase is primarily explained by the following significant business factors:

•favorable contracting and lower operating costs on our US Gas Transmission assets;

•contributions from the acquisitions of Tres Palacios in the second quarter of 2023, Aitken Creek in the fourth quarter of 2023 and Tomorrow RNG in the first quarter of 2024; and

•higher first quarter earnings at Aux Sable joint venture due to favorable contracting; partially offset by

•lower contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments to Pembina in April 2024; and

•the absence in 2024 of recognition of revenues attributable to the Texas Eastern 2022 rate case settlement.

GAS DISTRIBUTION AND STORAGE


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	567	367	1,332	1,083

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

EBITDA was positively impacted by $200 million primarily due to the following significant business factors:

•contributions from the EOG Acquisition and the Questar Acquisition in 2024; and

•higher distribution charges resulting from increases in rates and customer base; partially offset by

•warmer than normal weather in 2024, when compared with the normal weather forecast embedded in rates, which negatively impacted Enbridge Gas Ontario 2024 EBITDA by approximately $23 million period over period.

Six months ended June 30, 2024, compared with the six months ended June 30, 2023

EBITDA was positively impacted by $249 million primarily due to the following significant business factors:

•contributions from the EOG Acquisition and the Questar Acquisition in 2024; and

•higher distribution charges resulting from increases in rates and customer base; partially offset by

RENEWABLE POWER GENERATION


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	138	129	395	265

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

EBITDA was negatively impacted by $6 million due to certain infrequent or other non-operating factors, primarily explained by:

•a non-cash, net unrealized loss of $25 million in 2024, compared with a net unrealized gain of $2 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; partially offset by

•a gain on sale of $29 million related to disposition of our interest in NRGreen to Pembina.

The remaining $15 million increase is primarily due to higher contributions from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities.

Six months ended June 30, 2024, compared with the six months ended June 30, 2023

EBITDA was negatively impacted by $25 million due to certain infrequent or other non-operating factors, primarily explained by:

•a non-cash, net unrealized loss of $36 million in 2024, compared with a net unrealized gain of $4 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; partially offset by

•a gain on sale of $29 million related to disposition of our interest in NRGreen to Pembina.

The remaining $155 million increase is primarily explained by the following significant business factors:

•contributions from our investment in Fox Squirrel as a result of the generation of investment tax credits;

•higher contributions from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities; and

•stronger wind resources at European wind facilities.

ELIMINATIONS AND OTHER


	Three months ended June 30,		Six months ended June 30,
	2024	2023	2024	2023
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	(155)	575	(797)	592

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

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

EBITDA was negatively impacted by $766 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, net unrealized loss of $229 million in 2024, compared with a net gain of $512 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk; and

•$16 million of integration and transaction costs incurred as a result of the Acquisitions.

After taking into consideration the non-operating factors above, the remaining $36 million increase is primarily explained by higher investment income primarily from the pre-funding of the Acquisitions.

Six months ended June 30, 2024, compared with the six months ended June 30, 2023

EBITDA was negatively impacted by $1,519 million due to certain infrequent or non-operating factors, primarily explained by:

•a non-cash, net unrealized loss of $951 million in 2024, compared with an unrealized gain of $435 million in 2023, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;

•severance costs of $105 million as a result of a workforce reduction in February 2024; and

•$30 million of integration and transaction costs incurred as a result of the Acquisitions.

After taking into consideration the non-operating factors above, the remaining $130 million increase is primarily explained by:

•higher investment income primarily from the pre-funding of the Acquisitions; and

•timing of certain operating and administrative cost recoveries from the business units; partially offset by

•realized foreign exchange loss on hedge settlements in 2024, compared to a gain in 2023.

GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS

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


		Enbridge's Ownership Interest		Estimated Capital Cost1	Expenditures to Date2	Status2	Expected In-Service Date
(Canadian dollars, unless stated otherwise)


GAS TRANSMISSION
1.	Texas Eastern Venice Extension3	100	%	US$477 million	US$317 million	Under construction	2024
2.	Texas Eastern Modernization	100	%	US$394 million	US$75 million	Pre-construction	2025 - 2026
3.	T-North Expansion (Aspen Point)	100	%	$1.2 billion	$139 million	Pre-construction	2026

4.	Tennessee Ridgeline Expansion	100	%	US$1.1 billion	US$117 million	Pre-construction	2026

5.	Woodfibre LNG4	30	%	US$1.5 billion	US$412 million	Under construction	2027
6.	T-South Expansion (Sunrise)	100	%	$4.0 billion	$122 million	Pre-construction	2028



RENEWABLE POWER GENERATION
7.	Fécamp Offshore Wind5	17.9	%	$692 million	$631 million	In service	May 2024
				(€471 million)	(€432 million)
8.	Calvados Offshore Wind6	21.7	%	$954 million	$375 million	Under construction	2025
				(€645 million)	(€261 million)
9.	Fox Squirrel Solar7	50	%	US$406 million	US$237 million	Under construction	2024

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 June 30, 2024.

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

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

5Our equity contribution is reduced to nil after project refinancing was approved in the first quarter of 2024. The project is fully financed through non-recourse project level debt.

6Our equity contribution is $181 million, with the remainder financed through non-recourse project level debt.

7Includes the first phase of the project which commenced operations in December 2023, and the second phase which is expected to be complete in the third quarter of 2024.

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

GAS TRANSMISSION

Tennessee Ridgeline Expansion

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

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

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

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

The following project has been announced during the quarter, but is not yet met our criteria to be classified as commercially secured:

RENEWABLE POWER GENERATION

Seven Stars Energy Project

On June 24, 2024, Enbridge and Six Nations Energy Development LP, a newly-created consortium of Cowessess, George Gordon, Kahkewistahaw, Pasqua and White Bear First Nations, as well as Métis Nation-Saskatchewan, announced plans to advance development of a new wind energy project southeast of Weyburn, Saskatchewan. The Seven Stars Energy Project (the Project) is expected to produce 200 megawatts of wind power, enough to support the annual energy needs of more than 100,000 Saskatchewan homes. It will be developed, constructed and operated by a wholly-owned indirect subsidiary of Enbridge.

Financial participation of the partners will be supported, in part, by loan guarantees of up to $100 million from the Saskatchewan Indigenous Investment Finance Corporation. Our Indigenous partners have an opportunity to acquire equity ownership of at least 30% in the Project.

The Project is targeted to be operational in 2027, subject to finalizing commercial agreements, securing the necessary environmental and regulatory approvals, and meeting investment criteria. Enbridge is working toward securing a long-term power purchase agreement with SaskPower to support a final investment decision, anticipated in 2025.

LIQUIDITY AND CAPITAL RESOURCES

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

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

We have signed capital obligation contracts for the purchase of services, pipe and other materials totaling approximately $2.7 billion, which are expected to be paid over the next five years.

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

CAPITAL MARKET ACCESS

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

Credit Facilities and Liquidity

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


	Maturity1	Total Facilities	Draws2	Available
(millions of Canadian dollars)
Enbridge Inc.	2025-2049	8,671	4,263	4,408
Enbridge (U.S.) Inc.	2025-2028	8,689	2,221	6,468
Enbridge Pipelines Inc.	2025	2,000	754	1,246
Enbridge Gas Inc.	2025	2,500	200	2,300
Total committed credit facilities		21,860	7,438	14,422

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

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

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

As at June 30, 2024, our net available liquidity totaled $18.0 billion (December 31, 2023 - $23.0 billion), consisting of available credit facilities of $14.4 billion (December 31, 2023 - $17.1 billion) and unrestricted cash and cash equivalents of $3.6 billion (December 31, 2023 - $5.9 billion) as reported in the Consolidated Statements of Financial Position.

LONG-TERM DEBT ISSUANCES

During the six months ended June 30, 2024, we completed the following long-term debt issuances totaling US$4.7 billion:

Company

Issue Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

April 2024

5.25%

senior notes due April 2027

US$750

April 2024

5.30%

senior notes due April 2029

US$750

April 2024

5.63%

senior notes due April 2034

US$1,200

April 2024

5.95%

senior notes due April 2054

US$800

June 2024

7.38%

fixed-to-fixed subordinated notes due March 20551

US$500

June 2024

7.20%

fixed-to-fixed subordinated notes due June 20542

US$700

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

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

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

LONG-TERM DEBT REPAYMENTS

During the six months ended June 30, 2024, we completed the following long-term debt repayments totaling US$3.2 billion, $0.2 billion and €23 million:

Company

Repayment Date

Principal Amount

(millions of Canadian dollars, unless otherwise stated)

Enbridge Inc.

February 2024

Floating rate notes1

US$600

February 2024

2.15%

senior notes

US$400

March 2024

5.97%

senior notes2

US$700

June 2024

3.50%

senior notes

US$500

Enbridge Pipelines (Southern Lights) L.L.C.

June 2024

3.98%

senior notes

US$42

Enbridge Pipelines Inc.

February 2024

8.20%

debentures

$200

Enbridge Southern Lights LP

January 2024

4.01%

senior notes

$10

Spectra Energy Partners, LP

March 2024

4.75%

senior notes

US$1,000

Blauracke GmbH

April 2024

2.10%

senior notes

€23

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

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

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

There are no material restrictions on our cash. Total restricted cash of $113 million, as reported in the Consolidated Statements of Financial Position, primarily includes reinsurance security, cash collateral, future pipeline abandonment costs collected and held in trust, amounts received in respect of specific shipper commitments and capital projects. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us.

Excluding current maturities of long-term debt, as at June 30, 2024 and December 31, 2023, we had positive working capital positions of $2.9 billion and $3.0 billion, respectively. During both the six months ended June 30, 2024 and the year ended December 31, 2023, the major contributing factor to the positive working capital position was due to the increase in cash associated with pre-funding of the Acquisitions. We maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due.

SOURCES AND USES OF CASH


	Six months ended June 30,
		2024	2023
(millions of Canadian dollars)
Operating activities		5,965	7,305
Investing activities		(11,230)	(2,333)
Financing activities		2,787	(4,770)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		192	(19)
Net change in cash and cash equivalents and restricted cash		(2,286)	183

Significant sources and uses of cash for the six months ended June 30, 2024 and 2023 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.

Investing Activities

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

Financing Activities

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

•net commercial paper and credit facility draws in 2024 when compared to net repayments during the same period in 2023;

•the ATM Program, resulting in the issuance of 51,298,629 common shares for aggregate net proceeds of $2.5 billion in 2024; and

•lower net repayments of short-term borrowings and larger principal amount of long-term debt issued in 2024 when compared to the same period in 2023.

The factors above were partially offset by:

•higher long-term debt repayments in 2024 when compared to the same period in 2023; and

•increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding.

SUMMARIZED FINANCIAL INFORMATION

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

Consenting SEP notes and EEP notes under Guarantees


SEP Notes1			EEP Notes2
3.50% Senior Notes due 2025			5.88% Notes due 2025
3.38% Senior Notes due 2026			5.95% Notes due 2033
5.95% Senior Notes due 2043			6.30% Notes due 2034
4.50% Senior Notes due 2045			7.50% Notes due 2038
			5.50% Notes due 2040

			7.38% Notes due 2045

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

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

Enbridge Notes under Guarantees


USD Denominated1			CAD Denominated2
2.50% Senior Notes due 2025			3.95% Senior Notes due 2024
2.50% Senior Notes due 2025			2.44% Senior Notes due 2025
4.25% Senior Notes due 2026			3.20% Senior Notes due 2027
1.60% Senior Notes due 2026			5.70% Senior Notes due 2027
5.90% Senior Notes due 2026			6.10% Senior Notes due 2028
3.70% Senior Notes due 2027			4.90% Senior Notes due 2028
5.25% Senior Notes due 2027			2.99% Senior Notes due 2029
6.00% Senior Notes due 2028			7.22% Senior Notes due 2030
3.13% Senior Notes due 2029			7.20% Senior Notes due 2032
5.30% Senior Notes due 2029			6.10% Sustainability-Linked Senior Notes due 2032
6.20% Senior Notes due 2030			3.10% Sustainability-Linked Senior Notes due 2033
2.50% Sustainability-Linked Senior Notes due 2033			5.36% Sustainability-Linked Senior Notes due 2033
5.70% Sustainability-Linked Senior Notes due 2033			5.57% Senior Notes due 2035
5.63% Senior Notes due 2034			5.75% Senior Notes due 2039
4.50% Senior Notes due 2044			5.12% Senior Notes due 2040
5.50% Senior Notes due 2046			4.24% Senior Notes due 2042
4.00% Senior Notes due 2049			4.57% Senior Notes due 2044
3.40% Senior Notes due 2051			4.87% Senior Notes due 2044
6.70% Senior Notes due 2053			4.10% Senior Notes due 2051
5.95% Senior Notes due 2054			6.51% Senior Notes due 2052
			5.76% Senior Notes due 2053
			4.56% Senior Notes due 2064

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

2As at June 30, 2024, 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 SEP, EEP and Enbridge.

Summarized Combined Statement of Earnings


Six months ended June 30,			2024
(millions of Canadian dollars)

Operating loss			(49)
Earnings			94
Loss attributable to common shareholders			(94)

Summarized Combined Statements of Financial Position


	June 30, 2024	December 31, 2023
(millions of Canadian dollars)
Cash and cash equivalents	3,772	6,525
Accounts receivable from affiliates	4,027	3,440
Short-term loans receivable from affiliates	3,103	3,291
Trade accounts receivable and unbilled revenue	35	—
Other current assets	510	491
Long-term loans receivable from affiliates	42,160	45,702
Other long-term assets	1,782	3,303
Accounts payable to affiliates	2,525	2,264
Short-term loans payable to affiliates	1,275	807
Trade payables and accrued liabilities	369	743
Other current liabilities	5,125	7,256
Long-term loans payable to affiliates	26,537	35,556
Other long-term liabilities	57,310	52,096

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

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

•received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;

•was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

•intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

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

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

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

•any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;

•the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;

•the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement;

•with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;

•with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or

•with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.

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

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

LEGAL AND OTHER UPDATES

MICHIGAN LINE 5 DUAL PIPELINES - STRAITS OF MACKINAC EASEMENT

Michigan Attorney General Lawsuit

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

On June 17, 2024, the 6th Circuit Court of Appeals (6th Circuit), overturned the US District Court’s decision and remanded the AG's lawsuit against Enbridge back to the Circuit Court. The remand decision was made on the issue of the timeliness of Enbridge's removal of the AG lawsuit to federal court, which was outside of the 30-day window. The 6th Circuit panel did not express an opinion on the merits of Enbridge's arguments on jurisdiction.

On July 15, 2024, Enbridge filed a petition for rehearing of the June 17 6th Circuit decision.

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

Enbridge Lawsuit

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

In January 2022, the State of Michigan filed a motion to dismiss Enbridge's Complaint and Enbridge filed a motion for Summary Judgment. Briefing on these motions was completed in April 2022. On July 5, 2024, the US District Court issued an Order denying the Michigan officials' motion to dismiss Enbridge's Complaint. The State of Michigan filed for an immediate appeal to the 6th Circuit on July 8, 2024. On July 23, 2024, the Judge issued an order cancelling oral argument that was set for July 31, 2024, and requested the parties file a joint status report by August 23, 2024.

OTHER LITIGATION

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

TAX MATTERS

CHANGES IN ACCOUNTING POLICIES

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

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 June 30, 2024, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

Changes in Internal Control over Financial Reporting

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

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in various legal and regulatory actions and proceedings which arise in the ordinary course of business. 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. Refer to Part I. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of certain legal proceedings with recent developments.

SEC regulations require the disclosure of any proceeding under environmental laws to which a governmental authority is a party unless the registrant reasonably believes it will not result in monetary sanctions over a certain threshold. Given the size of our operations, we have elected to use a threshold of US$1 million for the purposes of determining proceedings requiring disclosure. We have no such proceedings to disclose in this quarterly report.

ITEM 1A. RISK FACTORS

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

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Certain of our officers and directors have made elections to participate in, and are participating in, our compensation and benefit plans involving Enbridge stock, such as our 401(k) plan and directors' compensation plan, and may from time to time make elections which may be designed to satisfy the affirmative defense conditions of Rule 10b5-1 under the Exchange Act or may constitute non-Rule 10b5-1 trading arrangements (as defined in Item 408(c) of Regulation S-K).

ITEM 6. EXHIBITS

Each exhibit identified below is included as a part of this quarterly report. Exhibits included in this filing are designated by an asterisk ("*"); all exhibits not so designated are incorporated by reference to a prior filing as indicated. Exhibits designated with a "^" are furnished herewith.


Exhibit No.						Description
4.1						Thirteenth Supplemental Indenture to the Indenture, dated as of June 27, 2024, between the Corporation and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 to Enbridge’s Current Report on Form 8-K filed June 27, 2024).
4.2						Fourteenth Supplemental Indenture to the Indenture, dated as of June 27, 2024, between the Corporation and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.2 to Enbridge’s Current Report on Form 8-K filed June 27, 2024).
22.1*						Subsidiary Guarantors
31.1*						Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*						Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*^						Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*^						Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.SCH*						Inline XBRL Taxonomy Extension Schema Document.
101.CAL*						Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*						Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*						Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104						Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


			ENBRIDGE INC.
			(Registrant)

Date:	August 2, 2024	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel
			President and Chief Executive Officer
			(Principal Executive Officer)

Date:	August 2, 2024	By:	/s/ Patrick R. Murray
			Patrick R. Murray
			Executive Vice President and Chief Financial Officer
			(Principal Financial Officer)

Document

Exhibit 22.1

Subsidiary Guarantors

As of June 30, 2024, each of the following subsidiaries of Enbridge Inc. (“Enbridge”), both of which are indirect, wholly-owned subsidiaries of Enbridge, has fully and unconditionally guaranteed on an unsecured, joint and several basis, each of the registered debt securities of Enbridge listed below:

Subsidiary Guarantors

1.Spectra Energy Partners, LP, a Delaware limited partnership

2.Enbridge Energy Partners, L.P., a Delaware limited partnership

Registered Debt Securities of Enbridge Guaranteed by each of the Subsidiary Guarantors

1.2.500% Senior Notes due 2025

2.2.500% Senior Notes due 2025

3.4.250% Senior Notes due 2026

4.1.600% Senior Notes due 2026

5.5.900% Senior Notes due 2026

6.3.700% Senior Notes due 2027

7.5.250% Senior Notes due 2027

8.6.000% Senior Notes due 2028

9.3.125% Senior Notes due 2029

10.5.300% Senior Notes due 2029

11.6.200% Senior Notes due 2030

12.2.500% Sustainability-Linked Senior Notes due 2033

13.5.700% Sustainability-Linked Senior Notes due 2033

14.5.625% Senior Notes due 2034

15.4.500% Senior Notes due 2044

16.5.500% Senior Notes due 2046

17.4.000% Senior Notes due 2049

18.3.400% Senior Notes due 2051

19.6.700% Senior Notes due 2053

20.5.950% Senior Notes due 2054

Document

EXHIBIT 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Gregory L. Ebel, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Enbridge Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


Date:	August 2, 2024	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel
			President and Chief Executive Officer (Principal Executive Officer) Enbridge Inc.

Document

EXHIBIT 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Patrick R. Murray, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Enbridge Inc.;

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


Date:	August 2, 2024	By:	/s/ Patrick R. Murray
			Patrick R. Murray
			Executive Vice President and Chief Financial Officer (Principal Financial Officer) Enbridge Inc.

Document

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Enbridge Inc. on Form 10-Q for the period ending June 30, 2024 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gregory L. Ebel, President and Chief Executive Officer of Enbridge Inc., certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1.The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Enbridge Inc.


Date:	August 2, 2024	By:	/s/ Gregory L. Ebel
			Gregory L. Ebel
			President and Chief Executive Officer (Principal Executive Officer) Enbridge Inc.

Document

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Enbridge Inc. on Form 10-Q for the period ending June 30, 2024 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Patrick R. Murray, Executive Vice President and Chief Financial Officer of Enbridge Inc., certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1.The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Enbridge Inc.


Date:	August 2, 2024	By:	/s/ Patrick R. Murray
			Patrick R. Murray
			Executive Vice President and Chief Financial Officer (Principal Financial Officer) Enbridge Inc.