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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended
June 30,
2025
OR
☐
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 perio
d that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes
☒ No ☐
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 fil
es).
Yes
☒ No ☐
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. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Excha
nge Act). Yes ☐ No
☒
The registrant had
2,180,514,839
common shares outstanding as at July 25, 2025.
Earnings before interest, income taxes and depreciation and amortization
EEP
Enbridge Energy Partners, L.P.
EIS
Environmental Impact Statement
Enbridge Gas Ontario
Enbridge Gas Inc.
EOG
The East Ohio Gas Company
Exchange Act
United States Securities Exchange Act of 1934, as amended
FERC
Federal Energy Regulatory Commission
NRGreen
NRGreen Power Limited Partnership
OCI
Other comprehensive income/(loss)
OEB
Ontario Energy Board
OPEB
Other postretirement benefit obligations
Questar
Questar Gas Company
ROE
Return on Equity
SEP
Spectra Energy Partners, LP
the District Court
the US Court for the District of Columbia
the Guaranteed Enbridge Notes
Enbridge's outstanding guaranteed notes
the Ohio Commission
the Public Utilities Commission of Ohio
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
US District Court
the US District Court in the Western District of Michigan
US Gas Utilities / the Acquisitions
Enbridge Inc.'s acquisitions of three US gas utilities from Dominion Energy, Inc.
Vector
Vector Pipeline L.P.
Wexpro
Wexpro Company and its consolidated subsidiaries
3
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, governance and sustainability 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, dispositions and other transactions, including the anticipated benefits of the acquisitions of three US gas utilities (US Gas Utilities) from Dominion Energy, Inc. (the Acquisitions); expected future actions of regulators and courts, government trade policies, as well as possible impacts of potential and announced tariffs, duties, fees, economic sanctions, or other trade measures and the timing thereof; 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 successfully integrate the US Gas Utilities; expected closing of acquisitions, dispositions and other transactions and the timing thereof; toll and rate cases discussions and proceedings and anticipated outcomes, timelines and impacts 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; tariffs and trade policies; 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, dispositions and other transactions; 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, interest rates and tariffs 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
4
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; 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, dispositions and other transactions and the realization of anticipated benefits therefrom (including the anticipated benefits from the Acquisitions); evolving government trade policies, including potential and announced tariffs, duties, fees, economic sanctions or other trade measures; 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; our ability to maintain adequate insurance in the future at commercially reasonable rates and terms; 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
.
5
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENBRIDGE INC.
CONSOLIDATED S
TATEMENTS OF EARNINGS
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales
8,124
5,291
17,673
9,436
Gas distribution sales
1,763
1,208
5,462
3,169
Transportation and other services
4,989
4,837
10,243
9,769
Total operating revenues
(Note 3)
14,876
11,336
33,378
22,374
Operating expenses
Commodity costs
8,008
5,173
17,343
9,179
Gas distribution costs
548
309
2,164
1,303
Operating and administrative
2,310
2,308
4,781
4,442
Depreciation and amortization
1,391
1,273
2,799
2,466
Impairment of long-lived assets
(Note 4)
330
—
330
—
Total operating expenses
12,587
9,063
27,417
17,390
Operating income
2,289
2,273
5,961
4,984
Income from equity investments
510
489
1,239
1,185
Gain on disposition of equity investments
(Note 6)
—
1,091
—
1,091
Other income/(expense)
(Note 12)
1,369
(
31
)
1,489
(
582
)
Interest expense
(
1,181
)
(
1,082
)
(
2,515
)
(
1,987
)
Earnings before income taxes
2,987
2,740
6,174
4,691
Income tax expense
(
666
)
(
739
)
(
1,363
)
(
1,125
)
Earnings
2,321
2,001
4,811
3,566
Earnings attributable to noncontrolling interests
(
42
)
(
58
)
(
168
)
(
111
)
Earnings attributable to controlling interests
2,279
1,943
4,643
3,455
Preference share dividends
(
102
)
(
95
)
(
205
)
(
188
)
Earnings attributable to common shareholders
2,177
1,848
4,438
3,267
Earnings per common share attributable to common shareholders
(Note 5)
1.00
0.86
2.04
1.53
Diluted earnings per common share attributable to common shareholders
(Note 5)
1.00
0.86
2.03
1.53
The accompanying notes are an integral part of these interim consolidated financial statements.
6
ENBRIDGE INC.
CONSOLIDATED STATEMENT
S OF COMPREHENSIVE INCOME
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(unaudited; millions of Canadian dollars)
Earnings
2,321
2,001
4,811
3,566
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges
11
12
(
14
)
128
Gain/(loss) on net investment hedges
(Note 10)
447
(
161
)
413
(
538
)
Other comprehensive income from equity investees and other investments
9
2
21
1
Excluded components of fair value hedges
10
—
14
4
Reclassification to earnings of loss on cash flow hedges
8
9
14
9
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts
(
6
)
(
5
)
(
13
)
(
9
)
Reclassification of actuarial gain on pension and OPEB from regulatory assets
49
—
49
—
Foreign currency translation adjustments
(
3,534
)
727
(
3,415
)
2,385
Other comprehensive income/(loss), net of tax
(
3,006
)
584
(
2,931
)
1,980
Comprehensive income/(loss)
(
685
)
2,585
1,880
5,546
Comprehensive (income)/loss attributable to noncontrolling interests
20
(
72
)
(
108
)
(
160
)
Comprehensive income/(loss) attributable to controlling interests
(
665
)
2,513
1,772
5,386
Preference share dividends
(
102
)
(
95
)
(
205
)
(
188
)
Comprehensive income/(loss) attributable to common shareholders
(
767
)
2,418
1,567
5,198
The accompanying notes are an integral part of these interim consolidated financial statements.
7
ENBRIDGE INC.
CONSOLIDATED STATEMEN
TS OF CHANGES IN EQUITY
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(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
71,808
69,201
71,738
69,180
Shares issued, net of issue costs
(Note 8)
—
2,489
—
2,489
Shares issued on exercise of stock options
14
1
46
5
Shares issued on vesting of restricted stock units (RSU), net of tax
1
7
39
24
Balance at end of period
71,823
71,698
71,823
71,698
Additional paid-in capital
Balance at beginning of period
229
274
275
268
Stock-based compensation
11
21
60
53
Stock options exercised
(
13
)
(
1
)
(
40
)
(
5
)
Vested RSUs
(
1
)
(
22
)
(
69
)
(
44
)
Balance at end of period
226
272
226
272
Deficit
Balance at beginning of period
(
17,785
)
(
15,696
)
(
20,046
)
(
17,115
)
Earnings attributable to controlling interests
2,279
1,943
4,643
3,455
Preference share dividends
(
102
)
(
95
)
(
205
)
(
188
)
Common share dividends declared
(
2,055
)
(
1,946
)
(
2,055
)
(
1,946
)
Balance at end of period
(
17,663
)
(
15,794
)
(
17,663
)
(
15,794
)
Accumulated other comprehensive income
(Note 9)
Balance at beginning of period
7,188
3,664
7,115
2,303
Other comprehensive income/(loss) attributable to common shareholders, net of tax
(
2,944
)
570
(
2,871
)
1,931
Balance at end of period
4,244
4,234
4,244
4,234
Total Enbridge Inc. shareholders' equity
65,448
67,228
65,448
67,228
Noncontrolling interests
Balance at beginning of period
3,022
3,042
2,993
3,029
Earnings attributable to noncontrolling interests
42
58
168
111
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain/(loss) on cash flow hedges
(
2
)
2
(
1
)
8
Foreign currency translation adjustments
(
60
)
12
(
59
)
41
(
62
)
14
(
60
)
49
Comprehensive income/(loss) attributable to noncontrolling interests
(
20
)
72
108
160
Distributions
(
95
)
(
89
)
(
195
)
(
167
)
Contributions
2
—
7
2
Other
1
—
(
3
)
1
Balance at end of period
2,910
3,025
2,910
3,025
Total equity
68,358
70,253
68,358
70,253
Dividends paid per common share
0.94
0.92
1.88
1.84
The accompanying notes are an integral part of these interim consolidated financial statements.
8
ENBRIDGE INC.
CONSOLIDATED STATE
MENTS OF CASH FLOWS
Six months ended
June 30,
2025
2024
(unaudited; millions of Canadian dollars)
Operating activities
Earnings
4,811
3,566
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization
2,799
2,466
Deferred income tax expense
791
613
Unrealized derivative fair value loss/(gain), net
(Note 10)
(
1,375
)
923
Income from equity investments
(
1,239
)
(
1,185
)
Distributions from equity investments
1,059
1,037
Impairment of long-lived assets
330
—
Gain on disposition of equity investments
—
(
1,091
)
Other
(
44
)
143
Changes in operating assets and liabilities
(
841
)
(
507
)
Net cash provided by operating activities
6,291
5,965
Investing activities
Capital expenditures
(
3,623
)
(
2,533
)
Long-term, restricted and other investments
(
1,380
)
(
1,294
)
Distributions from equity investments in excess of cumulative earnings
384
463
Additions to intangible assets
(
124
)
(
93
)
Acquisitions
—
(
10,454
)
Proceeds from disposition of equity investments
130
2,724
Other
(
35
)
(
43
)
Net cash used in investing activities
(
4,648
)
(
11,230
)
Financing activities
Net change in short-term borrowings
385
(
200
)
Net change in commercial paper and credit facility draws
(
497
)
2,963
Debenture and term note issues, net of issue costs
6,530
6,348
Debenture and term note repayments
(
4,079
)
(
4,561
)
Contributions from noncontrolling interests
7
2
Distributions to noncontrolling interests
(
195
)
(
167
)
Common shares issued, net of issue costs
6
2,485
Preference share dividends
(
206
)
(
188
)
Common share dividends
(
4,109
)
(
3,890
)
Net change in affiliate loans
25
15
Other
(
33
)
(
20
)
Net cash (used in)/provided by financing activities
(
2,166
)
2,787
Effect of translation of foreign denominated cash and cash equivalents and restricted cash
(
55
)
192
Net change in cash and cash equivalents and restricted cash
(
578
)
(
2,286
)
Cash and cash equivalents and restricted cash at beginning of period
1
2,000
5,985
Cash and cash equivalents and restricted cash at end of period
1
1,422
3,699
The accompanying notes are an integral part of these interim consolidated financial statements.
1
As at
June 30, 2025 and December 31, 2024, long-term restricted cash of
$
136
million
(June 30, 2024 -
$
96
million
) and
$
105
million
(December 31, 2023 -
nil
), respectively, was included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position.
9
ENBRIDGE INC.
CONSOLIDATED STATEMENTS
OF FINANCIAL POSITION
June 30,
2025
December 31,
2024
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents
1,203
1,803
Restricted cash
83
92
Trade receivables and unbilled revenues
5,454
6,920
Other current assets
2,844
2,770
Accounts receivable from affiliates
74
90
Inventory
1,414
1,488
11,072
13,163
Property, plant and equipment, net
128,179
131,104
Long-term investments
20,793
20,691
Restricted long-term investments and cash
(Note 10)
1,124
998
Deferred amounts and other assets
10,441
11,034
Intangible assets, net
4,276
4,587
Goodwill
35,162
36,600
Deferred income taxes
545
796
Total assets
211,592
218,973
Liabilities and equity
Current liabilities
Short-term borrowings
914
529
Trade payables and accrued liabilities
5,772
7,060
Other current liabilities
3,764
7,241
Accounts payable to affiliates
27
22
Interest payable
1,172
1,231
Current portion of long-term debt
3,158
7,729
14,807
23,812
Long-term debt
96,981
93,414
Other long-term liabilities
11,771
13,258
Deferred income taxes
19,675
19,596
143,234
150,080
Contingencies
(Note 13)
Equity
Share capital
Preference shares
6,818
6,818
Common shares
(
2,181
and
2,178
outstanding at June 30, 2025 and December 31, 2024, respectively)
71,823
71,738
Additional paid-in capital
226
275
Deficit
(
17,663
)
(
20,046
)
Accumulated other comprehensive income
(Note 9)
4,244
7,115
Total Enbridge Inc. shareholders’ equity
65,448
65,900
Noncontrolling interests
2,910
2,993
68,358
68,893
Total liabilities and equity
211,592
218,973
The accompanying notes are an integral part of these interim consolidated financial statements.
10
NOTES TO THE INTERIM
CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. BASIS OF PRESENTATION
The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2024. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2024. Amounts are stated in Canadian dollars unless otherwise noted.
Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as supply of and demand for crude oil and natural gas and may not be indicative of annual results.
Certain comparative figures in our interim consolidated financial statements have been reclassified to conform to the current year's presentation.
2.
CHANGES IN ACCOUNTING POLICIES
FUTURE ACCOUNTING POLICY CHANGES
Income Tax Disclosures
Accounting Standards Update (ASU) 2023-09 was issued in December 2023 to improve income tax disclosures by requiring specified categories in the annual rate reconciliation that meet quantitative thresholds and further disaggregation on income taxes paid by jurisdiction. ASU 2023-09 is effective January 1, 2025 and should be applied prospectively, with retrospective application being permitted. The effects of the new standard on the presentation of our income tax note disclosures will be reflected in our December 31, 2025 annual consolidated financial statements.
Disaggregation of Income Statement Expenses
ASU 2024-03 was issued in November 2024 to improve financial reporting by requiring entities to disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. The ASU requires entities to disclose 1) the amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, (e) depreciation, depletion and amortization recognized as part of oil and gas producing activities, (f) expense reimbursements included in a relevant expense caption, and (g) selling expenses, and 2) a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively. ASU 2024-03 is effective January 1, 2027, with interim period disclosure requirements effective after January 1, 2028 and can be applied either prospectively or retrospectively. We are currently assessing the impact of the new standard on our annual disclosures for the year ending December 31, 2027 and on our interim disclosures beginning in 2028.
11
3. REVENUE
Change in Revenue Classification
To better align the classification of revenues resulting from our acquisitions of the United States (US) Gas Utilities
(Note 6)
, we have made adjustments to Gas distribution sales and Transportation and other services revenues. Revenues generated from customers who procure their own gas but use our distribution system for delivery to the end use location have been reclassified to Gas distribution sales revenue from Transportation and other services revenue on the Consolidated Statements of Earnings and reclassified to Gas distribution sales from Transportation revenue in the Revenue from Contracts with Customers tables below. Our prior period comparable results have been recast to reflect the change in revenue classification. This change did not have an impact on our Total operating revenues.
REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
Three months ended June 30, 2025
Liquids Pipelines
Gas Transmission
Gas Distribution
and Storage
Renewable Power Generation
Eliminations and Other
Consolidated
(millions of Canadian dollars)
Transportation revenue
2,895
1,349
65
—
—
4,309
Storage and other revenue
75
162
152
—
—
389
Gas distribution sales
—
—
1,745
—
—
1,745
Electricity revenue
—
—
—
52
—
52
Commodity sales
—
28
—
—
—
28
Total revenue from contracts with customers
2,970
1,539
1,962
52
—
6,523
Commodity sales
7,787
29
—
—
280
8,096
Other revenue
1,2
80
32
55
90
—
257
Intersegment revenue
—
4
(
1
)
3
(
6
)
—
Total revenue
10,837
1,604
2,016
145
274
14,876
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
3
2,986
1,290
42
—
—
4,318
Storage and other revenue
65
135
127
—
—
327
Gas distribution sales
3
—
—
1,200
—
—
1,200
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 revenue
1,2
71
13
13
59
—
156
Intersegment revenue
—
5
2
3
(
10
)
—
Total revenue
8,158
1,492
1,384
106
196
11,336
12
Six months ended June 30, 2025
Liquids Pipelines
Gas Transmission
Gas Distribution
and Storage
Renewable Power Generation
Eliminations and Other
Consolidated
(millions of Canadian dollars)
Transportation revenue
6,000
2,829
155
—
—
8,984
Storage and other revenue
143
335
309
—
—
787
Gas distribution sales
—
—
5,415
—
—
5,415
Electricity revenue
—
—
—
94
—
94
Commodity sales
—
52
—
—
—
52
Total revenue from contracts with customers
6,143
3,216
5,879
94
—
15,332
Commodity sales
16,721
66
—
—
834
17,621
Other revenue
1,2
157
25
76
167
—
425
Intersegment revenue
—
12
17
4
(
33
)
—
Total revenue
23,021
3,319
5,972
265
801
33,378
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
3
6,010
2,631
135
—
—
8,776
Storage and other revenue
127
273
226
—
—
626
Gas distribution sales
3
—
—
3,124
—
—
3,124
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 revenue
1,2
134
19
26
132
—
311
Intersegment revenue
—
11
4
4
(
19
)
—
Total revenue
15,040
3,064
3,515
237
518
22,374
1
Includes realized and unrealized gains and losses from our hedging program which for the three months ended June 30, 2025 were a net
$
33
million
gain (2024 -
$
17
million
loss) and for the six months ended June 30, 2025 were a net
$
132
million
gain (2024 -
$
39
million
loss).
2
Includes revenues from lease contracts for the three months ended June 30, 2025 and 2024 of
$
141
million
and
$
142
million
, respectively, and for the six months ended June 30, 2025 and 2024 of
$
299
million
and
$
282
million
, respectively.
3
These balances reflect a transfer from Transportation revenue to Gas distribution sales of
$
427
million
and
$
685
million
for the three and six months ended June 30, 2024
, respectively.
We disaggregate revenues into categories which represent our principal performance obligations within each business segment. These revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.
13
Contract Balances
Contract Receivables
Contract
Assets
Contract Liabilities
(millions of Canadian dollars)
Balance as at June 30, 2025
2,859
302
2,672
Balance as at December 31, 2024
3,764
330
2,828
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, 2025 included in contract liabilities at the beginning of the period were
$
44
million
and
$
289
million
, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and six months ended June 30, 2025 were
$
69
million
and
$
211
million
, respectively.
Performance Obligations
There were no material revenues recognized in the three and six months ended June 30, 2025 from performance obligations satisfied in previous periods.
Revenues to be Recognized from Unfulfilled Performance Obligations
Total revenues from performance obligations expected to be fulfilled in future periods is
$
59.4
billion
, of which
$
5.0
billion
and
$
8.1
billion
are expected to be recognized during the remaining
six
months
ending
December 31, 2025
and the
year ending
December 31, 2026, 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.
14
Recognition and Measurement of Revenues
Three months ended June 30, 2025
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
—
28
31
—
59
Revenues from products and services transferred over time
1
2,970
1,511
1,931
52
6,464
Total revenue from contracts with customers
2,970
1,539
1,962
52
6,523
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 time
1
3,051
1,425
1,336
44
5,856
Total revenue from contracts with customers
3,051
1,463
1,369
44
5,927
Six months ended June 30, 2025
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
—
52
67
—
119
Revenues from products and services transferred over time
1
6,143
3,164
5,812
94
15,213
Total revenue from contracts with customers
6,143
3,216
5,879
94
15,332
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 time
1
6,137
2,904
3,423
101
12,565
Total revenue from contracts with customers
6,137
2,982
3,485
101
12,705
1
Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.
4. SEGMENTED INFORMATION
Three months ended June 30, 2025
Liquids
Pipelines
Gas
Transmission
Gas
Distribution
and Storage
Renewable
Power
Generation
Total
Reportable
Segments
(millions of Canadian dollars)
Operating revenues
1
10,837
1,604
2,016
145
14,602
Commodity and gas distribution costs
(
7,741
)
(
16
)
(
553
)
1
(
8,309
)
Operating and administrative
(
1,032
)
(
514
)
(
688
)
(
72
)
(
2,306
)
Impairment of long-lived assets
2
—
—
(
330
)
—
(
330
)
Income from equity investments
245
241
—
27
513
Other income
22
127
65
8
222
Earnings before interest, income taxes and depreciation and amortization
2,331
1,442
510
109
4,392
Eliminations and Other
1,167
Depreciation and amortization
(
1,391
)
Interest expense
(
1,181
)
Earnings before income taxes
2,987
15
Three months ended June 30, 2024
Liquids
Pipelines
Gas
Transmission
Gas
Distribution
and Storage
Renewable
Power
Generation
Total
Reportable
Segments
(millions of Canadian dollars)
Operating revenues
1
8,158
1,492
1,384
106
11,140
Commodity and gas distribution costs
(
4,909
)
(
41
)
(
312
)
2
(
5,260
)
Operating and administrative
(
1,100
)
(
604
)
(
528
)
(
71
)
(
2,303
)
Income from equity investments
284
164
1
45
494
Gain on disposition of equity investments
(Note 6)
—
1,063
—
28
1,091
Other income
17
21
22
28
88
Earnings before interest, income taxes and depreciation and amortization
2,450
2,095
567
138
5,250
Eliminations and Other
(
155
)
Depreciation and amortization
(
1,273
)
Interest expense
(
1,082
)
Earnings before income taxes
2,740
Six months ended June 30, 2025
Liquids
Pipelines
Gas
Transmission
Gas
Distribution
and Storage
Renewable
Power
Generation
Total
Reportable
Segments
(millions of Canadian dollars)
Operating revenues
1
23,021
3,319
5,972
265
32,577
Commodity and gas distribution costs
(
16,591
)
(
27
)
(
2,187
)
4
(
18,801
)
Operating and administrative
(
2,160
)
(
1,038
)
(
1,460
)
(
150
)
(
4,808
)
Impairment of long-lived assets
2
—
—
(
330
)
—
(
330
)
Income from equity investments
613
473
1
159
1,246
Other income
41
188
114
54
397
Earnings before interest, income taxes and depreciation and amortization
4,924
2,915
2,110
332
10,281
Eliminations and Other
1,207
Depreciation and amortization
(
2,799
)
Interest expense
(
2,515
)
Earnings before income taxes
6,174
Six months ended June 30, 2024
Liquids
Pipelines
Gas
Transmission
Gas
Distribution
and Storage
Renewable
Power
Generation
Total
Reportable
Segments
(millions of Canadian dollars)
Operating revenues
1
15,040
3,064
3,515
237
21,856
Commodity and gas distribution costs
(
8,544
)
(
88
)
(
1,316
)
(
1
)
(
9,949
)
Operating and administrative
(
2,207
)
(
1,165
)
(
907
)
(
140
)
(
4,419
)
Income from equity investments
537
429
1
226
1,193
Gain on disposition of equity investments
(Note 6)
—
1,063
—
28
1,091
Other income
28
57
39
45
169
Earnings before interest, income taxes and depreciation and amortization
4,854
3,360
1,332
395
9,941
Eliminations and Other
(
797
)
Depreciation and amortization
(
2,466
)
Interest expense
(
1,987
)
Earnings before income taxes
4,691
1
Refer to
Note 3 - Revenue
for a reconciliation of segment Operating revenues to the Consolidated Statements of Earnings.
2
The Gas Distribution and Storage segment includes the impact of an impairment recognized for certain rate-regulated assets related to pension and other disallowances as a result of the Public Utilities Commission of Ohio
's (Ohio Commission) June 2025 order related to Enbridge Gas Ohio's rate case.
16
Capital Expenditures
1
Three months ended June 30,
Six months ended June 30,
2025
2024
2025
2024
(millions of Canadian dollars)
Liquids Pipelines
284
209
593
498
Gas Transmission
691
666
1,295
1,161
Gas Distribution and Storage
735
433
1,396
737
Renewable Power Generation
214
48
359
117
Eliminations and Other
16
8
51
51
1,940
1,364
3,694
2,564
1
Capital expenditures are cash basis plus equity component of the allowance for funds used during construction.
Property, Plant and Equipment
June 30,
2025
December 31,
2024
(millions of Canadian dollars)
Liquids Pipelines
51,835
53,863
Gas Transmission
33,981
34,683
Gas Distribution
and Storage
38,261
38,636
Renewable Power Generation
3,781
3,612
Eliminations and Other
321
310
128,179
131,104
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,
2025
2024
2025
2024
(number of shares in millions)
Weighted average shares outstanding
2,180
2,137
2,180
2,131
Effect of dilutive options and RSUs
6
2
6
2
Diluted weighted average shares outstanding
2,186
2,139
2,186
2,133
For the three months ended June 30, 2025 and 2024,
1.6
million
and
18.0
million
, respectively, of anti-dilutive stock options with a weighted average exercise price of
$
60.21
and
$
54.55
, respectively, were excluded from the diluted earnings per common share calculation.
For the six months ended June 30, 2025 and 2024,
2.4
million
and
20.5
million
, respectively, of anti-dilutive stock options with a weighted average exercise price of
$
60.37
and
$
53.66
, respectively, were excluded from the diluted earnings per common share calculation.
17
DIVIDENDS PER SHARE
The Board of Directors has declared the following quarterly dividends. All dividends are payable on
September 1, 2025 to shareholders of record on August 15, 2025.
Dividend per share
Common Shares
$
0.94250
Preference Shares, Series A
$
0.34375
Preference Shares, Series B
$
0.32513
Preference Shares, Series D
$
0.33825
Preference Shares, Series F
$
0.34613
Preference Shares, Series G
1
$
0.32515
Preference Shares, Series H
$
0.38200
Preference Shares, Series I
2
$
0.30058
Preference Shares, Series L
US$
0.36612
Preference Shares, Series N
$
0.41850
Preference Shares, Series P
$
0.36988
Preference Shares, Series R
$
0.39463
Preference Shares, Series 1
US$
0.41898
Preference Shares, Series 3
$
0.33050
Preference Shares, Series 4
3
$
0.31696
Preference Shares, Series 5
US$
0.41769
Preference Shares, Series 7
$
0.37425
Preference Shares, Series 9
$
0.35450
Preference Shares, Series 11
$
0.34231
Preference Shares, Series 13
4
$
0.33719
Preference Shares, Series 15
$
0.18644
Preference Shares, Series 19
$
0.38825
1
The quarterly dividend per share paid on Preference Shares, Series G was decreased to
$
0.32515
from
$
0.34468
on June 1, 2025 due to the reset of the dividend on a quarterly basis.
2
The quarterly dividend per share paid on Preference Shares, Series I was decreased to
$
0.30058
from
$
0.32011
on June 1, 2025 due to the reset of the dividend on a quarterly basis.
3
The quarterly dividend per share paid on Preference Shares, Series 4 was decreased to
$
0.31696
from
$
0.33649
on June 1, 2025 due to the reset of the dividend on a quarterly basis.
4
The quarterly dividend per share paid on Preference Shares, Series 13 was increased to
$
0.33719
from
$
0.19019
on June 1, 2025 due to the reset of the annual dividend on June 1, 2025
.
18
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 Utah Public Service Commission, the Wyoming Public Service Commission and the Idaho Public Utilities Commission have granted Questar the necessary regulatory approvals to serve these areas. Wexpro develops and produces cost-of-service gas reserves for Questar and operates under agreements with the states of Utah and Wyoming. Subsequent to its acquisition, Questar conducts business as Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho in those respective states.
The following table summarizes the estimated fair values that were assigned to the net assets of Questar and Wexpro:
May 31, 2024
1
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)
380
Property, plant and equipment (b)
6,013
Long-term assets (c)
163
Current liabilities
416
Long-term debt (d)
1,343
Other long-term liabilities (e)
919
Deferred income tax liabilities
527
Goodwill (f)
793
Purchase price:
Cash
4,144
1
In the fourth quarter of 2024, immaterial adjustments were made to the Questar Acquisition purchase price allocation.
a)
Current assets consist primarily of cash, trade and other accounts receivable and inventory. The fair value of trade receivables from customers approximates their carrying value of $
202
million due to the short period to maturity. A provision of $
9
million for expected credit loss associated with accounts receivable has been recorded.
19
b)
Questar's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, distribution and storage assets. Wexpro's property, plant and equipment consists of cost-of-service gas and oil properties developed and produced for Questar. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value.
c)
Long-term assets consist primarily of funds collected from Questar by Wexpro and held in trust to fund future asset retirement obligations (ARO), as well as regulatory assets expected to be recovered from customers in future periods through rates.
d)
The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $
301
million 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, including the results of operations for Questar and Wexpro as if the Questar Acquisition had been completed on January 1, 2023, was as follows:
June 30, 2024
Three months ended
Six months ended
(unaudited; millions of Canadian dollars)
Operating revenues
11,619
23,589
Earnings attributable to common shareholders
1,871
3,402
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 o
f $
5.8
billion (US$
4.3
bil
lion) (the EOG Acquisition). EOG is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Ohio and is regulated by the Ohio Commission. Subsequent to its acquisition, EOG conducts business as Enbridge Gas Ohio.
20
The following table summarizes the estimated fair values that were assigned to the net assets of EOG:
March 6, 2024
1
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)
493
Property, plant and equipment (b)
7,276
Long-term assets (c)
1,689
Current liabilities
551
Long-term debt (d)
2,612
Other long-term liabilities (e)
1,001
Deferred income tax liabilities
1,045
Goodwill (f)
1,603
Purchase price:
Cash
5,852
1
In the fourth quarter of 2024, immaterial adjustments were made to the EOG Acquisition purchase price allocation.
a)
Current assets consist primarily of trade and other accounts receivable, prepaid expenses, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $
379
million due to the short period to maturity. A provision of $
3
million for expected credit loss associated with accounts receivable has been recorded.
b)
EOG's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, gathering, distribution and storage assets. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value.
c)
Long-term assets consist primarily of overfunded pension plan assets of $
367
million and $
1.2
billion of regulatory assets expected to be recovered from customers in future periods through rates.
Pension plan assets attributable to the workforce acquired from EOG were transferred in cash to an Enbridge-sponsored pension plan based on their fair value as at March 6, 2024. The fair value of plan assets was determined using unadjusted quoted market prices for identical investments.
d)
The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $
478
million 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.
21
Our supplemental pro forma consolidated financial information for the
three and six months ended June 30, 2024, including the results of operations for EOG as if the EOG Acquisition had been completed on January 1, 2023, was as follows:
June 30, 2024
Three months ended
Six months ended
(unaudited; millions of Canadian dollars)
Operating revenues
11,340
22,686
Earnings attributable to common shareholders
1,842
3,318
The Questar Acquisition and EOG Acquisition further diversify, and are complementary to, our existing gas distribution operations.
Acquisition of RNG Facilities
On January 2, 2024, through a wholly-owned US subsidiary, we 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 lower-carbon strategy.
The following table summarizes the estimated 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 (approximately
nine years
to the next extension period on a weighted-average basis).
b)
Tomorrow RNG's property, plant and equipment constitutes specialized landfill gas plant and equipment which collects gas produced by waste decomposition, treats and compresses the gas to pipeline specifications. The direct method of replacement cost was used to determine the majority of the fair value of property, plant and equipment. Adjustments were then applied for estimated physical deterioration.
22
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 payment was made on January 2, 2025 and the second payment is due on December 31, 2025. The $
757
million (US$
568
million) recognized in the purchase price represents the fair value of deferred consideration at the date of acquisition using the imputed interest rate method over the terms of the notes.
Upon completion of the RNG Facilities Acquisition, we began consolidating Tomorrow RNG. For the period beginning January 2, 2024 through to 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, as if the RNG Facilities Acquisition had been completed on January 1, 2023, was also immaterial.
NONCONTROLLING INTEREST INVESTMENT
BC Pipeline System
On July 2, 2025, Stonlasec8 Indigenous Alliance Limited Partnership (the First Nations Partnership), an entity representing
38
First Nations in British Columbia (BC), invested approximately $
736
million in our Westcoast Energy Inc. BC natural gas pipeline system, resulting in the First Nations Partnership owning a
12.5
% interest in that system.
The cash consideration of $
736
million and a respective redeemable noncontrolling interest at the consideration received less transaction costs will be recorded in our consolidated financial statements in the third quarter of 2025 to reflect the interest held by the First Nations Partnership.
Subsequent to the First Nations Partnership's investment, we will hold an
87.5
% controlling interest in these assets, which are included in our Gas Transmission segment, and continue to manage and operate the pipeline system.
DISPOSITION
Disposition of Alliance Pipeline and Aux Sable Interests
On April 1, 2024, we closed the sale of our
50.0
% interest in the Alliance Pipeline, our interest in Aux Sable (including a
42.7
% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a
50.0
% interest in Aux Sable Canada LP) and our interest in NRGreen Power Limited Partnership (NRGreen) to Pembina Pipeline Corporation for $
3.1
billion, including $
327
million of non-recourse debt. A gain on disposal of $
1.1
billion before tax, which is net of $
1.0
billion of the goodwill from our Gas Transmission segment allocated to the disposal group, is included in Gain on disposition of equity investments in the Consolidated Statements of Earnings for the 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 TRANSACTIONS
Joint Venture with WhiteWater/I Squared and MPLX
On May 29, 2024, we formed a joint venture (the Whistler Parent JV) with WhiteWater/I Squared Capital (WhiteWater/I Squared) and MPLX LP (MPLX) that 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.
23
In connection with the formation of the Whistler Parent JV, we contributed our
100
% interest in the Rio Bravo Pipeline project and $
487
million (US$
357
million) of cash to the Whistler Parent JV. In addition to our
19.0
% equity interest in the Whistler Parent JV, we received a special equity interest in the Whistler Parent JV which provides for a
25.0
% economic interest in the Rio Bravo Pipeline project. This interest is subject to certain redemption rights held by the Whistler Parent JV, which was redeemed on July 17, 2025 for net proceeds of $
180
million (US$
130
million). After the closing on May 29, 2024, we accrued for our share of the post-closing mandatory capital expenditures of approximately US$
150
million for the Rio Bravo Pipeline project.
The contribution of our interest in the Rio Bravo Pipeline project to the Whistler Parent JV in exchange for the equity interests discussed above represents a non-cash transaction in Cash Flows from Investing Activities and does not have an effect on our Consolidated Statements of Cash Flows. This component of the transaction resulted in a reduction of $
321
million (US$
235
million) to Property, plant and equipment, net and a corresponding increase to Long-term investments in the Consolidated Statements of Financial Position. The cash component of the transaction, as well as subsequent cash payments made for post-closing mandatory capital expenditures, have been reflected as contributions in Cash Flows from Investing Activities.
7. DEBT
CREDIT FACILITIES
The following table provides details of our committed credit facilities as at
June 30, 2025:
Maturity
1
Total
Facilities
Draws
2
Available
(millions of Canadian dollars)
Enbridge Inc.
2026
-
2049
8,032
6,112
1,920
Enbridge (U.S.) Inc.
2026
-
2029
10,259
3,781
6,478
Enbridge Pipelines Inc.
2026
2,000
441
1,559
Enbridge Gas Inc.
2026
2,500
915
1,585
Total committed credit facilities
22,791
11,249
11,542
1
Maturity date is inclusive of the
one-year
term out option for certain credit facilities.
2
Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
In July 2025, we renewed approximately
$
8.8
billion
of our
364
-day
extendible credit facilities, extending the maturity dates to
July 2027
, which includes a
one
-year
term out provision from
July 2026. We also renewed approximately
$
7.8
billion
of our
five
-year
credit facilities, extending the maturity dates to
July 2030
. Further, we extended the maturity dates of our
three
-year
credit facilities to
July 2028
.
In July 2025, Enbridge Gas Inc. (Enbridge Gas Ontario) and Enbridge Pipelines Inc. extended the maturity dates of their
$
2.5
billion
and
$
2.0
billion
364
-day
extendible credit facilities, respectively, to
July 2027
, which includes a
one
-year
term out provision from
July 2026.
In addition to the committed credit facilities noted above, we maintain
$
1.5
billion
of uncommitted demand letter of credit facilities, of which
$
932
million
was unutilized as at June 30, 2025. As at December 31, 2024, we had
$
1.4
billion
of uncommitted demand letter of credit facilities, of which
$
931
million
was unutilized.
Our credit facilities carry a weighted average standby fee of
0.1
%
per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to our commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from
2026
to
2049
.
24
As at June 30, 2025 and December 31, 2024, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of
$
10.3
billion
, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.
LONG-TERM DEBT ISSUANCES
During the
six months ended June 30, 2025, we completed the following long-term debt issuances totaling
$
2.8
billion
and US
$
2.8
billion
:
Company
Issue Date
Principal
Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
February 2025
Floating rate medium-term notes due February 2028
1
$
400
February 2025
3.55
%
medium-term notes due February 2028
$
300
February 2025
3.90
%
medium-term notes due February 2030
$
800
February 2025
4.56
%
medium-term notes due February 2035
$
700
February 2025
5.32
%
medium-term notes due August 2054
$
600
June 2025
4.60
%
senior notes due June 2028
US$
400
June 2025
4.90
%
senior notes due June 2030
US$
600
June 2025
5.55
%
senior notes due June 2035
US$
900
June 2025
5.95
%
senior notes due April 2054
US$
350
The East Ohio Gas Company
June 2025
5.68
%
senior notes due June 2035
US$
250
June 2025
6.32
%
senior notes due June 2055
US$
250
1
Notes carry an interest rate set to equal the Canadian Overnight Repo Rate Average plus a margin of
85
basis points.
LONG-TERM DEBT REPAYMENTS
During the
six months ended June 30, 2025, we completed the following long-term debt repayments totaling US
$
2.5
billion
,
$
661
million
and
€
21
million
:
Company
Repayment Date
Principal
Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
January 2025
2.50
%
senior notes
US$
500
February 2025
2.50
%
senior notes
US$
500
June 2025
2.44
%
medium-term notes
$
550
Enbridge Pipelines (Southern Lights) L.L.C.
June 2025
3.98
%
senior notes
US$
47
Enbridge Pipelines Inc.
February 2025
4.10
%
medium-term notes
1
$
100
Enbridge Southern Lights LP
June 2025
4.01
%
senior notes
$
11
Spectra Energy Partners, LP
March 2025
3.50
%
senior notes
US$
500
Blauracke GMBH
April 2025
2.10
%
senior notes
€
21
Enbridge Holdings (Tomorrow RNG), LLC
January 2025
4.97
%
senior notes
US$
309
January 2025
4.97
%
senior notes
US$
85
January 2025
4.97
%
senior notes
US$
19
The East Ohio Gas Company
June 2025
1.30
%
senior notes
US$
500
1
The notes carried an original maturity date in July 2112
.
On July 28, 2025, Enbridge Energy Partners, L.P. redeemed at par all of the outstanding US
$
500
million
5.88
%
senior notes that carried an original maturity date in
October 2025
.
25
SUBORDINATED TERM NOTES
As at June 30, 2025 and December 31, 2024, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of
$
14.9
billion and $
15.5
billion, respectively
.
FAIR VALUE ADJUSTMENT
As at June 30, 2025 and December 31, 2024, the fair value adjustments to decrease total debt assumed in historical acquisitions were
$
424
million
and
$
468
million
, respectively.
DEBT COVENANTS
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at June 30, 2025
, 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 the acquisition of Public Service Company of North Carolina, Incorporated 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, 2025 and 2024 are as follows:
Cash
Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
and Other
Investments
Pension
and
OPEB
Adjustment
Total
(millions of Canadian dollars)
Balance as at January 1, 2025
407
(
14
)
(
2,033
)
8,452
1
302
7,115
Other comprehensive income/(loss) retained in AOCI
(
15
)
12
413
(
3,356
)
21
62
(
2,863
)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts
1
17
—
—
—
—
—
17
Foreign exchange contracts
2
—
(
3
)
—
—
—
—
(
3
)
Amortization of pension and OPEB actuarial gain
3
—
—
—
—
—
(
14
)
(
14
)
2
9
413
(
3,356
)
21
48
(
2,863
)
Tax impact
Income tax on amounts retained in AOCI
2
(
3
)
—
—
—
(
13
)
(
14
)
Income tax on amounts reclassified to earnings
(
3
)
8
—
—
—
1
6
(
1
)
5
—
—
—
(
12
)
(
8
)
Balance as at June 30, 2025
408
—
(
1,620
)
5,096
22
338
4,244
26
Cash
Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
and Other
Investments
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 contracts
1
12
—
—
—
—
—
12
Commodity contracts
4
(
1
)
—
—
—
—
—
(
1
)
Foreign exchange contracts
2
—
31
—
—
—
—
31
Amortization of pension and OPEB actuarial gain
3
—
—
—
—
—
(
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
1
Reported within Interest expense in the Consolidated Statements of Earnings.
2
Reported within Interest expense and Other income/(expense) in the Consolidated Statements of Earnings.
3
These components are included in the computation of net periodic benefit credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings.
4
Reported within Transportation and other services revenues 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 US dollar-denominated debt.
Interest Rate Risk
Our earnings, cash flows and OCI are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We have a policy of limiting the maximum floating rate debt to
30
% of total debt outstanding. To ensure compliance with our policy, we monitor and adjust our debt portfolio mix of fixed and variable rate debt instruments in conjunction with the use of derivative instruments.
We have implemented a program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps and costless collars. These swaps have an average fixed rate of
3.1
%.
27
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. A combination of qualifying and non-qualifying forward starting interest rate swaps is used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via execution of floating-to-fixed interest rate swaps with an average swap rate of
3.4
%.
Commodity Price Risk
Our earnings, cash flows and OCI are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy marketing subsidiaries. These commodities include natural gas, crude oil, power and natural gas liquids (NGL). We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. For our US Gas Utilities, changes in derivatives' fair values are deferred as regulatory assets or liabilities until settlement. We use primarily non-qualifying derivative instruments to manage commodity price risk.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through the revaluation of outstanding units every period.
TOTAL DERIVATIVE INSTRUMENTS
We have a policy of entering into individual International Swaps and Derivatives Association, Inc. (ISDA) agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions in those circumstances.
The following tables summarize the Consolidated Statements of Financial Position location and carrying value of our derivative instruments, as well as the maximum potential settlement amounts, in the event of the specific circumstances described above.
28
June 30, 2025
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
—
—
33
33
(
19
)
14
Interest rate contracts
12
—
20
32
(
15
)
17
Commodity contracts
—
—
391
391
(
230
)
161
12
—
444
456
(
264
)
192
Deferred amounts and other assets
Foreign exchange contracts
—
—
75
75
(
33
)
42
Interest rate contracts
26
—
91
117
(
28
)
89
Commodity contracts
—
—
116
116
(
43
)
73
26
—
282
308
(
104
)
204
Other current liabilities
Foreign exchange contracts
—
—
(
334
)
(
334
)
19
(
315
)
Interest rate contracts
(
12
)
—
(
26
)
(
38
)
15
(
23
)
Commodity contracts
(
1
)
—
(
395
)
(
396
)
230
(
166
)
(
13
)
—
(
755
)
(
768
)
264
(
504
)
Other long-term liabilities
Foreign exchange contracts
—
—
(
721
)
(
721
)
33
(
688
)
Interest rate contracts
(
12
)
—
(
67
)
(
79
)
28
(
51
)
Commodity contracts
—
—
(
122
)
(
122
)
43
(
79
)
(
12
)
—
(
910
)
(
922
)
104
(
818
)
Total net derivative asset/(liability)
Foreign exchange contracts
—
—
(
947
)
(
947
)
—
(
947
)
Interest rate contracts
14
—
18
32
—
32
Commodity contracts
(
1
)
—
(
10
)
(
11
)
—
(
11
)
13
—
(
939
)
(
926
)
—
(
926
)
29
December 31, 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
—
78
47
125
(
29
)
96
Interest rate contracts
44
—
23
67
(
39
)
28
Commodity contracts
2
—
360
362
(
191
)
171
Other contracts
—
—
3
3
—
3
46
78
433
557
(
259
)
298
Deferred amounts and other assets
Foreign exchange contracts
—
—
83
83
(
71
)
12
Interest rate contracts
9
—
137
146
(
27
)
119
Commodity contracts
—
—
197
197
(
39
)
158
9
—
417
426
(
137
)
289
Other current liabilities
Foreign exchange contracts
—
(
73
)
(
731
)
(
804
)
29
(
775
)
Interest rate contracts
(
58
)
—
(
22
)
(
80
)
39
(
41
)
Commodity contracts
—
—
(
451
)
(
451
)
191
(
260
)
(
58
)
(
73
)
(
1,204
)
(
1,335
)
259
(
1,076
)
Other long-term liabilities
Foreign exchange contracts
—
—
(
1,579
)
(
1,579
)
71
(
1,508
)
Interest rate contracts
—
—
(
80
)
(
80
)
27
(
53
)
Commodity contracts
(
1
)
—
(
238
)
(
239
)
39
(
200
)
(
1
)
—
(
1,897
)
(
1,898
)
137
(
1,761
)
Total net derivative asset/(liability)
Foreign exchange contracts
—
5
(
2,180
)
(
2,175
)
—
(
2,175
)
Interest rate contracts
(
5
)
—
58
53
—
53
Commodity contracts
1
—
(
132
)
(
131
)
—
(
131
)
Other contracts
—
—
3
3
—
3
(
4
)
5
(
2,251
)
(
2,250
)
—
(
2,250
)
The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments:
June 30, 2025
2025
2026
2027
2028
2029
Thereafter
Total
Foreign exchange contracts - US dollar forwards - purchase
(millions of US dollars)
798
—
—
—
—
—
798
Foreign exchange contracts - US dollar forwards - sell
(millions of US dollars)
3,330
5,627
4,841
3,552
1,278
30
18,658
Foreign exchange contracts - British pound (GBP) forwards - sell
(millions of GBP)
18
28
32
—
—
—
78
Foreign exchange contracts - Euro forwards - sell
(millions of Euro)
63
121
81
67
66
129
527
Interest rate contracts - short-term pay fixed rate
(millions of Canadian dollars)
1,338
2,230
1,175
549
34
—
5,326
Interest rate contracts - long-term pay fixed rate
(millions of Canadian dollars)
1
1,048
1,860
—
—
—
—
2,908
Interest rate contracts - costless collar
(millions of Canadian dollars)
981
1,760
1,319
51
—
—
4,111
Commodity contracts - natural gas
(billions of cubic feet)
2
42
91
56
22
14
2
227
Commodity contracts - crude oil
(millions of barrels)
2
(
15
)
2
2
1
1
1
(
8
)
Commodity contracts - power
(megawatt per hour (MW/H))
149
142
85
30
29
(
2
)
37
3
1
Represents the notional amount of long-term debt issuances hedged.
2
Represents the notional amount of net purchase/(sale).
3
Total is an average net purchase/(sale) of power.
30
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,
2025
2024
2025
2024
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative
28
(
29
)
(
14
)
(
92
)
Unrealized gain/(loss) on hedged item
(
51
)
26
(
1
)
100
Realized gain/(loss) on derivative
(
36
)
(
12
)
25
47
Realized gain/(loss) on hedged item
51
—
(
23
)
(
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,
2025
2024
2025
2024
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Interest rate contracts
21
10
(
14
)
148
Commodity contracts
(
3
)
3
(
2
)
15
Other contracts
—
—
—
1
Fair value hedges
Foreign exchange contracts
18
(
11
)
12
(
26
)
36
2
(
4
)
138
Amount of (income)/loss reclassified from AOCI to earnings
Foreign exchange contracts
¹
(
15
)
12
(
3
)
31
Interest rate contracts
²
9
12
17
12
Commodity contracts
3
—
(
1
)
—
(
1
)
(
6
)
23
14
42
1
Reported within Interest expense and Other income/(expense) in the Consolidated Statements of Earnings.
2
Reported within Interest expense in the Consolidated Statements of Earnings.
3
Reported within Transportation and other services
revenues in the Consolidated Statements of Earnings.
We estimate that a loss of
$
1
million
from AOCI related to open cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is
two years
as at
June 30, 2025.
31
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,
2025
2024
2025
2024
(millions of Canadian dollars)
Foreign exchange contracts
1
1,195
(
209
)
1,233
(
939
)
Interest rate contracts
2
33
17
(
40
)
122
Commodity contracts
3
4
(
50
)
126
(
117
)
Other contracts
4
—
—
(
3
)
(
1
)
Total unrealized derivative fair value gain/(loss), net
1,232
(
242
)
1,316
(
935
)
1
Reported within Other income/(expense) in the Consolidated Statements of Earnings.
2
Reported within Interest expense in the Consolidated Statements of Earnings.
3
For the respective six months ended periods, reported within Transportation and other services (2025 -
$
105
million
gain; 2024 -
$
60
million
loss), Commodity sales (2025 -
$
42
million
gain; 2024 -
$
2
million
loss), Commodity costs (2025 -
$
18
million
gain; 2024 -
$
20
million
loss) and Operating and administrative expense (2025 -
$
20
million
gain; 2024 -
$
23
million
loss) in the Consolidated Statements of Earnings.The fair value change in our US Gas Utilities is deferred as regulatory assets/(liabilities) (2025 -
$
59
million
asset; 2024 -
$
12
million
liability).
4
Reported within Operating and administrative
expense in the Consolidated Statements of Earnings.
LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a
12
-month rolling time period to determine whether sufficient funds will be available. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. Our shelf prospectuses with securities regulators enable ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for 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, 2025. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities. We also identify other potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.
CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through the maintenance and monitoring of credit exposure limits, contractual requirements and netting arrangements. We also review counterparty credit exposure using external credit rating services and other analytical tools to manage credit risk.
We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:
June 30,
2025
December 31,
2024
(millions of Canadian dollars)
Canadian financial institutions
249
344
US financial institutions
191
128
European financial institutions
75
116
Asian financial institutions
32
53
Other
1
209
332
756
973
1
Other is comprised of commodity clearing house and crude oil, natural gas and power counterparties.
32
As at June 30, 2025
, we did not provide any letters of credit in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held
no
cash collateral on derivative asset exposures as at
June 30, 2025 and December 31, 2024.
Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation.
Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, the assessment of counterparty credit ratings and netting arrangements. Within the Gas Distribution and Storage segment, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.
FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.
FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our financial instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.
Level 1
Level 1 includes financial instruments measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a financial instrument is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Under the fair value hierarchy, cash and cash equivalents are classified as Level 1. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations, US and Canadian treasury bills, and investments in exchange-traded funds held by our captive insurance subsidiaries. We also have restricted long-term investments in exchange-traded funds and common shares held in trust in accordance with the regulatory requirements of the Canada Energy Regulator (CER) under the Land Matters Consultation Initiative (LMCI) and to cover future pipeline decommissioning costs in the state of Minnesota.
Level 2
Level 2 includes financial instrument valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Financial instruments in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the financial instrument. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross-currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.
33
We have also categorized the fair value of our long-term debt, investments in debt securities held by our captive insurance subsidiaries, and restricted long-term investments in Canadian government bonds held in trust in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our long-term debt is based on quoted market prices for instruments of similar credit risk and tenor. When possible, the fair value of our restricted long-term investments is based on quoted market prices for similar instruments and, if not available, based on broker quotes.
Level 3
Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivative's fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on the extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power, NGL and natural gas contracts, basis swaps, commodity swaps, and power and energy swaps, physical forward commodity contracts, as well as options. We do not have any other financial instruments categorized in Level 3.
We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third-party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread, as well as the credit default swap spreads associated with our counterparties, in our estimation of fair value.
34
Fair Value of Derivatives
We have categorized our derivative assets and liabilities measured at fair value as follows:
June 30, 2025
Level 1
Level 2
Level 3
Total Gross
Derivative
Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
—
33
—
33
Interest rate contracts
—
32
—
32
Commodity contracts
65
72
254
391
65
137
254
456
Long-term derivative assets
Foreign exchange contracts
—
75
—
75
Interest rate contracts
—
117
—
117
Commodity contracts
2
14
100
116
2
206
100
308
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
—
(
334
)
—
(
334
)
Interest rate contracts
—
(
38
)
—
(
38
)
Commodity contracts
(
79
)
(
71
)
(
246
)
(
396
)
(
79
)
(
443
)
(
246
)
(
768
)
Long-term derivative liabilities
Foreign exchange contracts
—
(
721
)
—
(
721
)
Interest rate contracts
—
(
79
)
—
(
79
)
Commodity contracts
(
8
)
(
23
)
(
91
)
(
122
)
(
8
)
(
823
)
(
91
)
(
922
)
Total net financial asset/(liability)
Foreign exchange contracts
—
(
947
)
—
(
947
)
Interest rate contracts
—
32
—
32
Commodity contracts
(
20
)
(
8
)
17
(
11
)
(
20
)
(
923
)
17
(
926
)
35
December 31, 2024
Level 1
Level 2
Level 3
Total Gross
Derivative
Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
—
125
—
125
Interest rate contracts
—
67
—
67
Commodity contracts
34
72
256
362
Other contracts
—
3
—
3
34
267
256
557
Long-term derivative assets
Foreign exchange contracts
—
83
—
83
Interest rate contracts
—
146
—
146
Commodity contracts
1
14
182
197
1
243
182
426
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
—
(
804
)
—
(
804
)
Interest rate contracts
—
(
80
)
—
(
80
)
Commodity contracts
(
52
)
(
116
)
(
283
)
(
451
)
(
52
)
(
1,000
)
(
283
)
(
1,335
)
Long-term derivative liabilities
Foreign exchange contracts
—
(
1,579
)
—
(
1,579
)
Interest rate contracts
—
(
80
)
—
(
80
)
Commodity contracts
(
1
)
(
31
)
(
207
)
(
239
)
(
1
)
(
1,690
)
(
207
)
(
1,898
)
Total net financial asset/(liability)
Foreign exchange contracts
—
(
2,175
)
—
(
2,175
)
Interest rate contracts
—
53
—
53
Commodity contracts
(
18
)
(
61
)
(
52
)
(
131
)
Other contracts
—
3
—
3
(
18
)
(
2,180
)
(
52
)
(
2,250
)
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
June 30, 2025
Fair
Value
Unobservable
Input
Minimum
Price/
Volatility
Maximum
Price/Volatility
Weighted
Average Price/Volatility
Unit of
Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial
¹
Natural gas
8
Forward gas price
2.31
8.99
5.22
$/mmbtu
2
Crude
5
Forward crude price
63.63
87.11
83.24
$/barrel
Power
(
7
)
Forward power price
31.69
185.09
69.54
$/MW/H
Commodity contracts - physical
¹
Natural gas
(
45
)
Forward gas price
0.35
13.79
4.42
$/mmbtu
2
Crude
(
6
)
Forward crude price
65.05
112.22
85.79
$/barrel
Power
(
7
)
Forward power price
28.70
139.72
70.66
$/MW/H
Commodity options
3
Natural gas
69
Forward gas price
3.62
11.03
7.22
$/mmbtu
2
Price volatility
3
%
74
%
52
%
17
1
Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2
One million British thermal units (mmbtu).
3
Commodity options contracts are valued using an option model valuation technique.
36
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,
2025
2024
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period
(
52
)
(
131
)
Total gain/(loss), unrealized
Included in earnings
1
42
(
38
)
Included in OCI
(
1
)
15
Included in regulatory assets/liabilities
(
132
)
—
Settlements
160
5
Level 3 net derivative asset/(liability) at end of period
17
(
149
)
1
Reported 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, 2025 or December 31, 2024.
Net Investment Hedges
We currently have designated a portion of our US dollar-denominated debt as a hedge of our net investment in US dollar-denominated investments and subsidiaries.
During the six months ended June 30, 2025 and 2024, we recognized unrealized foreign exchange gains of
$
494
million
and losses of
$
425
million
, respectively, on the translation of US dollar-denominated debt, in OCI. During the six months ended June 30, 2025 and 2024, we recognized realized losses of
$
81
million
and
$
113
million
, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.
Fair Value of Other Financial Instruments
Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled
$
185
million
and
$
187
million
as at June 30, 2025 and December 31, 2024
, respectively.
We have restricted long-term investments and cash held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements under the LMCI, to cover future pipeline decommissioning costs in the state of Minnesota and to satisfy retirement obligations as Wexpro properties are abandoned. These investments are classified as available-for-sale, recognized at fair value and included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position. As at
June 30, 2025, the fair value of investments in Level 1 and Level 2 was
$
746
million
and
$
378
million
, respectively (December 31, 2024 -
$
491
million
and
$
507
million
, respectively). Our Level 2 investments had a cost basis of
$
377
million
as at June 30, 2025 (December 31, 2024 -
$
540
million
). There were unrealized holding gains of
$
30
million
and
$
46
million
on these investments for the three and six months ended June 30, 2025, respectively (2024 - gains of
$
12
million
and losses of
$
1
million
, respectively). During the six months ended June 30, 2025, we purchased and sold investments totaling
$
892
million
and
$
801
million
, respectively (2024 - purchases of
$
240
million
and sales of
$
197
million
). The resulting net cash flow impact is presented under Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.
37
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, 2025, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was
nil
and
$
1.1
billion
, respectively (December 31, 2024 -
$
114
million
and
$
1.1
billion
, respectively). Our investments in debt securities had a cost basis of
$
1.1
billion
as at June 30, 2025 and December 31, 2024
. These investments in equity funds and debt securities are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, respectively, and are recorded in
Other current assets
and
Long-term investments
in the Consolidated Statements of Financial Position. There were unrealized holding
gains of
$
1
million
for the three and six months ended June 30, 2025, respectively (2024 - gains of
$
5
million
and
$
21
million
, respectively).
As at
June 30, 2025 and December 31, 2024, our long-term debt, including finance lease liabilities, had a carrying value of
$
100.6
billion
and
$
101.6
billion
, respectively, before debt issuance costs and a fair value of
$
98.7
billion
and
$
98.9
billion
, respectively.
The fair value of financial assets and liabilities other than derivative instruments, certain long-term investments in other entities, restricted long-term investments, investments held by our captive insurance subsidiaries and long-term debt described above approximate their carrying value due to the short period to maturity.
11. INCOME TAXES
The effective income tax rates for the three months ended June 30, 2025 and 2024
were
22.3
%
and
27.0
%
, respectively, and for the six months ended June 30, 2025 and 2024 were
22.1
%
and
24.0
%
, respectively.
The period-over-period decreases in the effective income tax rates were primarily due to higher US investment tax credits, lower US minimum tax, the prior year write-down of non-deductible goodwill on the Gas Transmission segment, partially offset by the prior year tax benefits relating to the state apportionment income tax rate change due to the Acquisitions
(Note 6)
and the non-taxable portion of the gain on the disposition of Alliance Pipeline and Aux Sable
(Note 6)
relative to the increase in earnings over the comparative periods.
On July 4, 2025, President Trump signed into law the
One Big Beautiful Bill Act
, which includes a broad range of tax reform provisions. As the legislation was enacted after the reporting period, the financial results for the period ended June 30, 2025, do not reflect the impact of this new law. We do not expect the changes from the
One Big Beautiful Bill Act
to have a material impact on our consolidated financial results.
12. OTHER INCOME/(EXPENSE)
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(millions of Canadian dollars)
Realized foreign currency gain/(loss)
(
104
)
(
8
)
(
286
)
114
Unrealized foreign currency gain/(loss)
1,194
(
213
)
1,249
(
1,071
)
Net defined pension and OPEB credit
72
48
144
89
Other
207
142
382
286
1,369
(
31
)
1,489
(
582
)
38
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 cases, we may decide to self-insure additional risks.
In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among entities on an equitable basis based on an insurance allocation agreement we have entered into with us and other subsidiaries.
39
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, 2024.
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
NONCONTROLLING INTEREST INVESTMENT
BC Pipeline System
On July 2, 2025, Stonlasec8 Indigenous Alliance Limited Partnership (the First Nations Partnership), an entity representing 38 First Nations in British Columbia (BC), invested approximately $736 million in our Westcoast Energy Inc. BC natural gas pipeline system, resulting in the First Nations Partnership owning a 12.5% interest in that system.
Subsequent to the First Nations Partnership's investment, we will hold an 87.5% controlling interest in these assets, which are included in our Gas Transmission segment, and continue to manage and operate the pipeline system.
GAS TRANSMISSION RATE PROCEEDINGS
Algonquin
Algonquin Gas Transmission, LLC (Algonquin) filed a rate case on May 30, 2024 and a settlement in principle was reached with customers in December 2024. A Stipulation and Agreement was approved by the Federal Energy Regulatory Commission (FERC) on April 25, 2025 with rates effective December 1, 2024.
Maritimes & Northeast Pipeline
Maritimes & Northeast Pipeline US filed a rate case on May 30, 2024 and a settlement in principle was reached with customers in December 2024. A Stipulation and Agreement was approved by the FERC on April 25, 2025 with rates effective January 1, 2025.
East Tennessee
East Tennessee Natural Gas, LLC (East Tennessee) filed a rate case on April 29, 2025. On May 29, 2025, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In compliance with the order, East Tennessee intends to make a motion filing to implement the rates to be effective November 1, 2025, subject to refund. East Tennessee expects settlement discussions with shippers to commence in the third quarter of 2025.
40
Vector
On September 19, 2024, the FERC initiated a review of Vector Pipeline L.P.’s (Vector) rates. Vector subsequently filed a rate case on May 30, 2025. On June 30, 2025, the FERC issued an order accepting and suspending tariff records filed in this rate case, subject to refund and establishing hearing procedures. In compliance with the order, Vector placed the rate reductions into effect on July 1, 2025. Additionally, on July 1, 2025, the chief administrative law judge issued an order consolidating Vector’s outstanding review of rates initiated by the FERC in 2024 with Vector’s May 30, 2025 rate case filing. Vector expects settlement discussions with shippers to commence in the third quarter of 2025.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
Enbridge Gas Ontario
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 incentive rate-setting (Price Cap IR) 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 addresses cost allocation and the harmonization of rates and rate classes and is anticipated to be completed in 2025.
In December 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). Enbridge Gas Ontario initiated various appeals of select aspects of the Phase 1 Decision, including a review motion with the OEB that concluded in April 2025 with the OEB denying its motion to vary the Phase 1 Decision which disallowed recoverability of certain undepreciated capital. Enbridge Gas Ontario continues to pursue appeal and judicial review applications to the Ontario Divisional Court that challenge some of the OEB’s Phase 1 findings with respect to depreciation, equity thickness and undepreciated capital. These proceedings are at the stage of written submissions and no hearing dates have been scheduled yet.
In November 2024, the OEB issued its Decision approving the Phase 2 Partial Settlement Proposal (Phase 2 Settlement). The Phase 2 Settlement establishes a Price Cap IR mechanism to be used for determining rates for 2025-2028. The Price Cap IR mechanism includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas Ontario to share equally with customers any earnings in excess of 100 basis points over the allowed return on equity (ROE), and 90% of any earnings in excess of 300 basis points over the allowed ROE. Issues not addressed as part of the Phase 2 Settlement proceeded to hearing in December 2024 and the OEB rendered its Decision in May 2025. Rates effective January 1, 2025 were set using the Price Cap IR mechanism.
In March 2025, the OEB released its decision in the Generic Cost of Capital proceeding. The OEB determined that Enbridge Gas Ontario's equity thickness would remain at 38% as approved in the Phase 1 Decision. The OEB also revised the formula for calculating ROE by reducing flotation costs by 25 basis points. The new formula will be applicable to Enbridge Gas Ontario at its next rebasing expected in 2029. Until then, rates will continue to reflect the embedded 2024 ROE formula value of 9.21%.
Enbridge Gas Ohio
In October 2023, Enbridge Gas Ohio filed its first rates application with the Public Utilities Commission of Ohio (Ohio Commission) since 2007 proposing a base rate annual revenue increase (compared to current rates) of US$212 million, to be effective January 2025. The base rate increase was proposed to recover the significant investment in distribution infrastructure for the benefit of Ohio customers, including an ROE of 10.40%. The application was subsequently amended to reduce the annual revenue increase from US$212 million to US$60 million.
41
In June 2025, the Ohio Commission issued an order approving an annual revenue decrease (compared to current rates) of US$26.3 million, including an ROE of 9.79%, an increase to the equity thickness to 51.9%, and the continuation of the Pipeline Infrastructure Replacement and Capital Expenditure Programs. The order also resulted in disallowances of $330 million (US$240 million) including regulatory assets related to pension balances of $280 million (US$204 million) and other disallowances of $50 million (US$36 million) and the subsequent impairments recognized for the period ended June 30, 2025.
In July 2025, Enbridge Gas Ohio filed an application for rehearing regarding certain aspects of the order and continues to assess legal options.
Enbridge Gas North Carolina
On April 1, 2025, Enbridge Gas North Carolina filed its first rates application since 2021 with the North Carolina Utilities Commission. This rate case aims to reflect the costs of delivering natural gas to customers and recover investments in infrastructure to support service reliability and customer growth. Enbridge Gas North Carolina is proposing a 12% increase to its residential natural gas rates.
Enbridge Gas Utah
On May 1, 2025, Enbridge Gas Utah filed its first rates application since 2022 with the Utah Public Service Commission. This rate case aims to reflect the costs of delivering natural gas to customers and recover investments in infrastructure to support service reliability and customer growth. Enbridge Gas Utah is proposing a 9.5% increase to its residential natural gas rates.
FINANCING UPDATE
On February 25, 2025, Enbridge Pipelines Inc. redeemed below par all of the outstanding $100 million 4.10% medium-term notes that carried an original maturity date in July 2112.
In February 2025, we closed a five-tranche offering consisting of three-year floating medium-term notes, three-year medium-term notes, five-year medium-term notes, 10-year medium-term notes and re-opened existing 30-year medium-term notes for an aggregate principal amount of $2.8 billion, which mature in February 2028, February 2028, February 2030, February 2035, and August 2054, respectively.
In June 2025, Enbridge Gas Ohio closed a two-tranche offering consisting of 10-year senior notes and 30-year senior notes for an aggregate principal amount of US$500 million, which mature in June 2035 and June 2055, respectively.
In June 2025, we closed a four-tranche offering consisting of three-year senior notes, five-year senior notes, 10-year senior notes and re-opened existing 30-year senior notes for an aggregate principal of US$2.3 billion, which mature in June 2028, June 2030, June 2035 and April 2054, respectively.
In July 2025, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2027, which includes a one-year term out provision from July 2026. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2030. Further, we extended the maturity dates of our three-year credit facilities to July 2028.
In July 2025, Enbridge Gas Ontario and Enbridge Pipelines Inc. extended the maturity dates of their $2.5 billion and $2.0 billion 364-day extendible credit facilities, respectively, to July 2027, which includes a one-year term out provision from July 2026.
On July 28, 2025, Enbridge Energy Partners, L.P. (EEP) redeemed at par all of the outstanding US$500 million 5.88% senior notes that carried an original maturity date in October 2025.
These financing activities, in combination with the financing activities executed in 2024, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects and other operating working capital requirements without requiring access to the capital markets for the next 12 months, should market access be restricted or pricing be unattractive. Refer to
Liquidity and Capital Resources
.
42
As at June 30, 2025, after adjusting for the impact of floating-to-fixed interest rate swap hedges, approximately 7% of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements -
Note 10. Risk Management and Financial Instruments
for more information on our interest rate hedging program.
RESULTS OF OPERATIONS
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization
1
Liquids Pipelines
2,331
2,450
4,924
4,854
Gas Transmission
1,442
2,095
2,915
3,360
Gas Distribution and Storage
510
567
2,110
1,332
Renewable Power Generation
109
138
332
395
Eliminations and Other
1,167
(155
)
1,207
(797
)
Earnings before interest, income taxes and depreciation and amortization
1
5,559
5,095
11,488
9,144
Depreciation and amortization
(1,391
)
(1,273
)
(2,799
)
(2,466
)
Interest expense
(1,181
)
(1,082
)
(2,515
)
(1,987
)
Income tax expense
(666
)
(739
)
(1,363
)
(1,125
)
Earnings attributable to noncontrolling interests
(42
)
(58
)
(168
)
(111
)
Preference share dividends
(102
)
(95
)
(205
)
(188
)
Earnings attributable to common shareholders
2,177
1,848
4,438
3,267
Earnings per common share attributable to common shareholders
1.00
0.86
2.04
1.53
Diluted earnings per common share attributable to common shareholders
1.00
0.86
2.03
1.53
1
Non-GAAP financial measure. Refer to
Non-GAAP and Other Financial Measures
.
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
Three months ended June 30, 2025, compared with the three months ended June 30, 2024
Earnings attributable to common shareholders were positively impacted by $159 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•
a non-cash, net unrealized derivative fair value gain of $1.4 billion ($1.0 billion after-tax) in 2025, compared with a net unrealized loss of $208 million ($160 million after-tax) in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;
•
a net positive adjustment of $8 million ($6 million after-tax) in 2025 to the gas inventory at the Aitken Creek Gas Storage Facility (Aitken Creek), compared to a net negative adjustment of $29 million ($21 million after-tax) in 2024; and
•
the absence in 2025 of 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 a joint venture with WhiteWater/I Squared Capital and MPLX LP (the Whistler Parent JV); partially offset by
•
the absence in 2025 of a gain on sale of $1.1 billion ($765 million after-tax) on the disposition of interests in the Alliance Pipeline, Aux Sable (including a 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a 50.0% interest in Aux Sable Canada LP) and NRGreen Power Limited Partnership (NRGreen);
43
•
an impairment of $330 million ($261 million after-tax) of certain rate-regulated assets related to pension and other disallowances as a result of the Ohio Commission's June 2025 order related to Enbridge Gas Ohio's rate case;
•
the absence in 2025 of a deferred tax recovery of $82 million due to change in state apportionment as a result of the Acquisitions; and
•
$42 million ($33 million after-tax) of integration costs incurred related to the Acquisitions in 2025, as compared to $16 million ($13 million after-tax) of integration and transaction costs in 2024.
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 $170 million increase in earnings attributable to common shareholders is primarily explained by:
•
full-quarter contributions from the acquisitions of Enbridge Gas Utah and Enbridge Gas North Carolina in our Gas Distribution and Storage segment;
•
higher contributions from our Gas Transmission segment primarily due to favorable contracting and lower operating costs on our US Gas Transmission assets and recognition of increased revenue attributable to Algonquin and Texas Eastern rate case settlements;
•
lower income tax expense mainly driven by higher investment tax credits; and
•
positive earnings impact in Enbridge Gas Ontario in our Gas Distribution and Storage segment due to higher storage optimization and pricing, higher distribution margin, and colder weather in 2025 compared to a negative impact in 2024.
The factors above were partially offset by:
•
higher realized foreign exchange losses on hedge settlements in Eliminations and Other;
•
higher depreciation and amortization expense mainly driven by a full quarter ownership of the acquired US Gas Utilities;
•
higher interest expense primarily due to higher average debt balances principal outstanding; and
•
lower contributions from the Gulf Coast and Mid-Continent System in our Liquids Pipelines segment due to lower spot volumes on the Flanagan South and Spearhead Pipelines.
Six months ended June 30, 2025, compared with the six months ended June 30, 2024
Earnings attributable to common shareholders were positively impacted by $714 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•
a non-cash, net unrealized derivative fair value gain of $1.3 billion ($1.0 billion after-tax) in 2025, compared with a net unrealized loss of $885 million ($678 million after-tax) in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;
•
the absence in 2025 of severance costs of $105 million ($79 million after-tax) as a result of a workforce reduction in February 2024; and
•
equity earnings of $87 million ($65 million after-tax) from our investment in DCP Midstream, LP (DCP), as a result of DCP's gain on disposition from certain pipeline assets; partially offset by
•
the absence in 2025 of a gain on sale of $1.1 billion ($765 million after-tax) on the disposition of interests in the Alliance Pipeline, Aux Sable and NRGreen;
•
an impairment of $330 million ($261 million after-tax) of certain rate-regulated assets related to pension and other disallowances as a result of the Ohio Commission's June 2025 order related to Enbridge Gas Ohio's rate case; and
44
•
the absence in 2025 of a deferred tax recovery of $82 million due to change in state apportionment as a result of the Acquisitions.
After taking into consideration the factors above, the remaining $457 million increase in earnings attributable to common shareholders is primarily explained by:
•
two full-quarter contributions from the acquisitions of Enbridge Gas Ohio, Enbridge Gas Utah, and Enbridge Gas North Carolina in our Gas Distribution and Storage segment;
•
positive earnings impact in Enbridge Gas Ontario due to colder weather in 2025 compared to a negative impact in 2024, higher storage optimization and pricing, and higher distribution margin in our Gas Distribution and Storage segment;
•
higher contributions from our Liquids Pipelines segment due to equity earnings related to a litigation settlement and higher contributions from Mainline System due to higher tolls and operational efficiencies; and
•
higher contributions from our Gas Transmission segment primarily due to favorable contracting in our US Gas Transmission assets, and the recognition of increased revenue attributable to Algonquin and Texas Eastern rate case settlements.
The factors above were partially offset by:
•
higher depreciation and amortization expense mainly driven by two full quarters' ownership of the acquired US Gas Utilities;
•
higher interest expense primarily due to higher average debt balances principal outstanding;
•
lower contributions from the Gulf Coast and Mid-Continent System in our Liquids Pipelines segment due to lower spot volumes on the Flanagan South and Spearhead Pipelines; and
•
lower contributions from the Gas Transmission segment due to the sale of our interests in Alliance Pipeline and Aux Sable in April 2024.
BUSINESS SEGMENTS
LIQUIDS PIPELINES
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization
2,331
2,450
4,924
4,854
Three months ended June 30, 2025, compared with the three months ended June 30, 2024
EBITDA was negatively impacted by $119 million, primarily explained by the following significant business factors:
•
lower contributions from the Gulf Coast and Mid-Continent System due to lower spot volumes on the Flanagan South Pipeline and Spearhead Pipeline; and
•
lower contributions from the Bakken System due to lower volumes.
Six months ended June 30, 2025, compared with the six months ended June 30, 2024
EBITDA was positively impacted by $29 million due to certain infrequent or other non-operating factors, primarily explained by:
•
a non-cash, net unrealized gain of $38 million in 2025, compared with a net unrealized loss of $6 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks; partially offset by
•
a net negative adjustment to crude oil inventory of $6 million in 2025, compared with a net positive adjustment of $15 million in 2024.
45
After taking into consideration the factors above, the remaining $41 million increase is primarily explained by the following significant business factors:
•
equity earnings attributable to a litigation settlement;
•
higher Mainline System contributions as a result of annual escalators and surcharge effective July 1, 2024 and lower power costs from operational efficiencies and lower mill rates, net of lower demand; and
•
the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to the same period in 2024; partially offset by
•
lower contributions from the Gulf Coast and Mid-Continent System due to lower spot volumes on the Flanagan South Pipeline and Spearhead Pipeline; and
•
lower contributions from the Bakken System due to lower volumes.
GAS TRANSMISSION
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization
1,442
2,095
2,915
3,360
Three months ended June 30, 2025, compared with the three months ended June 30, 2024
EBITDA was negatively impacted by $955 million due to certain infrequent or other non-operating factors, primarily explained by:
•
the absence in 2025 of a gain on sale of $1.1 billion on the disposition of interests in the Alliance Pipeline and Aux Sable; partially offset by
•
the absence in 2024 of a non-cash, net unrealized gain of $40 million, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks;
•
a net positive adjustment of $8 million to the gas inventory at Aitken Creek in 2025, compared to a net negative adjustment of $29 million in 2024; and
•
the absence in 2025 of 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 $302 million increase is primarily explained by the following significant business factors:
•
favorable contracting and lower operating costs on our US Gas Transmission assets;
•
the recognition of increased revenues attributable to the Algonquin and Texas Eastern rate case settlements;
•
contributions from the acquisition of equity interests in the Whistler Parent JV and in the Delaware Basin Residue in the second and fourth quarters of 2024, respectively;
•
contributions from the Texas Eastern Venice Extension project since service commencement in late 2024;
•
higher earnings from our investment in DCP; and
•
the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to the same period in 2024.
Six months ended June 30, 2025, compared with the six months ended June 30, 2024
EBITDA was negatively impacted by $912 million due to certain infrequent or other non-operating factors, primarily explained by:
•
the absence in 2025 of a gain on sale of $1.1 billion on the disposition of interests in the Alliance Pipeline and Aux Sable; partially offset by
46
•
equity earnings of $87 million from our investment in DCP, as a result of DCP's gain on disposition from certain pipeline assets;
•
a net positive adjustment of $23 million in 2025 to the gas inventory at Aitken Creek compared to a net negative adjustment of $29 million in 2024; and
•
the absence in 2025 of 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 $467 million increase is primarily explained by the following significant business factors:
•
the recognition of increased revenues attributable to the Algonquin and Texas Eastern rate case settlements;
•
favorable contracting on our US Gas Transmission assets;
•
contributions from the acquisition of equity interests in the Whistler Parent JV and in the Delaware Basin Residue in the second and fourth quarters of 2024, respectively;
•
contributions from the Texas Eastern Venice Extension project since service commencement in late 2024;
•
higher revenues at Aitken Creek;
•
higher earnings from our investment in DCP; and
•
the favorable effect of translating US dollar earnings at a higher average exchange rate in 2025, compared to the same period in 2024; partially offset by
•
the absence of contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments in April 2024.
GAS DISTRIBUTION AND STORAGE
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization
510
567
2,110
1,332
Three months ended June 30, 2025, compared with the three months ended June 30, 2024
EBITDA was negatively impacted by $330 million due to an impairment of certain rate-regulated assets related to pension and other disallowances as a result of the Ohio Commission's June 2025 order related to Enbridge Gas Ohio's rate case.
The remaining $273 million increase is primarily explained by the following significant business factors:
•
full-quarter contributions from the acquisitions of Enbridge Gas Utah and Enbridge Gas North Carolina;
•
higher storage optimization and pricing at Enbridge Gas Ontario;
•
higher distribution margin resulting from increases in rates and customer base at Enbridge Gas Ontario; and
•
when compared with the normal forecast embedded in rates, the positive impact of weather on EBITDA for Enbridge Gas Ontario was approximately $10 million in 2025, compared to a negative impact of approximately $28 million in the same period of 2024.
Six months ended June 30, 2025, compared with the six months ended June 30, 2024
EBITDA was negatively impacted by $330 million due to an impairment of certain rate-regulated assets related to pension and other disallowances as a result of the Ohio Commission's June 2025 order related to Enbridge Gas Ohio's rate case.
47
The remaining $1.1 billion increase is primarily explained by the following significant business factors:
•
two full quarters of contributions from the acquired US Gas Utilities including Enbridge Gas Ohio, Enbridge Gas Utah and Enbridge Gas North Carolina;
•
when compared with the normal forecast embedded in rates, the positive impact of weather on EBITDA for Enbridge Gas Ontario was approximately $19 million in 2025 compared to a negative impact of approximately $106 million in the same period of 2024;
•
lower operating and administrative costs primarily due to lower employee related costs at Enbridge Gas Ontario;
•
higher storage optimization and pricing at Enbridge Gas Ontario; and
•
higher distribution margin resulting from increases in rates and customer base at Enbridge Gas Ontario.
RENEWABLE POWER GENERATION
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization
109
138
332
395
Three months ended June 30, 2025, compared with the three months ended June 30, 2024
EBITDA was negatively impacted by $2 million due to certain infrequent or other non-operating factors, primarily explained by:
•
the absence in 2025 of a gain on sale of $29 million related to the disposition of our interest in NRGreen; partially offset by
•
a non-cash, net unrealized gain of $2 million in 2025, compared with a net unrealized loss of $25 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.
The remaining $27 million decrease is primarily explained by:
•
lower fees earned in 2025 on certain wind development contracts; and
•
lower contributions from European offshore wind facilities.
Six months ended June 30, 2025, compared with the six months ended June 30, 2024
EBITDA was positively impacted by $2 million due to certain infrequent or other non-operating factors, primarily explained by:
•
a $27 million gain on the disposition of our interest in East-West Tie Limited Partnership; and
•
a realized loss of $139 million, partially offset by a non-cash, net unrealized gain of $108 million in 2025, compared with a net unrealized loss of $36 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; partially offset by
•
the absence in 2025 of a gain on sale of $29 million related to the disposition of our interest in NRGreen.
The remaining $65 million decrease is primarily explained by lower contributions from European offshore wind facilities, including weaker wind resources.
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ELIMINATIONS AND OTHER
Three months ended
June 30,
Six months ended
June 30,
2025
2024
2025
2024
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization
1,167
(155
)
1,207
(797
)
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, 2025, compared with the three months ended June 30, 2024
EBITDA was positively impacted by $1.4 billion, primarily due to certain infrequent or non-operating factors, explained by:
•
a non-cash, net unrealized gain of $1.3 billion in 2025, compared with a net unrealized loss of $229 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk; partially offset by
•
$42 million of integration costs incurred related to the Acquisitions in 2025, compared to $16 million of integration and transaction costs in 2024.
After taking into consideration the non-operating factors above, the remaining $119 million decrease in EBITDA is primarily explained by higher realized foreign exchange losses on hedge settlements in 2025.
Six months ended June 30, 2025, compared with the six months ended June 30, 2024
EBITDA was positively impacted by $2.4 billion, primarily due to certain infrequent or non-operating factors, explained by:
•
a non-cash, net unrealized gain of $1.4 billion in 2025, compared with a net unrealized loss of $951 million in 2024, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk; and
•
the absence in 2025 of severance costs of $105 million as a result of a workforce reduction in February 2024; partially offset by
•
$63 million of integration costs incurred related to the Acquisitions in 2025, compared to $30 million of integration and transaction costs in 2024.
After taking into consideration the non-operating factors above, the remaining $368 million decrease in EBITDA is primarily explained by:
•
higher realized foreign exchange losses on hedge settlements in 2025; and
•
lower investment income in 2025 compared to 2024 from investing cash sources from the pre-funding of the Acquisitions.
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GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS
The following table summarizes the status of our material commercially secured projects, organized by business segment:
Enbridge's
Ownership
Interest
Estimated
Capital
Cost
1
Expenditures
to Date
2
Status
2
Expected
In-Service
Date
(Canadian dollars, unless stated otherwise)
GAS TRANSMISSION
1.
Texas Eastern Modernization
100%
US$0.4 billion
US$191 million
Under construction
2025 - 2026
2.
T-North Expansion (Aspen Point)
100%
$1.2 billion
$459 million
Under construction
2026
3.
Tennessee Ridgeline Expansion
100%
US$1.1 billion
US$327 million
Pre-construction
2026
4.
Woodfibre LNG
3
30%
US$2.9 billion
US$1.1 billion
Under construction
2027
5.
T-South Expansion (Sunrise)
100%
$4.0 billion
$317 million
Pre-construction
2028
No significant
T-North Expansion
expenditures to
Pre-
6.
(Birch Grove)
100%
$0.4 billion
date
construction
2028
7.
Canyon System Pipelines
100%
US$0.7 billion
US$29 million
Pre-construction
2029
GAS DISTRIBUTION AND STORAGE
8.
Moriah Energy Center
4
100%
US$0.6 billion
US$300 million
Under construction
2027
9.
T-15 Reliability Project
4,5
100%
US$0.7 billion
US$27 million
Pre-construction
2027 - 2028
RENEWABLE POWER GENERATION
10.
Sequoia Solar
100%
US$1.1 billion
US$579 million
Under construction
2025 - 2026
11.
Clear Fork Solar
100%
US$0.9 billion
US$83 million
Pre-construction
2027
Calvados Offshore
$1.0 billion
$426 million
Under
12.
Wind
6
21.7%
(€0.6 billion)
(€294 million)
construction
2027
1
These 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.
2
Expenditures to date and status of the project are determined as at June 30, 2025.
3
Our expected investment is approximately US$2.3 billion, with the remainder financed through non-recourse project level debt.
4
Previously approved projects that were acquired by Enbridge through the acquisition of Public Service Company of North Carolina, Incorporated in the third quarter of 2024.
5
Includes approved capital costs for the second phase of the project which involves installation of additional compression to add capacity and is expected to go into service in 2028.
6
Our investment is approximately $0.3 billion, with the remainder financed through non-recourse project level debt.
A full description of each of our material projects is provided in our annual report on Form 10-K for the year ended December 31, 2024. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.
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GAS TRANSMISSION
•
T-North Expansion (Birch Grove) -
An expansion of our BC Pipeline system in northern BC that includes pipeline looping and ancillary station modifications to support 178 million cubic feet per day of additional capacity. The project is underpinned by a cost-of-service commercial model with a target in-service date in the third quarter of 2028. This expansion is driven by the need for natural gas producers in northeastern BC to access markets for their growing production, mainly from the prolific Montney formation.
•
Woodfibre LNG Commercial Update -
Enbridge and its partners have agreed to updated commercial terms for Woodfibre LNG. The preferred return is expected to be set closer to completion of construction, de-risking Enbridge's return on capital, and our share of capital costs has been updated.
RENEWABLE POWER GENERATION
•
Clear Fork Solar -
A 600-megawatt solar farm located near San Antonio, Texas, fully contracted under a long-term offtake agreement. The project has an expected in-service date in 2027.
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 $3.1 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 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.
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Credit Facilities and Liquidity
To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain 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, 2025:
Maturity
1
Total
Facilities
Draws
2
Available
(millions of Canadian dollars)
Enbridge Inc.
2026-2049
8,032
6,112
1,920
Enbridge (U.S.) Inc.
2026-2029
10,259
3,781
6,478
Enbridge Pipelines Inc.
2026
2,000
441
1,559
Enbridge Gas Inc.
2026
2,500
915
1,585
Total committed credit facilities
22,791
11,249
11,542
1
Maturity date is inclusive of the one-year term out option for certain credit facilities.
2
Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
In July 2025, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2027, which includes a one-year term out provision from July 2026. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2030. Further, we extended the maturity dates of our three-year credit facilities to July 2028.
In July 2025, Enbridge Gas Ontario and Enbridge Pipelines Inc. extended the maturity dates of their $2.5 billion and $2.0 billion 364-day extendible credit facilities, respectively, to July 2027, which includes a one-year term out provision from July 2026.
In addition to the committed credit facilities noted above, we maintain $1.5 billion of uncommitted demand letter of credit facilities, of which $932 million was unutilized as at June 30, 2025. As at December 31, 2024, we had $1.4 billion of uncommitted demand letter of credit facilities, of which $931 million was unutilized.
As at June 30, 2025, our net available liquidity totaled $12.7 billion (December 31, 2024 - $14.4 billion), consisting of available credit facilities of $11.5 billion (December 31, 2024 - $12.6 billion) and unrestricted cash and cash equivalents of $1.2 billion (December 31, 2024 - $1.8 billion) as reported in the Consolidated Statements of Financial Position.
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at June 30, 2025, we were in compliance with all such debt covenant provisions.
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LONG-TERM DEBT ISSUANCES
During the six months ended June 30, 2025, we completed the following long-term debt issuances totaling $2.8 billion and US$2.8 billion:
Company
Issue Date
Principal
Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
February 2025
Floating rate medium-term notes due February 2028
1
$400
February 2025
3.55%
medium-term notes due February 2028
$300
February 2025
3.90%
medium-term notes due February 2030
$800
February 2025
4.56%
medium-term notes due February 2035
$700
February 2025
5.32%
medium-term notes due August 2054
$600
June 2025
4.60%
senior notes due June 2028
US$400
June 2025
4.90%
senior notes due June 2030
US$600
June 2025
5.55%
senior notes due June 2035
US$900
June 2025
5.95%
senior notes due April 2054
US$350
The East Ohio Gas Company
June 2025
5.68%
senior notes due June 2035
US$250
June 2025
6.32%
senior notes due June 2055
US$250
1
Notes carry an interest rate set to equal the Canadian Overnight Repo Rate Average plus a margin of 85 basis points.
LONG-TERM DEBT REPAYMENTS
During the six months ended June 30, 2025, we completed the following long-term debt repayments totaling US$2.5 billion, $661 million and and €21 million:
Company
Repayment Date
Principal
Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
January 2025
2.50%
senior notes
US$500
February 2025
2.50%
senior notes
US$500
June 2025
2.44%
medium-term notes
$550
Enbridge Pipelines (Southern Lights) L.L.C.
June 2025
3.98%
senior notes
US$47
Enbridge Pipelines Inc.
February 2025
4.10%
medium-term notes
1
$100
Enbridge Southern Lights LP
June 2025
4.01%
senior notes
$11
Spectra Energy Partners, LP
March 2025
3.50%
senior notes
US$500
Blauracke GMBH
April 2025
2.10%
senior notes
€21
Enbridge Holdings (Tomorrow RNG), LLC
January 2025
4.97%
senior notes
US$309
January 2025
4.97%
senior notes
US$85
January 2025
4.97%
senior notes
US$19
The East Ohio Gas Company
June 2025
1.30%
senior notes
US$500
1
The notes carried an original maturity date in July 2112.
On July 28, 2025, EEP redeemed at par all of the outstanding US$500 million 5.88% senior notes that carried an original maturity date in October 2025.
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Cash flow growth, 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 $83 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, 2025 and December 31, 2024, we had negative working capital positions of $577 million and $2.9 billion, respectively. During the six months ended June 30, 2025, the major contributing factor to the negative working capital position was due to settlement of current liabilities, while during the year ended December 31, 2024, the major contributing factor to the negative working capital position was the current liabilities associated with our growth capital program.
SOURCES AND USES OF CASH
Six months ended
June 30,
2025
2024
(millions of Canadian dollars)
Operating activities
6,291
5,965
Investing activities
(4,648
)
(11,230
)
Financing activities
(2,166
)
2,787
Effect of translation of foreign denominated cash and cash equivalents and restricted cash
(55
)
192
Net change in cash and cash equivalents and restricted cash
(578
)
(2,286
)
Significant sources and uses of cash for the six months ended June 30, 2025 and 2024 are summarized below:
Operating Activities
The primary factors impacting cash provided by operating activities period-over-period include changes in our operating assets and liabilities in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments and cash receipts and payments generally. Cash provided by operating activities is also impacted by changes in earnings and certain infrequent or other non-operating factors, as discussed in
Results of Operations
, as well as Distributions from equity investments.
Investing Activities
Cash used in investing activities includes capital expenditures to execute our capital program, which is further described in
Growth Projects - Commercially Secured Projects
. The timing of project approval, construction and in-service dates impacts the timing of cash requirements. Cash used in investing activities is also impacted by acquisitions, dispositions and changes in contributions to, and distributions from, our equity investments. The decrease in cash used in investing activities period-over-period was primarily due to the acquisitions of EOG, Questar and Tomorrow RNG in 2024; partially offset by the absence of proceeds received from the disposition of our interests in the Alliance Pipeline, Aux Sable and NRGreen in 2024 and higher capital expenditures in 2025.
54
Financing Activities
Cash used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, share redemptions and common share repurchases under our normal course issuer bid. Cash used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the increase in cash used in financing activities period-over-period primarily include:
•
net commercial paper and credit facility repayments in 2025 when compared to net draws during the same period in 2024; and
•
absence of the at-the-market equity issuance program in 2025, which resulted in the issuance of 51,298,629 common shares for aggregate net proceeds of $2.5 billion in 2024.
The factors above were partially offset by net draws of short-term borrowings in 2025 when compared to net repayments during the same period in 2024.
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 Notes
1
EEP Notes
2
3.38% Senior Notes due 2026
5.88% Notes due 2025
5.95% Senior Notes due 2043
5.95% Notes due 2033
4.50% Senior Notes due 2045
6.30% Notes due 2034
7.50% Notes due 2038
5.50% Notes due 2040
7.38% Notes due 2045
1
As at June 30, 2025, the aggregate outstanding principal amount of SEP notes was approximately US$1.7 billion.
2
As at June 30, 2025, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.
55
Enbridge Notes under Guarantees
USD Denominated
1
CAD Denominated
2
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
3.55% Senior Notes due 2028
4.60% Senior Notes due 2028
Floating Rate Senior Notes due 2028
6.00% Senior Notes due 2028
2.99% Senior Notes due 2029
3.13% Senior Notes due 2029
7.22% Senior Notes due 2030
5.30% Senior Notes due 2029
4.21% Senior Notes due 2030
4.90% Senior Notes due 2030
3.90% Senior Notes due 2030
6.20% Senior Notes due 2030
7.20% Senior Notes due 2032
2.50% Sustainability-Linked Senior Notes due 2033
6.10% Sustainability-Linked Senior Notes due 2032
5.70% Sustainability-Linked Senior Notes due 2033
3.10% Sustainability-Linked Senior Notes due 2033
5.63% Senior Notes due 2034
5.36% Sustainability-Linked Senior Notes due 2033
5.55% Senior Notes due 2035
4.73% Senior Notes due 2034
4.50% Senior Notes due 2044
5.57% Senior Notes due 2035
5.50% Senior Notes due 2046
4.56% Senior Notes due 2035
4.00% Senior Notes due 2049
5.75% Senior Notes due 2039
3.40% Senior Notes due 2051
5.12% Senior Notes due 2040
6.70% Senior Notes due 2053
4.24% Senior Notes due 2042
5.95% Senior Notes due 2054
4.57% Senior Notes due 2044
4.87% Senior Notes due 2044
4.10% Senior Notes due 2051
6.51% Senior Notes due 2052
5.76% Senior Notes due 2053
5.32% Senior Notes due 2054
4.56% Senior Notes due 2064
1
As at June 30, 2025, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$18.3 billion.
2
As at June 30, 2025, the aggregate outstanding principal amount of the Enbridge Canadian dollar-denominated notes was approximately $14.5 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.
56
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,
2025
(millions of Canadian dollars)
Operating income
3
Earnings
1,682
Earnings attributable to common shareholders
1,477
Summarized Combined Statements of Financial Position
June 30,
2025
December 31,
2024
(millions of Canadian dollars)
Cash and cash equivalents
1,423
2,000
Accounts receivable from affiliates
3,629
3,901
Short-term loans receivable from affiliates
5,867
3,892
Other current assets
523
499
Long-term loans receivable from affiliates
44,483
54,416
Other long-term assets
1,840
2,139
Accounts payable to affiliates
1,987
2,252
Short-term loans payable to affiliates
1,634
1,188
Trade payables and accrued liabilities
382
661
Other current liabilities
1,942
8,047
Long-term loans payable to affiliates
31,042
36,576
Other long-term liabilities
66,612
62,642
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.
57
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 initiated legal action in the Michigan Ingham County Circuit Court (Michigan Circuit Court) seeking to invalidate the 1953 easement that authorizes the operation of Enbridge’s Line 5 pipeline in the Straits of Mackinac. The Attorney General’s case was later moved to U.S. federal court in December 2021, following a November 16, 2021 ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force the shutdown of Line 5 raised important federal issues that should be heard in federal court.
In June 2024, the US Court of Appeals for the Sixth Circuit (Sixth Circuit) ruled that the case should proceed in state court. Enbridge’s request for a rehearing was denied in August 2024. Oral argument on long-standing cross motions for summary disposition was held in January 2025 in the Michigan Circuit Court. We anticipate a decision on the motions for summary disposition in 2025.
Separately, in January 2025, Enbridge petitioned the US Supreme Court to review the Sixth Circuit’s decision. The Court granted the petition in June 2025 and is expected to hear the case in late 2025, with a decision anticipated in the first half of 2026. In the interim, Enbridge requested that the Michigan Circuit Court pause proceedings pending the US Supreme Court’s ruling.
In parallel, the US Army Corps of Engineers (Army Corps) announced in April 2025 that the Line 5 Tunnel Project qualifies for review under emergency and special processing procedures, potentially expediting federal permitting.
Enbridge Lawsuit
On November 24, 2020, Enbridge filed in the US District Court a complaint for declaratory and injunctive relief, seeking to prevent the Governor of Michigan and Director of the Michigan Department of Natural Resources (Michigan State Officials) from interfering with the continued operation of Line 5. The Government of Canada has reiterated its support for the pipeline, emphasizing the relevance of the 1977 Transit Pipelines Treaty and the matter’s importance to Canada. The case remains in federal court.
58
In January 2022, Michigan State Officials moved to dismiss the case, while Enbridge filed for summary judgment. On July 5, 2024, the US District Court denied the state’s motion to dismiss, prompting an immediate appeal to the Sixth Circuit. The US District Court stayed the case pending the outcome of the appeal.
On April 23, 2025, the Sixth Circuit affirmed the US District Court’s ruling and a petition for rehearing en banc was denied on June 16, 2025. On June 24, 2025, the case was administratively transferred back to the US District Court and Michigan State Officials filed their Answer to Enbridge’s complaint.
A case management order was issued on July 14, 2025, setting out a briefing schedule for Enbridge’s summary judgment motion and the state’s motion to abstain. Briefing is expected to conclude by September 22, 2025.
DAKOTA ACCESS PIPELINE
We hold an effective 27.6% interest in the Bakken Pipeline System, which includes the Dakota Access Pipeline (DAPL). The Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court for the District of Columbia (the District Court) challenging the Army Corps’ easement for DAPL, citing concerns over the adequacy of the Army Corps' environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018. In 2017 and again in 2020, the District Court found deficiencies in the Army Corps’ environmental assessments and ordered the preparation of a full Environmental Impact Statement (EIS).
In July 2020, the District Court vacated the easement and ordered the pipeline shut down, but that order was stayed by the US Court of Appeals for the District of Columbia. In January 2021, the US Court of Appeals upheld the requirement for an EIS and confirmed the easement’s vacatur, though it ruled that DAPL could continue operating absent an injunction. The US Supreme Court declined to review the case, and the Army Corps indicated it would not seek to halt operations during the review process.
On September 8, 2023, the Army Corps released a draft EIS evaluating five alternatives, including continued operation, shutdown, rerouting, and removal of the pipeline. No preferred alternative was identified. The public comment period closed on December 13, 2023, and a final EIS is expected in 2025. DAPL remains operational during this process.
Separately, on October 15, 2024, the Standing Rock Sioux Tribe filed a new complaint in the District Court seeking to permanently enjoin DAPL’s operation, alleging the Army Corps is unlawfully allowing continued operations without a valid easement or compliant Facility Response Plan. Dakota Access, LLC and 13 states intervened in support of continued operations. On March 28, 2025, the District Court dismissed the complaint. The Tribe filed a notice of appeal on May 27, 2025. The appeal process is expected to take 6-12 months.
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.
CHANGES IN ACCOUNTING POLICIES
Refer to Part I.
Item 1. Financial Statements - Note 2. Changes in Accounting Policies.
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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, 2024. 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 designed to provide reasonable assurance that information required to be disclosed by us in the reports filed with, or submitted to, securities regulatory authorities, including under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified under Canadian and US securities law. 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, 2025, 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, 2025 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
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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, 2024, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors, other than as set forth below.
The effects of US, Canadian and other governments' policies on tariffs and trade relations remain uncertain and could significantly adversely impact our business, operations or financial results.
The announcement and imposition of tariffs by the US, together with potential, announced or implemented retaliatory tariffs by other governments on imports from the US, and other potential measures, including duties, fees, economic sanctions or other trade measures, as well as the potential impacts of these tariffs and trade measures, present significant risks to our business operations and financial results. Tariffs announced by the US (which are in addition to any pre-existing tariffs) include, among others:
•
March 4, 2025: 25% tariff on Canadian goods exports and 10% on certain Canadian energy exports that are non-compliant under the United States-Mexico-Canada Agreement (USMCA);
•
March 12, 2025: 25% tariff on Canadian steel and aluminum products;
•
April 2, 2025: 10% tariff on product imports from almost all countries and individualized higher tariffs on imports from dozens of countries;
•
June 4, 2025: tariffs on Canadian steel and aluminum products were increased to 50%; and
•
July 31, 2025: 35% tariff on most Canadian goods exports, effective August 1, 2025, that are non-compliant under USMCA.
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Several of the US tariff announcements have been followed by announcements of limited exemptions and temporary pauses on implementation dates. In response to the US tariff announcements, certain governments have threatened or announced retaliatory measures against the US, including increased tariffs on US goods. For instance, effective March 13, 2025, the Canadian federal government imposed 25% tariffs on a list of products imported from the US. These announcements have led to significant uncertainty and market volatility during the first half of 2025. If maintained, such trade measures, the nature, extent and timing of which are uncertain, and the potential for escalation of trade disputes, including retaliatory measures, could lead to, among other things, worsening of macroeconomic conditions, inflationary pressures, increased construction costs, costs to maintain our assets and other costs and expenses, as well as potential reductions in demand for Canadian energy. The measures also introduce uncertainty in North American energy and capital markets and have the potential to disrupt supply chains and access to capital markets and jeopardize our competitiveness. The US Government has also stated its interest in renegotiating and altering the USMCA, which could further impact the energy market and our business.
Any of the foregoing could significantly adversely impact our business, operations or financial results.
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).
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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.
Inline XBRL Instance Document-the instance document does not appear in the Interactive Data File as its XBRL tags are embedded within the Inline XBRL document
101.SCH
Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents
104
Cover page formatted as Inline XBRL and contained in Exhibit 101
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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 1, 2025
By:
/s/ Gregory L. Ebel
Gregory L. Ebel
President and Chief Executive Officer
(Principal Executive Officer)
Date:
August 1, 2025
By:
/s/ Patrick R. Murray
Patrick R. Murray
Executive Vice President and Chief Financial Officer
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