The accompanying notes are an integral part of these interim consolidated financial statements.
8
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine months ended September 30,
2024
2023
(unaudited; millions of Canadian dollars)
Operating activities
Earnings
5,013
4,490
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization
3,783
3,447
Deferred income tax expense
743
923
Unrealized derivative fair value loss/(gain), net (Note 10)
809
(270)
Income from equity investments
(1,664)
(1,338)
Distributions from equity investments
1,499
1,539
Gain on disposition of equity investments
(1,091)
—
Other
198
137
Changes in operating assets and liabilities
(352)
1,461
Net cash provided by operating activities
8,938
10,389
Investing activities
Capital expenditures
(4,165)
(3,284)
Long-term, restricted and other investments
(1,851)
(487)
Distributions from equity investments in excess of cumulative earnings
646
865
Additions to intangible assets
(157)
(165)
Acquisitions
(13,065)
(487)
Proceeds from disposition of equity investments
2,724
—
Net change in affiliate loans
2
86
Other
(49)
(31)
Net cash used in investing activities
(15,915)
(3,503)
Financing activities
Net change in short-term borrowings
528
(412)
Net change in commercial paper and credit facility draws
3,276
(9,855)
Debenture and term note issues, net of issue costs
8,614
9,611
Debenture and term note repayments
(5,615)
(2,881)
Contributions from noncontrolling interests
4
10
Distributions to noncontrolling interests
(246)
(281)
Common shares issued, net of issue costs
2,485
4,450
Common shares repurchased
—
(125)
Preference share dividends
(286)
(260)
Common share dividends
(5,885)
(5,390)
Net change in affiliate loans
99
69
Other
(31)
(82)
Net cash provided by/(used in) financing activities
2,943
(5,146)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash
151
—
Net change in cash and cash equivalents and restricted cash
(3,883)
1,740
Cash and cash equivalents and restricted cash at beginning of period
5,985
907
Cash and cash equivalents and restricted cash at end of period1
2,102
2,647
The accompanying notes are an integral part of these interim consolidated financial statements.
1 As at September 30, 2024, long-term restricted cash of $94 million (2023 - nil) was included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position.
9
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
September 30, 2024
December 31, 2023
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents
1,875
5,901
Restricted cash
133
84
Trade receivables and unbilled revenues
5,559
4,410
Other current assets
2,611
2,440
Accounts receivable from affiliates
109
85
Inventory
1,608
1,479
11,895
14,399
Property, plant and equipment, net
124,429
104,641
Long-term investments
18,295
16,793
Restricted long-term investments and cash
959
717
Deferred amounts and other assets
10,440
8,041
Intangible assets, net
4,403
3,537
Goodwill
34,858
31,848
Deferred income taxes
494
341
Total assets
205,773
180,317
Liabilities and equity
Current liabilities
Short-term borrowings
928
400
Trade payables and accrued liabilities
6,024
4,308
Other current liabilities
3,869
5,659
Accounts payable to affiliates
20
26
Interest payable
1,156
958
Current portion of long-term debt
7,053
6,084
19,050
17,435
Long-term debt
87,320
74,715
Other long-term liabilities
12,254
8,653
Deferred income taxes
18,371
15,031
136,995
115,834
Contingencies (Note 13)
Equity
Share capital
Preference shares
6,818
6,818
Common shares (2,178 and 2,125 outstanding at September 30, 2024 and December 31, 2023, respectively)
71,707
69,180
Additional paid-in capital
286
268
Deficit
(16,495)
(17,115)
Accumulated other comprehensive income (Note 9)
3,472
2,303
Total Enbridge Inc. shareholders’ equity
65,788
61,454
Noncontrolling interests
2,990
3,029
68,778
64,483
Total liabilities and equity
205,773
180,317
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, 2023. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2023. Amounts are stated in Canadian dollars unless otherwise noted.
Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as supply of and demand for crude oil and natural gas, and may not be indicative of annual results. Our current year earnings are also impacted by the effect of acquisitions and dispositions, if any, occurring during the remaining three months period ending December 31, 2023.
Certain comparative figures in our interim consolidated financial statements have been reclassified to conform to the current year's presentation.
2. CHANGES IN ACCOUNTING POLICIES
FUTURE ACCOUNTING POLICY CHANGES
Segment Reporting
Accounting Standards Update (ASU) 2023-07 was issued in November 2023 to improve reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and to require in interim period financial statements all disclosures about a reportable segment's profit or loss and assets that are currently required annually. The new ASU requires entities to disclose the title and position of the individual or the name of the group or committee identified as the chief operating decision maker (CODM). ASU 2023-07 is effective January 1, 2024, with interim period disclosure requirements effective after January 1, 2025 and should be applied retrospectively to all prior periods presented in the financial statements. We are currently assessing the impact of the new standard on our annual disclosures for the year ending December 31, 2024 and on our interim disclosures beginning in 2025.
Income Tax Disclosures
ASU 2023-09 was issued in December 2023 to improve income tax disclosures by requiring specified categories in the annual rate reconciliation that meet quantitative thresholds and further disaggregation on income taxes paid by jurisdiction. ASU 2023-09 is effective January 1, 2025 and should be applied prospectively, with retrospective application being permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.
11
3. REVENUE
REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
Three months ended September 30, 2024
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Eliminations and Other
Consolidated
(millions of Canadian dollars)
Transportation revenue
2,906
1,264
447
—
—
4,617
Storage and other revenue
65
143
125
—
—
333
Gas distribution revenue
—
—
710
—
—
710
Electricity revenue
—
—
—
36
—
36
Commodity sales
—
37
—
—
—
37
Total revenue from contracts with customers
2,971
1,444
1,282
36
—
5,733
Commodity sales
8,725
10
—
—
214
8,949
Other revenue1,2
79
27
(2)
96
—
200
Intersegment revenue
—
5
1
1
(7)
—
Total revenue
11,775
1,486
1,281
133
207
14,882
Three months ended September 30, 2023
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Eliminations and Other
Consolidated
(millions of Canadian dollars)
Transportation revenue
2,856
1,294
148
—
—
4,298
Storage and other revenue
65
118
83
—
—
266
Gas distribution revenue
—
—
528
—
—
528
Electricity revenue
—
—
—
79
—
79
Total revenue from contracts with customers
2,921
1,412
759
79
—
5,171
Commodity sales
4,373
—
—
—
279
4,652
Other revenue1,2
61
11
(9)
(42)
—
21
Intersegment revenue
—
—
1
3
(4)
—
Total revenue
7,355
1,423
751
40
275
9,844
12
Nine months ended September 30, 2024
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Eliminations and Other
Consolidated
(millions of Canadian dollars)
Transportation revenue
8,916
3,895
1,267
—
—
14,078
Storage and other revenue
192
416
351
—
—
959
Gas distribution revenue
—
—
3,149
—
—
3,149
Electricity revenue
—
—
—
137
—
137
Commodity sales
—
115
—
—
—
115
Total revenue from contracts with customers
9,108
4,426
4,767
137
—
18,438
Commodity sales
17,494
62
—
—
751
18,307
Other revenue1,2
213
46
24
228
—
511
Intersegment revenue
—
16
5
5
(26)
—
Total revenue
26,815
4,550
4,796
370
725
37,256
Nine months ended September 30, 2023
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Eliminations and Other
Consolidated
(millions of Canadian dollars)
Transportation revenue
8,800
3,968
593
—
—
13,361
Storage and other revenue
191
326
267
—
—
784
Gas distribution revenue
—
—
3,611
—
—
3,611
Electricity revenue
—
—
—
220
—
220
Total revenue from contracts with customers
8,991
4,294
4,471
220
—
17,976
Commodity sales
13,039
—
—
—
1,075
14,114
Other revenue1,2
170
29
(50)
112
—
261
Intersegment revenue
—
1
5
2
(8)
—
Total revenue
22,200
4,324
4,426
334
1,067
32,351
1Includes realized and unrealized gains and losses from our hedging program which for the three months ended September 30, 2024 were a net $54 million gain (2023 - $97 million loss) and for the nine months ended September 30, 2024 were a net $15 million gain (2023 - $149 million loss).
2Includes revenues from lease contracts for the three months ended September 30, 2024 and 2023 of $125 million and $107 million, respectively, and for the nine months ended September 30, 2024 and 2023 of $407 million and $387 million, respectively.
We disaggregate revenues into categories which represent our principal performance obligations within each business segment. These revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.
13
Contract Balances
Contract Receivables
Contract Assets
Contract Liabilities
(millions of Canadian dollars)
Balance as at September 30, 2024
2,563
325
2,738
Balance as at December 31, 2023
2,802
400
2,591
Contract receivables represent the amount of receivables derived from contracts with customers.
Contract assets represent the amount of revenues which has been recognized in advance of payments received for performance obligations we have fulfilled (or have partially fulfilled) and prior to the point in time at which our right to payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to receive the consideration becomes unconditional.
Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenues. Revenue recognized during the three and nine months ended September 30, 2024 included in contract liabilities at the beginning of the period were $62 million and $295 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and nine months ended September 30, 2024 were $201 million and $467 million, respectively.
Performance Obligations
There were no material revenues recognized in the three and nine months ended September 30, 2024 from performance obligations satisfied in previous periods.
Revenues to be Recognized from Unfulfilled Performance Obligations
Total revenues from performance obligations expected to be fulfilled in future periods is $57.7 billion, of which $2.1 billion and $8.4 billion are expected to be recognized during the remaining three months ending December 31, 2024 and the year ending December 31, 2025, respectively.
The revenues excluded from the amounts above based on optional exemptions available under Accounting Standards Codification (ASC) 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for revenues to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.
Mainline Tolling Agreement
On March 4, 2024, the Canada Energy Regulator (CER) approved the negotiated Mainline tolling settlement. The new tolls are finalized and were in effect on an interim basis on July 1, 2023, and the overall agreement is retroactively effective as of July 1, 2021 through to the end of 2028.
14
Recognition and Measurement of Revenues
Three months ended September 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
—
37
31
—
68
Revenues from products and services transferred over time1
2,971
1,407
1,251
36
5,665
Total revenue from contracts with customers
2,971
1,444
1,282
36
5,733
Three months ended September 30, 2023
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time
—
—
38
—
38
Revenues from products and services transferred over time1
2,921
1,412
721
79
5,133
Total revenue from contracts with customers
2,921
1,412
759
79
5,171
Nine months ended September 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
—
115
93
—
208
Revenues from products and services transferred over time1
9,108
4,311
4,674
137
18,230
Total revenue from contracts with customers
9,108
4,426
4,767
137
18,438
Nine months ended September 30, 2023
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point in time
—
—
105
—
105
Revenues from products and services transferred over time1
8,991
4,294
4,366
220
17,871
Total revenue from contracts with customers
8,991
4,294
4,471
220
17,976
1Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.
4. SEGMENTED INFORMATION
Change in Reportable Segments
Effective January 1, 2024, to better align how the CODM reviews operating performance and resource allocation across operating segments, we transferred our Canadian and United States (US) crude oil marketing businesses from the Energy Services segment to the Liquids Pipelines segment. As a result, the Energy Services segment ceased to exist and the remainder of the business, comprising natural gas and power marketing, is now reported in the Eliminations and Other segment. Beginning in the first quarter of 2024, prior period comparable results for segmented information have been recast to reflect the change in reportable segments. This segment reporting change does not have an impact on our consolidated results.
15
Three months ended September 30, 2024
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Eliminations and Other1
Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)
11,775
1,486
1,281
133
207
14,882
Commodity and gas distribution costs
(8,624)
(29)
(203)
2
(212)
(9,066)
Operating and administrative
(1,104)
(536)
(579)
(74)
12
(2,281)
Income/(loss) from equity investments
261
182
—
39
(3)
479
Other income (Note 12)
17
43
23
2
291
376
Earnings before interest, income taxes and depreciation and amortization
2,325
1,146
522
102
295
4,390
Depreciation and amortization
(1,317)
Interest expense
(1,314)
Income tax expense
(312)
Earnings
1,447
Capital expenditures2
268
609
675
92
8
1,652
Three months ended
September 30, 2023
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Eliminations and Other1
Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)
7,355
1,423
751
40
275
9,844
Commodity and gas distribution costs
(4,344)
1
(190)
(13)
(285)
(4,831)
Operating and administrative
(1,093)
(578)
(305)
(63)
(16)
(2,055)
Income/(loss) from equity investments
232
94
—
21
(4)
343
Other income/(expense) (Note 12)
14
33
15
45
(572)
(465)
Earnings/(loss) before interest, income taxes and depreciation and amortization
2,164
973
271
30
(602)
2,836
Depreciation and amortization
(1,164)
Interest expense
(921)
Income tax expense
(128)
Earnings
623
Capital expenditures2
318
462
415
9
2
1,206
Nine months ended September 30, 2024
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Eliminations and Other1
Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)
26,815
4,550
4,796
370
725
37,256
Commodity and gas distribution costs
(17,168)
(117)
(1,519)
1
(745)
(19,548)
Operating and administrative
(3,311)
(1,701)
(1,486)
(214)
(11)
(6,723)
Income/(loss) from equity investments
798
611
1
265
(11)
1,664
Gain on disposition of equity investments (Note 6)
—
1,063
—
28
—
1,091
Other income/(expense) (Note 12)
45
100
62
47
(460)
(206)
Earnings/(loss) before interest, income taxes and depreciation and amortization
7,179
4,506
1,854
497
(502)
13,534
Depreciation and amortization
(3,783)
Interest expense
(3,301)
Income tax expense
(1,437)
Earnings
5,013
Capital expenditures2
766
1,770
1,412
209
59
4,216
16
Nine months ended September 30, 2023
Liquids Pipelines
Gas Transmission
Gas Distribution and Storage
Renewable Power Generation
Eliminations and Other1
Consolidated
(millions of Canadian dollars)
Operating revenues (Note 3)
22,200
4,324
4,426
334
1,067
32,351
Commodity and gas distribution costs
(12,771)
1
(2,173)
(19)
(1,016)
(15,978)
Operating and administrative
(3,320)
(1,715)
(939)
(178)
32
(6,120)
Income/(loss) from equity investments
733
531
1
83
(10)
1,338
Other income/(expense) (Note 12)
102
79
39
75
(83)
212
Earnings/(loss) before interest, income taxes and depreciation and amortization
6,944
3,220
1,354
295
(10)
11,803
Depreciation and amortization
(3,447)
Interest expense
(2,709)
Income tax expense
(1,157)
Earnings
4,490
Capital expenditures2
835
1,332
1,025
77
54
3,323
1Includes operating revenues and commodity costs from our natural gas and power marketing subsidiaries for the three months ended September 30, 2024 of $213 million (2023 - $279 million) and $213 million (2023 - $292 million), respectively, and for the nine months ended September 30, 2024 of $750 million (2023 - $1.1 billion) and $757 million (2023 - $1.0 billion), respectively.
2Includes the equity component of the allowance for funds used during construction.
5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE
BASIC
Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding.
DILUTED
The treasury stock method is used to determine the dilutive impact of stock options and share-settled RSUs. This method assumes any proceeds from the exercise of stock options and vesting of share-settled RSUs would be used to purchase common shares at the average market price during the period.
Weighted average shares outstanding used to calculate basic and diluted earnings per common share are as follows:
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(number of shares in millions)
Weighted average shares outstanding
2,177
2,048
2,147
2,033
Effect of dilutive options and RSUs
3
1
3
2
Diluted weighted average shares outstanding
2,180
2,049
2,150
2,035
For the three months ended September 30, 2024 and 2023, 15.2 million and 21.6 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $55.56 and $53.69, respectively, were excluded from the diluted earnings per common share calculation.
For the nine months ended September 30, 2024 and 2023, 18.7 million and 18.2 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $54.18 and $54.81, respectively, were excluded from the diluted earnings per common share calculation.
17
DIVIDENDS PER SHARE
On October 29, 2024, our Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2024 to shareholders of record on November 15, 2024.
Dividend per share
Common Shares
$0.91500
Preference Shares, Series A
$0.34375
Preference Shares, Series B
$0.32513
Preference Shares, Series D
$0.33825
Preference Shares, Series F
$0.34613
Preference Shares, Series G1
$0.43014
Preference Shares, Series H
$0.38200
Preference Shares, Series I2
$0.40589
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 33
$0.33050
Preference Shares, Series 44
$0.42206
Preference Shares, Series 5
US$0.41769
Preference Shares, Series 7
$0.37425
Preference Shares, Series 9
$0.25606
Preference Shares, Series 11
$0.24613
Preference Shares, Series 13
$0.19019
Preference Shares, Series 15
$0.18644
Preference Shares, Series 19
$0.38825
1The quarterly dividend per share paid on Preference Shares, Series G was decreased to $0.43014 from $0.46817 on September 1, 2024 due to reset on a quarterly basis.
2The quarterly dividend per share paid on Preference Shares, Series I was decreased to $0.40589 from $0.44366 on September 1, 2024 due to reset on a quarterly basis.
3The quarterly dividend per share paid on Preference Shares, Series 3 was increased to $0.33050 from $0.23356 on September 1, 2024 due to reset of the annual dividend on September 1, 2024.
4The first quarterly dividend of $0.42206 per share paid on Preference Shares, Series 4 will be paid on December 1, 2024, due to conversion of Preference Shares, Series 3 into Preference Shares, Series 4 on September 1, 2024.
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.
Public Service Company of North Carolina, Incorporated
On September 30, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall North Carolina Holdco LLC, which owns 100% of Public Service Company of North Carolina, Incorporated (PSNC), for cash consideration of $2.7 billion (US$2.0 billion) (the PSNC Acquisition). PSNC is a public utility primarily engaged in the purchase, sale, transportation and distribution of natural gas to residential, commercial and industrial customers in North Carolina. PSNC operates under rates approved by the North Carolina Utilities Commission.
The following table summarizes the estimated preliminary fair values that were assigned to the net assets of PSNC:
September 30,
2024
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)
351
Property, plant and equipment (b)
4,113
Long-term assets (c)
203
Current liabilities
292
Long-term debt (d)
1,529
Other long-term liabilities (e)
667
Deferred income tax liabilities
365
Goodwill (f)
868
Purchase price:
Cash
2,682
a) Current assets consist primarily of cash, trade and other accounts receivable, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $50 million due to the short period to maturity. A provision for credit and recovery risk associated with accounts receivable has been made through the expected credit loss, which totaled $2 million.
b) PSNC's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, 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 $128 million of regulatory assets expected to be recovered from customers in future periods through rates and equity interests in a liquefied natural gas (LNG) storage facility in North Carolina and in an intrastate natural gas pipeline.
19
d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar yield, credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $156 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 PSNC 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 PSNC Acquisition, we began consolidating PSNC.
Our supplemental pro forma consolidated financial information for the three and nine months ended September 30, 2024 and 2023, including the results of operations for PSNC as if the PSNC Acquisition had been completed on January 1, 2023, are as follows:
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(unaudited; millions of Canadian dollars)
Operating revenues
15,010
9,949
37,921
33,038
Earnings attributable to common shareholders1
1,276
506
4,655
4,173
1 Includes adjustment for pro forma interest expense on debt financing for the PSNC Acquisition of $12 million and $48 million (after-tax of $9 million and $37 million) for the three and nine months ended September 30, 2023, respectively.
20
Questar Gas Company
On May 31, 2024, through a wholly-owned US subsidiary, we acquired all of the membership interests of Fall West Holdco LLC which owns 100% of Questar Gas Company (Questar) and its related Wexpro companies (Wexpro) for cash consideration of $4.1 billion (US$3.0 billion) (the Questar Acquisition). Questar is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Utah, southwestern Wyoming and southeastern Idaho. The Public Utilities Commissions of Utah, Wyoming and Idaho have granted Questar the necessary regulatory approvals to serve these areas. Wexpro develops and produces cost-of-service gas reserves for Questar and operates under agreements with the states of Utah and Wyoming.
The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Questar and Wexpro:
May 31, 2024
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)
464
Property, plant and equipment (b)
5,921
Long-term assets (c)
191
Current liabilities
407
Long-term debt (d)
1,343
Other long-term liabilities (e)
948
Deferred income tax liabilities
522
Goodwill (f)
751
Purchase price:
Cash
4,107
a) Current assets consist primarily of cash, trade and other accounts receivable and inventory. The fair value of trade receivables from customers approximates their carrying value of $201 million due to the short period to maturity. A provision for credit and recovery risk associated with accounts receivable has been made through the expected credit loss, which totaled $9 million.
b) Questar's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, distribution and storage assets. Wexpro's property, plant and equipment consists of cost-of-service gas and oil properties developed and produced for Questar. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value.
c) Long-term assets consist primarily of funds collected from Questar by Wexpro and held in trust to fund future asset retirement obligations (ARO), as well as regulatory assets expected to be recovered from customers in future periods through rates.
d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar yield, credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $301 million with no corresponding regulatory offset.
e) Other long-term liabilities consist primarily of regulatory liabilities, expected to be refunded to customers in future periods through rates, as well as ARO. The fair value of the ARO liability was determined using a discounted cash flow approach.
21
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 September 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 nine months ended September 30, 2024 and 2023, including the results of operations for Questar and Wexpro as if the Questar Acquisition had been completed on January 1, 2023, are as follows:
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(unaudited; millions of Canadian dollars)
Operating revenues
14,882
10,040
38,471
33,885
Earnings attributable to common shareholders1
1,293
501
4,695
4,153
1 Includes adjustment for pro forma interest expense on debt financing for the Questar Acquisition of $18 million and $70 million (after-tax of $14 million and $52 million) for the three and nine months ended September 30, 2023, respectively.
The East Ohio Gas Company
On March 6, 2024, through a wholly-owned US subsidiary, we acquired all of the outstanding shares of capital stock of The East Ohio Gas Company (EOG) for cash consideration of $5.8 billion (US$4.3 billion) (the EOG Acquisition). EOG is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Ohio and is regulated by the Public Utilities Commission of Ohio.
The following table summarizes the estimated preliminary fair values that were assigned to the net assets of EOG:
March 6, 2024
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)
641
Property, plant and equipment (b)
7,253
Long-term assets (c)
1,647
Current liabilities
670
Long-term debt (d)
2,612
Other long-term liabilities (e)
993
Deferred income tax liabilities
1,036
Goodwill (f)
1,608
Purchase price:
Cash
5,838
a) Current assets consist primarily of cash, trade and other accounts receivable, prepaid expenses, regulatory assets and inventory. The fair value of trade receivables from customers approximates their carrying value of $376 million due to the short period to maturity. A provision for credit and recovery risk associated with accounts receivable has been made through the expected credit loss, which totaled $3 million.
22
b) EOG's property, plant and equipment constitutes an integrated system of rate-regulated natural gas transmission, gathering, distribution and storage assets. For these rate-regulated assets, fair value was determined using a market participant perspective. Given the regulated nature of, and fixed return on the assets, the fair value of property, plant and equipment acquired is equal to its carrying value.
c) Long-term assets consist primarily of overfunded pension plan assets of $395 million and $1.2 billion of regulatory assets expected to be recovered from customers in future periods through rates.
Pension plan assets attributable to the workforce acquired from EOG were transferred in cash to an Enbridge-sponsored pension plan based on their fair value as at December 31, 2023, subject to closing adjustments. The fair value of plan assets was determined using unadjusted quoted market prices for identical investments.
d) The fair value of long-term debt was determined based on the current underlying US Treasury interest rates on instruments of similar yield, credit risk and tenor, as well as an implied credit spread based on current market conditions. We recorded a fair value adjustment to reduce long-term debt by $478 million with no corresponding regulatory offset.
e) Other long-term liabilities consist primarily of regulatory liabilities expected to be refunded to customers in future periods through rates.
f) Goodwill is primarily attributable to the existing assembled assets and workforce of EOG that cannot be duplicated at the same cost by a new entrant and the enhanced scale and geographic diversity of our regulated natural gas distribution business, which provides a platform for future growth and optimization with existing assets. The goodwill balance recognized has been assigned to our Gas Distribution and Storage segment and is not tax deductible.
Upon completion of the EOG Acquisition, we began consolidating EOG. For the period beginning March 6, 2024 through to September 30, 2024, EOG generated $751 million of operating revenues and $170 million of earnings attributable to common shareholders.
Our supplemental pro forma consolidated financial information for the three and nine months ended September 30, 2024 and 2023, including the results of operations for EOG as if the EOG Acquisition had been completed on January 1, 2023, are as follows:
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(unaudited; millions of Canadian dollars)
Operating revenues
14,882
10,131
37,568
33,375
Earnings attributable to common shareholders1
1,296
625
4,614
4,266
1 Includes adjustment for pro forma interest expense on debt financing for the EOG Acquisition of $26 million and $100 million (after-tax of $20 million and $77 million) for the three and nine months ended September 30, 2023, respectively.
The purchase price allocations for the PSNC Acquisition, Questar Acquisition and EOG Acquisition (together, the Acquisitions) were prepared on a preliminary basis and are subject to change as additional information becomes available concerning the fair values of the pension, ARO and regulatory balances and their tax bases. Any adjustments to the purchase price allocations will be made as soon as practicable, but no later than one year from the date of each acquisition.
The Acquisitions further diversify, and are complementary to, our existing gas distribution operations.
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Acquisition of RNG Facilities
On January 2, 2024, through a wholly-owned US subsidiary, we acquired six Morrow Renewables operating landfill gas-to-renewable natural gas (RNG) production facilities (Tomorrow RNG) located in Texas and Arkansas for total consideration of $1.3 billion (US$1.0 billion), of which $584 million (US$439 million) was paid at close and an additional deferred consideration is payable within two years with a fair value of $757 million (US$568 million) (the RNG Facilities Acquisition). The acquired assets align with and advance our low-carbon strategy.
The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Tomorrow RNG:
January 2, 2024
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets
31
Intangible assets (a)
925
Property, plant and equipment (b)
174
Current liabilities
5
Goodwill (c)
223
Purchase price:
Cash
584
Deferred consideration (d):
Current portion of long-term debt
550
Long-term debt
207
Other adjustments
7
1,348
a) Intangible assets consist of long-term gas supply agreements with the respective facility's landfill owner. Fair value was determined using an income-based approach, specifically the multi-period excess earnings method, by estimating the present value of the after-tax cash flows attributable to the gas rights. The intangible assets will be amortized on a straight-line basis over the term of the respective agreement, inclusive of extension options, which range from 13 to 42 years.
b) Tomorrow RNG's property, plant and equipment constitutes specialized landfill gas plant and equipment which collects gas produced by waste decomposition, treats and compresses the gas to pipeline specifications. The direct method of replacement cost was used to determine the majority of the fair value of property, plant and equipment. Adjustments were then applied for estimated physical deterioration.
c) Goodwill is primarily attributable to expected future returns from a portfolio of both operating and scalable RNG assets, furthering the diversity of our renewable projects portfolio and accelerating progress toward our energy transition goals. The goodwill balance recognized has been assigned to our Gas Transmission segment and is tax deductible over 15 years.
d) We entered into six non-interest bearing promissory notes due to Morrow Renewables, the total value of which represents deferred payments of $808 million (US$606 million) due within two years. The first and second payments are due on January 2, 2025 and December 31, 2025, respectively. The $757 million (US$568 million) recognized in the purchase price represents the fair value of deferred consideration at the date of acquisition using the imputed interest rate method over the terms of the notes.
24
Upon completion of the RNG Facilities Acquisition, we began consolidating Tomorrow RNG. For the period beginning January 2, 2024 through to September 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 nine months ended September 30, 2024 and 2023, as if the RNG Facilities Acquisition had been completed on January 1, 2023, was also immaterial.
ASSET ACQUISITION
Tres Palacios Holdings LLC
On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for $451 million (US$335 million) of cash. Tres Palacios is a natural gas storage facility located in the US Gulf Coast and its infrastructure serves Texas gas-fired power generation and LNG exports, as well as Mexico pipeline exports.
We allocated assets with a fair value of $790 million (US$588 million) to Property, plant and equipment, net, of which $254 million (US$189 million) relates to storage cavern right-of-use assets, and recorded the related lease liabilities of $7 million (US$5 million) and $248 million (US$184 million) to Current portion of long-term debt and Long-term debt, respectively, in the Consolidated Statements of Financial Position. The acquired assets are included in our Gas Transmission segment.
DISPOSITION
Disposition of Alliance Pipeline and Aux Sable Interests
On April 1, 2024, we closed the sale of our 50.0% interest in the Alliance Pipeline, our interest in Aux Sable (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, subject to customary closing adjustments. A gain on disposal of $1.1 billion before tax, which is net of $1.0 billion of the goodwill from our Gas Transmission segment allocated to the disposal group, is included in Gain on disposition of equity investments in the Consolidated Statements of Earnings for the nine months ended September 30, 2024. Our equity investments in the Alliance Pipeline and Aux Sable were previously included in our Gas Transmission segment. Our equity investment in NRGreen was previously included in our Renewable Power Generation segment.
EQUITY INVESTMENT TRANSACTION
Joint Venture with WhiteWater/I Squared and MPLX
On May 29, 2024, through a wholly-owned US subsidiary, we formed a joint venture (the Whistler Parent JV) with WhiteWater/I Squared Capital (WhiteWater/I Squared) and MPLX LP (MPLX) that will develop, construct, own and operate natural gas pipeline and storage assets connecting Permian Basin natural gas supply to growing LNG and other US Gulf Coast demand. The Whistler Parent JV is owned by WhiteWater/I Squared (50.6%), MPLX (30.4%) and Enbridge (19.0%) and is accounted for as an equity method investment.
25
In connection with the formation of the Whistler Parent JV, we contributed our 100% interest in the Rio Bravo Pipeline project and $487 million (US$357 million) of cash to the Whistler Parent JV. In addition to our 19.0% equity interest in the Whistler Parent JV, we received a special equity interest in the Whistler Parent JV which provides for a 25.0% economic interest in the Rio Bravo Pipeline project. This interest is subject to certain redemption rights held by Whitewater/I Squared and MPLX. After the closing on May 29, 2024, we accrued for our share of the post-closing mandatory capital expenditures of approximately US$150 million for the Rio Bravo Pipeline project. Additional capital expenditures to complete the Rio Bravo Pipeline project will be proportionate to our economic interest.
The contribution of our interest in the Rio Bravo Pipeline project to the Whistler Parent JV in exchange for the equity interests discussed above represents a non-cash transaction in Cash Flows from Investing Activities and does not have an effect on our Consolidated Statements of Cash Flows. This component of the transaction resulted in a reduction of $321 million (US$235 million) to Property, plant and equipment, net and a corresponding increase to Long-term investments in the Consolidated Statements of Financial Position. The cash component of the transaction, 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 September 30, 2024:
Maturity1
Total Facilities
Draws2
Available
(millions of Canadian dollars)
Enbridge Inc.
2025-2049
8,835
3,993
4,842
Enbridge (U.S.) Inc.
2026-2029
10,403
2,518
7,885
Enbridge Pipelines Inc.
2026
2,000
1,095
905
Enbridge Gas Inc.
2026
2,500
930
1,570
Total committed credit facilities
23,738
8,536
15,202
1Maturity date is inclusive of the one-year term out option for certain credit facilities.
2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
In March 2024, we entered into a delayed-draw term loan facility in support of sustainable retrofit projects for large buildings using decarbonization solutions for $200 million which matures in March 2049.
In June 2024, we entered into a five-year, non-revolving term loan facility of US$250 million which matures in June 2029.
In July 2024, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2026, which includes a one-year term out provision from July 2025. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2029. Further, we extended the maturity dates of our three-year credit facilities to July 2027.
In July 2024, Enbridge Gas Inc. (Enbridge Gas Ontario) extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.
In July 2024, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.
26
In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $859 million was unutilized as at September 30, 2024. As at December 31, 2023, we had $1.1 billion of uncommitted demand letter of credit facilities, of which $572 million was unutilized.
In October 2024, we increased our letter of credit facilities by $200 million.
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 2025 to 2049.
As at September 30, 2024 and December 31, 2023, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $6.8 billion and $3.8 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.
ACQUISITIONS
As a result of the EOG Acquisition, RNG Facilities Acquisition, Questar Acquisition and PSNC Acquisition, our debt increased by US$1.9 billion, US$568 million, US$1.0 billion, and US$1.1 billion, respectively, on each acquisition date. Refer to Note 6 - Acquisitions and Dispositions for further details.
LONG-TERM DEBT ISSUANCES
During the nine months ended September 30, 2024, we completed the following long-term debt issuances totaling US$5.1 billion and $1.8 billion:
Company
Issue Date
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
April 2024
5.25%
senior notes due April 2027
US$750
April 2024
5.30%
senior notes due April 2029
US$750
April 2024
5.63%
senior notes due April 2034
US$1,200
April 2024
5.95%
senior notes due April 2054
US$800
June 2024
7.38%
fixed-to-fixed subordinated notes due March 20551
US$500
June 2024
7.20%
fixed-to-fixed subordinated notes due June 20542
US$700
August 2024
4.21%
medium-term notes due February 2030
$600
August 2024
4.73%
medium-term notes due August 2034
$800
August 2024
5.32%
medium-term notes due August 2054
$400
Algonquin Gas Transmission, LLC
July 2024
5.95%
senior notes due July 2034
US$350
1For the initial 5.5 years, the notes carry a fixed interest rate. On March 15, 2030, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.12%.
2For the initial 9.75 years, the notes carry a fixed interest rate. On June 27, 2034, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 2.97%.
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LONG-TERM DEBT REPAYMENTS
During the nine months ended September 30, 2024, we completed the following long-term debt repayments totaling US$3.6 billion, $0.8 billion and €23 million:
Company
Repayment Date
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
February 2024
Floating rate notes1
US$600
February 2024
2.15%
senior notes
US$400
March 2024
5.97%
senior notes2
US$700
June 2024
3.50%
senior notes
US$500
Enbridge Gas Inc.
August 2024
3.15%
medium-term notes
$215
Enbridge Pipelines (Southern Lights) L.L.C.
June 2024
3.98%
senior notes
US$42
Enbridge Pipelines Inc.
February 2024
8.20%
debentures
$200
Enbridge Southern Lights LP
January and July 2024
4.01%
senior notes
$20
Westcoast Energy Inc.
September 2024
3.43%
medium-term notes
$350
Spectra Energy Partners, LP
March 2024
4.75%
senior notes
US$1,000
Blauracke GmbH
April 2024
2.10%
senior notes
€23
Algonquin Gas Transmission, LLC
July 2024
3.51%
senior notes
US$350
1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 63 basis points.
2The notes carried an original maturity date in March 2026, and were callable in March 2024, which was one year after their issuance.
SUBORDINATED TERM NOTES
As at September 30, 2024 and December 31, 2023, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $14.8 billion and $13.0 billion, respectively.
FAIR VALUE ADJUSTMENT
As at September 30, 2024 and December 31, 2023, the fair value adjustments to increase total debt assumed in a historical acquisition were $474 million and $514 million, respectively. As a result of the EOG, Questar, and PSNC Acquisitions, there were additional fair value adjustments of $451 million, $293 million, and $156 million, respectively, to decrease total debt as at September 30, 2024.
Amortization of the fair value adjustment is recorded to Interest expense in the Consolidated Statements of Earnings:
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
(Increase)/decrease to Interest expense
(9)
12
(7)
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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 September 30, 2024, we were in compliance with all such debt covenant provisions.
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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 PSNC Acquisition and to pay related fees and expenses.
On September 8, 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which were also used to finance a portion of the aggregate cash consideration payable for the Acquisitions discussed in Note 6 - Acquisitions and Dispositions.
9. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
Changes in Accumulated other comprehensive income (AOCI) attributable to our common shareholders for the nine months ended September 30, 2024 and 2023 are as follows:
Cash Flow Hedges
Excluded Components of Fair Value Hedges
Net Investment Hedges
Cumulative Translation Adjustment
Equity Investees
Pension and OPEB Adjustment
Total
(millions of Canadian dollars)
Balance as at January 1, 2024
320
(23)
(728)
2,653
11
70
2,303
Other comprehensive income/(loss) retained in AOCI
15
(34)
(357)
1,498
3
—
1,125
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1
22
—
—
—
—
—
22
Commodity contracts2
(1)
—
—
—
—
—
(1)
Foreign exchange contracts3
—
43
—
—
—
—
43
Amortization of pension and OPEB actuarial gain4
—
—
—
—
—
(14)
(14)
36
9
(357)
1,498
3
(14)
1,175
Tax impact
Income tax on amounts retained in AOCI
(4)
8
—
—
—
—
4
Income tax on amounts reclassified to earnings
(3)
(10)
—
—
—
3
(10)
(7)
(2)
—
—
—
3
(6)
Balance as at September 30, 2024
349
(16)
(1,085)
4,151
14
59
3,472
29
Cash Flow Hedges
Excluded Components of Fair Value Hedges
Net Investment Hedges
Cumulative Translation Adjustment
Equity Investees
Pension and OPEB Adjustment
Total
(millions of Canadian dollars)
Balance as at January 1, 2023
121
(35)
(1,137)
4,348
5
218
3,520
Other comprehensive income/(loss) retained in AOCI
447
11
42
(128)
8
—
380
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1
63
—
—
—
—
—
63
Other contracts5
1
—
—
—
—
—
1
Amortization of pension and OPEB actuarial gain4
—
—
—
—
—
(16)
(16)
511
11
42
(128)
8
(16)
428
Tax impact
Income tax on amounts retained in AOCI
(117)
—
—
—
(1)
—
(118)
Income tax on amounts reclassified to earnings
(6)
—
—
—
—
3
(3)
(123)
—
—
—
(1)
3
(121)
Balance as at September 30, 2023
509
(24)
(1,095)
4,220
12
205
3,827
1Reported within Interest expense in the Consolidated Statements of Earnings.
2Reported within Transportation and other services revenues in the Consolidated Statements of Earnings.
3Reported within Other income/(expense) in the Consolidated Statements of Earnings.
4These components are included in the computation of net periodic benefit credit and are reported within Other income/(expense) in the Consolidated Statements of Earnings.
5Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
10. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
MARKET RISK
Our earnings, cash flows and other comprehensive income/(loss) (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risks). Formal risk management policies, processes and systems have been designed to mitigate these risks.
The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.
Foreign Exchange Risk
We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in US dollar-denominated investments and subsidiaries using foreign currency US dollar-denominated debt.
30
Interest Rate Risk
Our earnings, cash flows and OCI are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We have a policy of limiting the maximum floating rate debt to 30% of total debt outstanding. To ensure compliance with our policy, we monitor and adjust our debt portfolio mix of fixed and variable rate debt instruments in conjunction with the use of hedging instruments.We have implemented a hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps and costless collars. These swaps have an average fixed rate of 3.7%.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. A combination of qualifying and non-qualifying forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via execution of floating-to-fixed interest rate swaps with an average swap rate of 3.5%.
Commodity Price Risk
Our earnings, cash flows and OCI are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy marketing subsidiaries. These commodities include natural gas, crude oil, power and natural gas liquids (NGL). We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through the revaluation of outstanding units every period.
TOTAL DERIVATIVE INSTRUMENTS
We have a policy of entering into individual International Swaps and Derivatives Association, Inc. (ISDA) agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances.
The following tables summarize the Consolidated Statements of Financial Position location and carrying value of our derivative instruments, as well as the maximum potential settlement amounts, in the event of the specific circumstances described above.
31
September 30, 2024
Derivative Instruments Used as Cash Flow Hedges
Derivative Instruments Used as Fair Value Hedges
Non- Qualifying Derivative Instruments
Total Gross Derivative Instruments as Presented
Amounts Available for Offset
Total Net Derivative Instruments
(millions of Canadian dollars)
Other current assets
Foreign exchange contracts
—
33
41
74
(20)
54
Interest rate contracts
5
—
16
21
(7)
14
Commodity contracts
2
—
328
330
(162)
168
Other contracts
—
—
1
1
—
1
7
33
386
426
(189)
237
Deferred amounts and other assets
Foreign exchange contracts
—
—
120
120
(81)
39
Interest rate contracts
20
—
72
92
(59)
33
Commodity contracts
—
—
102
102
(37)
65
20
—
294
314
(177)
137
Other current liabilities
Foreign exchange contracts
—
(49)
(252)
(301)
20
(281)
Interest rate contracts
—
—
(15)
(15)
7
(8)
Commodity contracts
—
—
(334)
(334)
162
(172)
—
(49)
(601)
(650)
189
(461)
Other long-term liabilities
Foreign exchange contracts
—
—
(794)
(794)
81
(713)
Interest rate contracts
(95)
—
(166)
(261)
59
(202)
Commodity contracts
—
—
(196)
(196)
37
(159)
(95)
—
(1,156)
(1,251)
177
(1,074)
Total net derivative asset/(liability)
Foreign exchange contracts
—
(16)
(885)
(901)
—
(901)
Interest rate contracts
(70)
—
(93)
(163)
—
(163)
Commodity contracts
2
—
(100)
(98)
—
(98)
Other contracts
—
—
1
1
—
1
(68)
(16)
(1,077)
(1,161)
—
(1,161)
32
December 31, 2023
Derivative Instruments Used as Cash Flow Hedges
Derivative Instruments Used as Fair Value Hedges
Non- Qualifying Derivative Instruments
Total Gross Derivative Instruments as Presented
Amounts Available for Offset
Total Net Derivative Instruments
(millions of Canadian dollars)
Other current assets
Foreign exchange contracts
—
41
98
139
(32)
107
Interest rate contracts
31
—
34
65
(32)
33
Commodity contracts
—
—
418
418
(270)
148
Other contracts
—
—
1
1
(1)
—
31
41
551
623
(335)
288
Deferred amounts and other assets
Foreign exchange contracts
—
16
319
335
(122)
213
Interest rate contracts
51
—
2
53
(21)
32
Commodity contracts
—
—
75
75
(41)
34
51
16
396
463
(184)
279
Other current liabilities
Foreign exchange contracts
—
(44)
(84)
(128)
32
(96)
Interest rate contracts
(183)
—
(3)
(186)
32
(154)
Commodity contracts
(11)
—
(412)
(423)
270
(153)
Other contracts
—
—
(1)
(1)
1
—
(194)
(44)
(500)
(738)
335
(403)
Other long-term liabilities
Foreign exchange contracts
—
(17)
(481)
(498)
122
(376)
Interest rate contracts
(3)
—
(85)
(88)
21
(67)
Commodity contracts
(7)
—
(159)
(166)
41
(125)
(10)
(17)
(725)
(752)
184
(568)
Total net derivative liability
Foreign exchange contracts
—
(4)
(148)
(152)
—
(152)
Interest rate contracts
(104)
—
(52)
(156)
—
(156)
Commodity contracts
(18)
—
(78)
(96)
—
(96)
Other contracts
—
—
—
—
—
—
(122)
(4)
(278)
(404)
—
(404)
The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments:
September 30, 2024
2024
2025
2026
2027
2028
Thereafter
Total
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)
695
500
—
—
—
—
1,195
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)
2,014
5,327
4,697
4,271
3,342
1,068
20,719
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)
9
30
28
32
—
—
99
Foreign exchange contracts - Euro forwards - sell (millions of Euro)
35
126
121
81
67
195
625
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)
—
84,800
—
—
—
—
84,800
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)
1,900
2,236
1,717
675
49
13
6,590
Interest rate contracts - short-term receive fixed rate (millions of Canadian dollars)
18
—
—
—
—
—
18
Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars)1
300
4,080
723
—
—
—
5,103
Interest rate contracts - costless collar (millions of Canadian dollars)
—
1,858
265
104
6
—
2,233
Commodity contracts - natural gas (billions of cubic feet)2
7
101
60
28
9
7
212
Commodity contracts - crude oil (millions of barrels)2
(9)
22
19
1
1
2
36
Commodity contracts - power (megawatt per hour (MW/H))
151
31
26
(51)
(49)
(30)
(7)
3
1Represents the notional amount of long-term debt issuances hedged.
2Represents the notional amount of net purchase/(sale).
3Total is an average net purchase/(sale) of power.
33
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 September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative
71
35
(21)
(107)
Unrealized gain/(loss) on hedged item
(67)
(35)
33
106
Realized gain/(loss) on derivative
(11)
(11)
36
(34)
Realized loss on hedged item
—
—
(79)
—
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
The following table presents the effect of cash flow hedges and fair value hedges on our consolidated earnings and comprehensive income, before the effect of income taxes:
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Interest rate contracts
(144)
313
4
423
Commodity contracts
5
20
20
56
Other contracts
—
(1)
1
(3)
Fair value hedges
Foreign exchange contracts
(8)
2
(34)
11
(147)
334
(9)
487
Amount of (income)/loss reclassified from AOCI to earnings
Foreign exchange contracts1
12
—
43
—
Interest rate contracts2
10
40
22
63
Commodity contracts3
—
1
(1)
—
Other contracts4
—
—
—
1
22
41
64
64
1Reported within Other income/(expense) in the Consolidated Statements of Earnings.
2Reported within Interest expense in the Consolidated Statements of Earnings.
3Reported within Transportation and other services revenues in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
We estimate that a gain of $2 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is three years as at September 30, 2024.
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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 September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
Foreign exchange contracts1
203
(650)
(736)
415
Interest rate contracts2
(161)
17
(39)
72
Commodity contracts3
70
(229)
(35)
(206)
Other contracts4
2
(3)
1
(11)
Total unrealized derivative fair value gain/(loss), net
114
(865)
(809)
270
1For the respective nine months ended periods, reported within Transportation and other services revenues (2024 - nil; 2023 - $645 million gain) and Other income/(expense) (2024 - $736 million loss; 2023 - $230 million loss) in the Consolidated Statements of Earnings.
2Reported within Interest expense in the Consolidated Statements of Earnings.
3For the respective nine months ended periods, reported within Transportation and other services revenues (2024 - $14 million loss; 2023 - $85 million loss), Commodity sales (2024 - $91 million loss; 2023 - $75 million gain), Commodity costs (2024 - $103 million gain; 2023 - $136 million loss) and Operating and administrative expense (2024 - $33 million loss; 2023 - $60 million loss) in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. Our shelf prospectuses with securities regulators enable ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at September 30, 2024. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities. We also identify a variety of other potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.
CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through the maintenance and monitoring of credit exposure limits, contractual requirements and netting arrangements. We also review counterparty credit exposure using external credit rating services and other analytical tools to manage credit risk.
35
We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:
September 30, 2024
December 31, 2023
(millions of Canadian dollars)
Canadian financial institutions
289
457
US financial institutions
117
252
European financial institutions
79
107
Asian financial institutions
42
121
Other1
196
125
723
1,062
1Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at September 30, 2024, we did not provide any letters of credit in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on derivative asset exposures as at September 30, 2024 and December 31, 2023.
Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation.
Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, the assessment of credit ratings and netting arrangements. Within Enbridge Gas Ontario, credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.
FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.
FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our financial instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.
36
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 hold restricted long-term investments in exchange-traded funds and common shares in trusts in accordance with the CER's regulatory requirements 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.
We have also categorized the fair value of our long-term debt, investments in debt securities held by our captive insurance subsidiaries, and restricted long-term investments in Canadian government bonds held in trust in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. When possible, the fair value of our restricted long-term investments is based on quoted market prices for similar instruments and, if not available, based on broker quotes.
Level 3
Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivative's fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on the extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power, NGL and natural gas contracts, basis swaps, commodity swaps, and power and energy swaps, 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.
37
Fair Value of Derivatives
We have categorized our derivative assets and liabilities measured at fair value as follows:
September 30, 2024
Level 1
Level 2
Level 3
Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
—
74
—
74
Interest rate contracts
—
21
—
21
Commodity contracts
59
89
182
330
Other contracts
—
1
—
1
59
185
182
426
Long-term derivative assets
Foreign exchange contracts
—
120
—
120
Interest rate contracts
—
92
—
92
Commodity contracts
1
19
82
102
1
231
82
314
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
—
(301)
—
(301)
Interest rate contracts
—
(15)
—
(15)
Commodity contracts
(42)
(91)
(201)
(334)
(42)
(407)
(201)
(650)
Long-term derivative liabilities
Foreign exchange contracts
—
(794)
—
(794)
Interest rate contracts
—
(261)
—
(261)
Commodity contracts
(1)
(23)
(172)
(196)
(1)
(1,078)
(172)
(1,251)
Total net financial asset/(liability)
Foreign exchange contracts
—
(901)
—
(901)
Interest rate contracts
—
(163)
—
(163)
Commodity contracts
17
(6)
(109)
(98)
Other contracts
—
1
—
1
17
(1,069)
(109)
(1,161)
38
December 31, 2023
Level 1
Level 2
Level 3
Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts
—
139
—
139
Interest rate contracts
—
65
—
65
Commodity contracts
142
103
173
418
Other contracts
—
1
—
1
142
308
173
623
Long-term derivative assets
Foreign exchange contracts
—
335
—
335
Interest rate contracts
—
53
—
53
Commodity contracts
—
24
51
75
—
412
51
463
Financial liabilities
Current derivative liabilities
Foreign exchange contracts
—
(128)
—
(128)
Interest rate contracts
—
(186)
—
(186)
Commodity contracts
(136)
(76)
(211)
(423)
Other contracts
—
(1)
—
(1)
(136)
(391)
(211)
(738)
Long-term derivative liabilities
Foreign exchange contracts
—
(498)
—
(498)
Interest rate contracts
—
(88)
—
(88)
Commodity contracts
—
(22)
(144)
(166)
—
(608)
(144)
(752)
Total net financial asset/(liability)
Foreign exchange contracts
—
(152)
—
(152)
Interest rate contracts
—
(156)
—
(156)
Commodity contracts
6
29
(131)
(96)
Other contracts
—
—
—
—
6
(279)
(131)
(404)
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
September 30, 2024
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 - financial1
Natural gas
(5)
Forward gas price
2.65
8.64
4.47
$/mmbtu2
Crude
(10)
Forward crude price
68.33
93.84
89.52
$/barrel
Power
(75)
Forward power price
28.63
162.60
60.57
$/MW/H
Commodity contracts - physical1
Natural gas
(10)
Forward gas price
0.05
10.03
3.66
$/mmbtu2
Crude
25
Forward crude price
70.48
111.10
90.27
$/barrel
Power
(73)
Forward power price
22.77
144.39
61.52
$/MW/H
Commodity options3
Natural gas
39
Option volatility
6%
70%
46%
(109)
1Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2One million British thermal units (mmbtu).
3Commodity options contracts are valued using an option model valuation technique.
39
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:
Nine months ended September 30,
2024
2023
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period
(131)
(136)
Total gain/(loss), unrealized
Included in earnings1
1
(205)
Included in OCI
19
—
Settlements
2
119
Level 3 net derivative liability at end of period
(109)
(222)
1Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
There were no transfers into or out of Level 3 as at September 30, 2024 or December 31, 2023.
Net Investment Hedges
We currently have designated a portion of our US dollar-denominated debt as a hedge of our net investment in US dollar-denominated investments and subsidiaries.
During the nine months ended September 30, 2024 and 2023, we recognized unrealized foreign exchange losses of $244 million and gains of $86 million, respectively, on the translation of US dollar-denominated debt, in OCI. During the nine months ended September 30, 2024 and 2023, we recognized realized losses of $113 million and $44 million, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.
Fair Value of Other Financial Instruments
Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $178 million and $173 million as at September 30, 2024 and December 31, 2023, respectively.
As at September 30, 2024, we had investments with a fair value of $959 million included in Restricted long-term investments and cash in the Consolidated Statements of Financial Position (December 31, 2023 - $717 million) which are classified as available-for-sale. These securities represent restricted funds held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements, to cover future pipeline decommissioning costs in the state of Minnesota and to satisfy retirement obligations as Wexpro properties are abandoned.
We had restricted long-term investments and cash held in trust totaling $447 million as at September 30, 2024 which are classified as Level 1 in the fair value hierarchy (December 31, 2023 - $263 million). We also had restricted long-term investments held in trust totaling $512 million (cost basis - $529 million) and $454 million (cost basis - $486 million) as at September 30, 2024 and December 31, 2023, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding gains of $46 million and $45 million on these investments for the three and nine months ended September 30, 2024, respectively (2023 - losses of $44 million and $7 million, respectively).
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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 September 30, 2024, the fair value of investments in equity funds and debt securities held by our captive insurance subsidiaries was $334 million and $255 million, respectively (December 31, 2023 - $287 million and $284 million, respectively). Our investments in debt securities had a cost basis of $248 million as at September 30, 2024 (December 31, 2023 - $279 million). These investments in equity funds and debt securities are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, respectively, and are recorded in Other current assets and Long-term investments in the Consolidated Statements of Financial Position. There were unrealized holding gains of $14 million and $35 million for the three and nine months ended September 30, 2024, (2023 - losses of $8 million and gains of $14 million, respectively).
As at September 30, 2024 and December 31, 2023, our long-term debt including finance lease liabilities had a carrying value of $94.8 billion and $81.2 billion, respectively, before debt issuance costs and a fair value of $94.5 billion and $78.1 billion, respectively.
The fair value of financial assets and liabilities other than derivative instruments, certain long-term investments in other entities, restricted long-term investments, investments held by our captive insurance subsidiaries and long-term debt described above approximate their carrying value due to the short period to maturity.
11. INCOME TAXES
The effective income tax rates for the three months ended September 30, 2024 and 2023 were 17.7% and 17.0%, respectively, and for the nine months ended September 30, 2024 and 2023 were 22.3% and 20.5%, respectively.
The period-over-period increase in the effective income tax rate for the three-months ended is driven by the increase in US minimum tax, the effects of rate regulated accounting for income taxes, partially offset by a state apportionment income tax rate change due to the PSNC Acquisition (Note 6) relative to the change in earnings over the comparative periods.
The period-over-period increase in the effective income tax rate for the nine-months ended is due to an increase in US minimum tax, the tax effect of the write-down of non-deductible goodwill on the Gas Transmission segment (Note 6), and the effects of rate regulated accounting for income taxes, partially offset by a state apportionment income tax rate change due to the 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 change in earnings over the comparative periods.
12. OTHER INCOME/(EXPENSE)
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
Realized foreign currency gain/(loss)
(34)
31
80
177
Unrealized foreign currency gain/(loss)
255
(652)
(816)
(348)
Net defined pension and OPEB credit
44
34
133
101
Other
111
122
397
282
376
(465)
(206)
212
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13. CONTINGENCIES
LITIGATION
We and our subsidiaries are subject to various legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our interim consolidated financial position or results of operations.
TAX MATTERS
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.
INSURANCE
We maintain an insurance program for us, our subsidiaries and certain of our affiliates to mitigate a certain portion of our risks. However, not all potential risks arising from our operations are insurable, or are insured by us as a result of availability, high premiums and for various other reasons. We self-insure a significant portion of certain risks through our wholly-owned captive insurance subsidiaries, which requires certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices and the selection of estimated loss among estimates derived using different methods. Our insurance coverage is also subject to terms and conditions, exclusions and large deductibles or self-insured retentions which may reduce or eliminate coverage in certain circumstances.
Our insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, terms, policy limits and/or deductibles can vary substantially. We can give no assurance that we will be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable. In such case, we may decide to self-insure additional risks.
In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among entities on an equitable basis based on an insurance allocation agreement we have entered into with us and other subsidiaries.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our interim consolidated financial statements and the accompanying notes included in Part I. Item 1. Financial Statements of this quarterly report on Form 10-Q and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of our annual report on Form 10-K for the year ended December 31, 2023.
We continue to qualify as a foreign private issuer for purposes of the United States Securities Exchange Act of 1934, as amended (Exchange Act), as determined annually as of the end of our second fiscal quarter. We intend to continue to file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K with the United States (US) Securities and Exchange Commission (SEC) instead of filing the reporting forms available to foreign private issuers. We also intend to maintain our Form S-3 registration statements.
RECENT DEVELOPMENTS
ACQUISITIONS
US Gas Utilities
On September 5, 2023, Enbridge Inc. (Enbridge) entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company (EOG), Questar Gas Company (Questar) and its related Wexpro companies (Wexpro), and Public Service Company of North Carolina, Incorporated (PSNC) (together, the Acquisitions). The Acquisitions further diversify, and are complementary to, our existing gas distribution operations.
On September 30, 2024, through a wholly-owned US subsidiary, we acquired PSNC for cash consideration of $2.7 billion (US$2.0 billion) (the PSNC Acquisition). PSNC is a public utility primarily engaged in the purchase, sale, transportation and distribution of natural gas to residential, commercial and industrial customers in North Carolina. PSNC operates under rates approved by the North Carolina Utilities Commission. Going forward, PSNC will conduct business as Enbridge Gas North Carolina.
On May 31, 2024, through a wholly-owned US subsidiary, we acquired Questar and Wexpro for cash consideration of $4.1 billion (US$3.0 billion) (the Questar Acquisition). Questar is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Utah, southwestern Wyoming and southeastern Idaho. The Public Utilities Commissions of Utah, Wyoming and Idaho have granted Questar the necessary regulatory approvals to serve these areas. Wexpro develops and produces cost-of-service gas reserves for Questar and operates under agreements with the states of Utah and Wyoming. Questar conducts business as Enbridge Gas Utah, Enbridge Gas Wyoming and Enbridge Gas Idaho in those respective states.
On March 6, 2024, through a wholly-owned US subsidiary, we acquired EOG for cash consideration of $5.8 billion (US$4.3 billion) (the EOG Acquisition). EOG is a public natural gas utility providing distribution, storage and transmission services to residential, commercial and industrial customers in Ohio and is regulated by the Public Utilities Commission of Ohio. EOG conducts business as Enbridge Gas Ohio.
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Joint Venture with WhiteWater/I Squared and MPLX
On May 29, 2024, through a wholly-owned US subsidiary, we formed a joint venture (the Whistler Parent JV) with WhiteWater/I Squared Capital (WhiteWater/I Squared) and MPLX LP (MPLX) that will develop, construct, own and operate natural gas pipeline and storage assets connecting Permian Basin natural gas supply to growing liquefied natural gas (LNG) and other US Gulf Coast demand.The Whistler Parent JV is owned by WhiteWater/I Squared (50.6%), MPLX (30.4%) and Enbridge (19.0%) and owns the following assets:
•a 100% interest in the Whistler Pipeline, a 450-mile intrastate pipeline transporting natural gas from the Waha Header in the Permian Basin to Agua Dulce, Texas;
•a 100% interest in the Rio Bravo Pipeline project, two new parallel 137-mile pipelines transporting natural gas from the Agua Dulce supply area to NextDecade's Rio Grande LNG project in Brownsville, Texas;
•a 70% interest in the ADCC Pipeline, a new 40-mile pipeline which was placed into service in July 2024 and is designed to transport 1.7 billion cubic feet per day (bcf/d) of natural gas from the terminus of the Whistler Pipeline in Agua Dulce, Texas to Cheniere's Corpus Christi LNG export facility; and
•a 50% interest in Waha Gas Storage, a 2.0 bcf gas storage cavern facility connecting to key Permian egress pipelines including the Whistler Pipeline.
In connection with the formation of the Whistler Parent JV, we contributed our 100% interest in the Rio Bravo Pipeline project and $487 million (US$357 million) of cash to the Whistler Parent JV. In addition to our 19.0% equity interest in the Whistler Parent JV, we received a special equity interest in the Whistler Parent JV which provides for a 25.0% economic interest in the Rio Bravo Pipeline project. This interest is subject to certain redemption rights held by Whitewater/I Squared and MPLX. After the closing on May 29, 2024, we accrued for our share of the post-closing mandatory capital expenditures of approximately US$150 million for the Rio Bravo Pipeline project. Additional capital expenditures to complete the Rio Bravo Pipeline project will be proportionate to our economic interest.
ASSET MONETIZATION
Disposition of Alliance Pipeline and Aux Sable Interests
On April 1, 2024, we closed the sale of our 50.0% interest in the Alliance Pipeline, our interest in Aux Sable (including a 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and a 50.0% interest in Aux Sable Canada LP) and our interest in NRGreen Power Limited Partnership (NRGreen) to Pembina Pipeline Corporation (Pembina) for $3.1 billion, including $327 million of non-recourse debt, subject to customary closing adjustments. A gain on disposal of $1.1 billion before tax, which is net of $1.0 billion of the goodwill from our Gas Transmission segment allocated to the disposal group, is included in Gain on disposition of equity investments in the Consolidated Statements of Earnings for the nine months ended September 30, 2024.
GAS TRANSMISSION RATE PROCEEDINGS
Texas Eastern
In May 2024, Texas Eastern Transmission, LP (Texas Eastern) reached a negotiated settlement with customers to increase rates starting October 1, 2024 and filed a Stipulation and Agreement with the Federal Energy Regulatory Commission (FERC) on June 3, 2024. Texas Eastern received approval on July 31, 2024 from the FERC of its uncontested settlement with customers.
Algonquin
Algonquin Gas Transmission, LLC (Algonquin) filed a rate case on May 30, 2024. On June 28, 2024, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In compliance with the order, Algonquin will make a motion filing to implement the rates to be effective December 1, 2024, subject to refund. Settlement negotiations with shippers have commenced.
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Maritimes & Northeast Pipeline
Maritimes & Northeast Pipeline (M&N) US filed a rate case on May 30, 2024. On June 27, 2024, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures. In compliance with the order, M&N US will make a motion filing to implement the rates to be effective December 1, 2024, subject to refund. Settlement negotiations with shippers have commenced.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
Incentive Regulation Rate Application
In October 2022, Enbridge Gas Inc. (Enbridge Gas Ontario) filed its application with the Ontario Energy Board (OEB) to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application initially sought approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term (2025–2028). A third phase (Phase 3) was established with the OEB in 2023. Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones.
On December 21, 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). Enbridge Gas Ontario filed a Notice of Appeal with the Ontario Divisional Court on January 22, 2024 regarding various aspects of the Phase 1 Decision. On January 29, 2024, Enbridge Gas Ontario also filed a Notice of Motion with the OEB requesting the OEB to review and vary the Phase 1 Decision. Our Notice of Motion was subsequently amended on May 29, 2024 (Amended Motion). The Amended Motion focused on two aspects of the Phase 1 Decision: asset class average useful lives for depreciation purposes and the recoverability of integration capital. On October 8, 2024, the OEB issued a decision on the Amended Motion and determined that the asset class average useful lives issue did not meet the threshold to warrant a review, however the issue of integration capital did meet the threshold to warrant a review. After it receives written submissions on the issue of integration capital, the OEB will make a determination on whether there will be an oral hearing. The outcome and timing of a decision on the matter of integration capital is uncertain.
On February 24, 2024, the Government of Ontario introduced Bill 165, the Keeping Energy Costs Down Act (the Act). The Act gives the Government of Ontario time-limited authority to set the revenue horizon for small volume customers, effectively reversing that aspect of the OEB's Phase 1 Decision. The Act proceeded to and passed a final vote in the provincial legislature on May 15, 2024 and received royal assent on May 16, 2024. Regulations are now in place setting the revenue horizon for new customer connections to 40 years.
The Phase 1 Decision resulted in interim 2024 rates, pending Phase 2 of the proceeding and resolution of the Amended Motion. An updated Draft Interim Rate Order reflecting the Phase 1 Decision was filed on March 15, 2024 and subsequently approved by the OEB on April 11, 2024. The Interim Rate Order implemented 2024 rates on May 1, 2024, with an effective date of January 1, 2024.
Enbridge Gas Ontario filed its Phase 2 evidence on April 26, 2024. Phase 2 will establish the incentive rate mechanism for 2025-2028, and will also address unregulated storage cost allocation and new energy transition proposals. Phase 3 is anticipated to be completed in 2025.
FINANCING UPDATE
On the March 8, 2024 call date, we redeemed at par all of the outstanding US$700 million three-year callable, 5.97% senior notes that carried an original maturity date in March 2026.
In March 2024, we entered into a delayed-draw term loan facility in support of sustainable retrofit projects for large buildings using decarbonization solutions for $200 million which matures in March 2049.
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In April 2024, we closed a four-tranche offering consisting of three-year senior notes, five-year senior notes, 10-year senior notes, and 30-year senior notes for an aggregate principal amount of US$3.5 billion, which mature in April 2027, April 2029, April 2034 and April 2054, respectively.
On May 15, 2024, we established an at-the-market equity issuance program (ATM Program) which provided us with additional flexibility to partially fund the Acquisitions. From May 15, 2024 to July 31, 2024, 51,298,629 common shares were issued on Canadian and US exchanges at average prices of CAD$48.72 and US$35.77 per common share for aggregate gross proceeds of $2.5 billion. On August 1, 2024, we terminated the ATM Program. Net proceeds from sales of common shares under the ATM Program were used to partially fund the Questar Acquisition and PSNC Acquisition and to pay related fees and expenses.
In June 2024, we closed an offering consisting of a tranche of 30.75-year non-call 5.5-year fixed-to-fixed subordinated notes and a tranche of 30-year non-call 9.75-year fixed-to-fixed subordinated notes, for an aggregate principal amount of US$1.2 billion, which mature in March 2055 and June 2054, respectively.
In June 2024, we entered into a five-year, non-revolving term loan facility of US$250 million which matures in June 2029.
In July 2024, Algonquin closed an offering of 10-year senior notes for US$350 million which mature in July 2034.
In July 2024, Enbridge Gas Ontario extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.
In July 2024, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.
In July 2024, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2026, which includes a one-year term out provision from July 2025. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2029. Further, we extended the maturity dates of our three-year credit facilities to July 2027.
In August 2024, we closed a three-tranche offering consisting of 5.5-year medium-term notes, 10-year medium-term notes, and 30-year medium-term notes for an aggregate principal of $1.8 billion, which mature in February 2030, August 2034, and August 2054, respectively.
In October 2024, we increased our letter of credit facilities by $200 million.
These financing activities, in combination with the financing activities executed in 2023, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects and acquisitions without requiring access to the capital markets for the next 12 months, should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources.
As at September 30, 2024, after adjusting for the impact of floating-to-fixed interest rate swap hedges, less than 5% of our total debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements - Note 10 - Risk Management and Financial Instruments for more information on our interest rate hedging program.
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RESULTS OF OPERATIONS
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines
2,325
2,164
7,179
6,944
Gas Transmission
1,146
973
4,506
3,220
Gas Distribution and Storage
522
271
1,854
1,354
Renewable Power Generation
102
30
497
295
Eliminations and Other
295
(602)
(502)
(10)
Earnings before interest, income taxes and depreciation and amortization1
4,390
2,836
13,534
11,803
Depreciation and amortization
(1,317)
(1,164)
(3,783)
(3,447)
Interest expense
(1,314)
(921)
(3,301)
(2,709)
Income tax expense
(312)
(128)
(1,437)
(1,157)
Earnings attributable to noncontrolling interests
(56)
(2)
(167)
(117)
Preference share dividends
(98)
(89)
(286)
(260)
Earnings attributable to common shareholders
1,293
532
4,560
4,113
Earnings per common share attributable to common shareholders
0.59
0.26
2.12
2.02
Diluted earnings per common share attributable to common shareholders
0.59
0.26
2.12
2.02
1Non-GAAP financial measure. Refer to Non-GAAP and Other Financial Measures.
Change in Reportable Segments
Effective January 1, 2024, to better align how the chief operating decision-maker reviews operating performance and resource allocation across operating segments, we transferred our Canadian and US crude oil marketing businesses from the Energy Services segment to the Liquids Pipelines segment. As a result, the Energy Services segment ceased to exist and the remainder of the business, comprising natural gas and power marketing, are now reported in the Eliminations and Other segment. Beginning in the first quarter of 2024, prior period comparable results for segmented information have been recast to reflect the change in reportable segments. This segment reporting change does not have an impact on our consolidated results.
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
Three months ended September 30, 2024, compared with the three months ended September 30, 2023
Earnings attributable to common shareholders were positively impacted by $841 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•a non-cash, net unrealized derivative fair value gain of $112 million ($92 million after-tax) in 2024, compared with a net unrealized loss of $782 million ($591 million after-tax) in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;
•the absence in 2024 of a provision adjustment of $124 million ($95 million after-tax) related to a litigation matter;
•a deferred tax recovery of $59 million in 2024 due to change in state apportionment as a result of the Acquisitions; and
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•a non-cash, net unrealized gain of $14 million ($13 million after-tax) in 2024, compared with a net loss of $8 million ($7 million after-tax) in 2023, reflecting changes in the fair value of investments held by our captive insurance subsidiaries; partially offset by
•a non-cash revaluation loss of $18 million in 2024 ($13 million after-tax) to the gas inventory at our Aitken Creek Gas Storage Facility (Aitken Creek).
The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of our comprehensive economic hedging program to mitigate foreign exchange, interest rate and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.
After taking into consideration the factors above, the remaining $80 million decrease in earnings attributable to common shareholders is primarily explained by:
•higher interest expense primarily due to higher interest rates and higher average principal outstanding;
•higher depreciation and amortization expense mainly driven by the Acquisitions completed in 2024; and
•absence of contributions from our Gas Transmission segment due to the sale of our interests in the Alliance Pipeline and Aux Sable in April 2024; partially offset by
•full-quarter contributions from Enbridge Gas Ohio and Enbridge Gas Utah, and higher distribution charges resulting from increases in rates and customer base from Enbridge Gas Ontario in our Gas Distribution and Storage segment;
•higher contributions from our Gas Transmission segment primarily due to acquisitions completed after September 2023, favourable contracting, and lower operating costs in our US Gas Transmission assets; and
•higher contributions from our Liquids Pipelines segment driven by higher Mainline System tolls effective July 1, 2024 as a result of annual escalators and discontinuation of rate-regulated accounting of Southern Lights Pipeline as at December 31, 2023, net of lower Mainline System throughput in the third quarter of 2024.
Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023
Earnings attributable to common shareholders were positively impacted by $430 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•a gain on sale of $1.1 billion ($765 million after-tax) related to the disposition of interests in the Alliance Pipeline, Aux Sable and NRGreen to Pembina;
•the absence in 2024 of a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, as foreign exchange risks inherent within the Competitive Toll Settlement (CTS) are not present in the Mainline Tolling Settlement (MTS);
•a deferred tax recovery of $141 million in 2024 due to change in state apportionment as a result of the Acquisitions;
•the absence in 2024 of a provision adjustment of $124 million ($95 million after-tax) related to a litigation matter; and
•a non-cash unrealized net gain of $35 million ($32 million after-tax) in 2024, compared with a net gain of $14 million ($12 million after-tax) in 2023, reflecting changes in the fair value of investments held by our captive insurance subsidiaries; partially offset by
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•a non-cash, net unrealized derivative fair value loss of $773 million ($586 million after-tax) in 2024, compared with a net unrealized gain of $363 million ($277 million after-tax) in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate and commodity price risks;
•severance costs of $105 million ($79 million after-tax) as a result of a workforce reduction in February 2024;
•the absence in 2024 of the receipt of a litigation claim settlement of $68 million ($52 million after-tax);
•$55 million ($46 million after-tax) of integration and transaction costs incurred related to the Acquisitions in 2024, as compared to $21 million ($16 million after-tax) of transaction costs in 2023;
•a non-cash revaluation loss of $47 million in 2024 ($34 million after-tax) to the gas inventory at Aitken Creek; and
•a loss of $29 million ($23 million after-tax) as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV.
After taking into consideration the factors above, the remaining $17 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:
•contributions from Enbridge Gas Ohio and Enbridge Gas Utah, and higher distribution charges resulting from increases in rates and customer base from Enbridge Gas Ontario in our Gas Distribution and Storage segment;
•higher contributions from our Gas Transmission segment primarily due to favorable contracting and lower operating costs in our US Gas Transmission assets, and acquisitions completed after September 2023;
•higher investment income primarily due to pre-funding of the Acquisitions and timing of certain operating and administrative costs recoveries in our Eliminations and Other segment; and
•higher contributions from our Liquids Pipelines segment due to discontinuation of rate-regulated accounting of Southern Lights Pipeline as at December 31, 2023, higher volumes from the Gulf Coast and Mid-Continent System and the Bakken System.
The factors above were partially offset by:
•higher interest expense primarily due to higher interest rates and higher average principal outstanding;
•higher depreciation and amortization expense as a result of acquisitions and projects placed into service after September 2023;
•lower contributions from the Mainline System in our Liquids Pipelines segment driven by lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower Line 3 Replacement (L3R) surcharge;
•higher income tax expense largely driven by higher US minimum tax, changes to the state apportionment and the effects of rate-regulated accounting for income taxes;
•lower contributions from our Gas Transmission segment due to the sale of our interests in the Alliance Pipeline and Aux Sable in April 2024; and
•realized loss on foreign exchange hedge settlement in 2024 compared to a realized gain in 2023 in our Eliminations and Other segment.
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BUSINESS SEGMENTS
LIQUIDS PIPELINES
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization
2,325
2,164
7,179
6,944
Three months ended September 30, 2024, compared with the three months ended September 30, 2023
EBITDA was positively impacted by $117 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized gain of $26 million in 2024, compared with a net unrealized loss of $95 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.
After taking into consideration the factors above, the remaining $44 million increase is primarily explained by the following significant business factors:
•higher Mainline System tolls effective July 1, 2024 as a result of annual escalators;
•higher contributions from the Southern Lights Pipeline due primarily to the discontinuation of rate-regulated accounting as at December 31, 2023; and
•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, as compared to 2023; partially offset by
•lower Mainline System throughput in the third quarter of 2024 as compared to the same period in 2023; and
•lower contributions from Regional Oil Sands System primarily due to lower throughput.
Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023
EBITDA was positively impacted by $46 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•a non-cash, net unrealized gain of $20 million in 2024, compared with a net unrealized gain of $555 million in 2023, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and
•the absence in 2024 of the receipt of a litigation claim settlement of $68 million; partially offset by
•the absence in 2024 of a realized loss of $638 million due to termination of foreign exchange hedges, as foreign exchange risks inherent within the CTS framework are not present in the MTS.
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After taking into consideration the factors above, the remaining $189 million increase is primarily explained by the following significant business factors:
•higher contributions from the Southern Lights Pipeline due primarily to the discontinuation of rate-regulated accounting as at December 31, 2023;
•higher contributions from the Gulf Coast and Mid-Continent System due primarily to higher volumes on the Flanagan South Pipeline driven by the open season commitments that commenced in the first quarter of 2024, and the Enbridge Ingleside Energy Center due to higher demand;
•stronger Mainline System performance due to higher throughput and longer haul volumes;
•higher contributions from the Express-Platte System due primarily to longer haul volumes;
•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, as compared to 2023; and
•higher contributions from the Bakken System due to higher volumes; partially offset by
•lower Mainline System tolls as a result of revised tolls effective July 1, 2023 and a lower L3R surcharge.
GAS TRANSMISSION
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization
1,146
973
4,506
3,220
Three months ended September 30, 2024, compared with the three months ended September 30, 2023
EBITDA was positively impacted by $111 million due to certain infrequent or other non-operating factors, primarily explained by:
•the absence in 2024 of a provision adjustment of $124 million related to a litigation matter; partially offset by
•a non-cash revaluation loss of $18 million to the gas inventory at Aitken Creek.
The remaining $62 million increase is primarily explained by the following significant business factors:
•favorable contracting and lower operating costs on our US Gas Transmission assets;
•contributions from the acquisitions of Aitken Creek in the fourth quarter of 2023, Tomorrow RNG in the first quarter of 2024, and Whistler Parent JV in the second quarter of 2024; and
•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, compared to the same period in 2023; partially offset by
•the absence of contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments to Pembina in April 2024.
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Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023
EBITDA was positively impacted by $1,090 million due to certain infrequent or other non-operating factors, primarily explained by:
•a gain on sale of $1,063 million on the disposition of interests in the Alliance Pipeline and Aux Sable; and
•the absence in 2024 of a provision adjustment of $124 million related to a litigation matter; partially offset by
•a non-cash revaluation loss of $47 million to the gas inventory at Aitken Creek; and
•a loss of $29 million as a result of the contribution of our 100% interest in the Rio Bravo Pipeline project to the Whistler Parent JV.
The remaining $196 million increase is primarily explained by the following significant business factors:
•favorable contracting and lower operating costs on our US Gas Transmission assets;
•contributions from the acquisitions of Tres Palacios in the second quarter of 2023, Aitken Creek in the fourth quarter of 2023, Tomorrow RNG in the first quarter of 2024 and Whistler Parent JV in the second quarter of 2024;
•the favorable effect of translating US dollar earnings at a higher average exchange rate in 2024, compared to the same period in 2023; and
•higher first quarter earnings at Aux Sable due to favorable contracting; partially offset by
•lower contributions from Alliance Pipeline and Aux Sable due to the sale of our interests in these investments to Pembina in April 2024; and
•the absence in 2024 of recognition of revenues attributable to the Texas Eastern 2022 rate case settlement.
GAS DISTRIBUTION AND STORAGE
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization
522
271
1,854
1,354
Three months ended September 30, 2024, compared with the three months ended September 30, 2023
EBITDA was positively impacted by $251 million primarily due to the following significant business factors:
•full-quarter contributions from Enbridge Gas Ohio and Enbridge Gas Utah; and
•higher distribution charges resulting from increases in rates and customer base, and higher demand in the contract market at Enbridge Gas Ontario.
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Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023
EBITDA was positively impacted by $500 million primarily due to the following significant business factors:
•contributions from Enbridge Gas Ohio and Enbridge Gas Utah since their acquisitions in 2024; and
•higher distribution charges resulting from increases in rates and customer base, and higher demand in the contract market at Enbridge Gas Ontario; partially offset by
•warmer than normal weather in 2024, when compared with the normal weather forecast embedded in rates, which negatively impacted Enbridge Gas Ontario 2024 EBITDA by approximately $64 million period over period.
RENEWABLE POWER GENERATION
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization
102
30
497
295
Three months ended September 30, 2024, compared with the three months ended September 30, 2023
EBITDA was positively impacted by $105 million due to certain infrequent or other non-operating factors, primarily explained by a non-cash, net unrealized gain of $28 million in 2024, compared with a net unrealized loss of $83 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks.
The remaining $33 million decrease is primarily explained by:
•the absence in 2024 of fees earned on certain wind and solar development contracts; partially offset by
•higher contributions from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities.
Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023
EBITDA was positively impacted by $80 million due to certain infrequent or other non-operating factors, primarily explained by:
•a non-cash, net unrealized loss of $8 million in 2024, compared with a net unrealized loss of $79 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and
•a gain on sale of $29 million related to disposition of our interest in NRGreen to Pembina.
The remaining $122 million increase is primarily explained by the following significant business factors:
•contributions from our investment in Fox Squirrel Solar as a result of the generation of investment tax credits;
•higher contributions from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities; and
•stronger wind resources at European offshore wind facilities; partially offset by
•the absence in 2024 of fees earned on certain wind and solar development contracts.
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ELIMINATIONS AND OTHER
Three months ended September 30,
Nine months ended September 30,
2024
2023
2024
2023
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization
295
(602)
(502)
(10)
Eliminations and Other includes operating and administrative costs that are not allocated to business segments, and the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. Eliminations and Other also includes the impact of new business development activities, corporate investments, and natural gas and power marketing and logistical services to North American refiners, producers, and other customers.
Three months ended September 30, 2024, compared with the three months ended September 30, 2023
EBITDA was positively impacted by $897 million, primarily due to certain infrequent or non-operating factors, explained by:
•a non-cash, net unrealized gain of $206 million in 2024, compared with a net loss of $661 million in 2023, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk; and
•a non-cash, net unrealized gain of $15 million in 2024, compared with a net loss of $8 million in 2023, reflecting changes in the fair value of investments held by our captive insurance subsidiaries.
Nine months ended September 30, 2024, compared with the nine months ended September 30, 2023
EBITDA was negatively impacted by $628 million due to certain infrequent or non-operating factors, primarily explained by:
•a non-cash, net unrealized loss of $745 million in 2024, compared with a net loss of $226 million in 2023, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk;
•severance costs of $105 million as a result of a workforce reduction in February 2024; and
•$55 million of integration and transaction costs incurred as a result of the Acquisitions in 2024, as compared to $21 million in 2023; partially offset by
•a non-cash net unrealized gain of $35 million in 2024, compared with a net gain of $14 million in 2023, reflecting changes in the fair value of investments held by our captive insurance subsidiaries.
After taking into consideration the non-operating factors above, the remaining $136 million increase is primarily explained by:
•higher investment income primarily from the pre-funding of the Acquisitions; and
•timing of certain operating and administrative cost recoveries from the business units; partially offset by
•realized foreign exchange loss on hedge settlements in 2024, compared to a gain in 2023.
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GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS
The following table summarizes the status of our significant commercially secured projects, organized by business segment:
Enbridge's Ownership Interest
Estimated Capital
Cost1
Expenditures to Date2
Status2
Expected In-Service Date
(Canadian dollars, unless stated otherwise)
GAS TRANSMISSION
1.
Texas Eastern Venice Extension3
100
%
US$477 million
US$370 million
Under construction
2024
2.
Texas Eastern Modernization
100
%
US$394 million
US$102 million
Under construction
2025 - 2026
3.
T-North Expansion (Aspen Point)
100
%
$1.2 billion
$181 million
Pre-construction
2026
4.
Tennessee Ridgeline Expansion
100
%
US$1.1 billion
US$175 million
Pre-construction
2026
5.
Woodfibre LNG4
30
%
US$1.5 billion
US$498 million
Under construction
2027
6.
T-South Expansion (Sunrise)
100
%
$4.0 billion
$157 million
Pre-construction
2028
7.
Canyon System Pipelines
100
%
US$700 million
US$1 million
Pre-construction
2029
GAS DISTRIBUTION AND STORAGE
8.
Moriah Energy Center5
100
%
US$538 million
US$167 million
Under construction
2027
9.
T15 Reliability Project5
100
%
US$632 million
US$6 million
Pre-construction
2027
RENEWABLE POWER GENERATION
10.
Fécamp Offshore Wind6
17.9
%
$692 million
$631 million
In service
May 2024
(€471 million)
(€432 million)
11.
Calvados Offshore Wind7
21.7
%
$954 million
$413 million
Under construction
2025
(€645 million)
(€286 million)
12.
Fox Squirrel Solar8
50
%
US$574 million
US$380 million
Under construction
2024
13.
Sequoia Solar
100
%
US$1.1 billion
US$259 million
Various stages
2025 - 2026
1These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.
2Expenditures to date and status of the project are determined as at September 30, 2024.
3Includes the US$37 million Gator Express Project placed into service in August 2023. Total estimated capital cost consists of the reversal and expansion of Texas Eastern's Line 40 expected to be completed in the fourth quarter of 2024.
4Our equity contribution is approximately US$893 million, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated prior to the 60% engineering milestone, at which point Enbridge's preferred return will be set.
5Previously approved PSNC projects that were acquired by Enbridge through the PSNC Acquisition.
6Our equity contribution is minimal after project refinancing was approved in the first quarter of 2024. The project is financed through non-recourse project level debt.
7Our equity contribution is $181 million, with the remainder financed through non-recourse project level debt.
8Includes three phases of the project. The first phase of the project commenced operations in December 2023, and the second phase commenced operations in the third quarter of 2024. The third phase is expected to enter service in the fourth quarter of 2024.
A full description of each of our projects is provided in our annual report on Form 10-K for the year ended December 31, 2023. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.
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GAS TRANSMISSION
Canyon System Pipelines
Enbridge has sanctioned the construction of two new offshore pipelines in the US Gulf of Mexico to deliver natural gas and crude oil from BP Exploration & Production Company's Kaskida offshore project.
The development includes a new 24/26-inch oil pipeline which will connect to Shell Pipeline Company LP's Green Canyon 19 Platform, and a 12-inch gas pipeline connecting to Enbridge's Magnolia Gas Gathering System.
Tennessee Ridgeline Expansion
The Tennessee Ridgeline Expansion project is an expansion of the East Tennessee Natural Gas (ETNG) system which would provide additional natural gas for the Tennessee Valley Authority (TVA) to support the replacement of an existing coal-fired power plant as TVA continues to transition its generation mix towards lower-carbon fuels. The proposed scope includes the installation of approximately 125 miles of 30-inch pipeline looping, one electric-powered compressor station, and an 8-megawatt behind-the-meter solar array.
TVA published a Notice of Intent in the Federal Register on June 15, 2021, to initiate the environmental review process for its proposed action to retire the Kingston Coal-Fired Plant and to replace it with a natural gas plant. On April 2, 2024, TVA issued a Record of Decision (ROD) documenting its decision to adopt TVA's Preferred Alternative to replace the retiring coal generating units at the Kingston Coal-Fired Plant with a natural gas plant. The issuance of the ROD adopting its Preferred Alternative satisfied a key condition of TVA's Precedent Agreement with ETNG related to the ETNG Ridgeline Expansion project.
All necessary regulatory authorizations from the FERC and other federal and state agencies will be obtained before construction of the project commences. Pending the approval and receipt of all necessary permits, construction is expected to begin in 2025 with a target in-service date of late 2026.
GAS DISTRIBUTION AND STORAGE
Moriah Energy Center
Moriah Energy Center is a LNG facility that is under construction in Person County, North Carolina with 2 bcf storage capacity. The facility is required to ensure system reliability and address supply constraints due to customer growth, and will be designed with trucking capabilities to support other LNG facilities. The construction started in first quarter of 2024 and is expected to achieve completion in 2027.
T-15 Reliability Project
The T-15 Reliability Project includes the construction of 45 miles of transmission pipe, a compressor station and associated metering and regulation facilities in Rockingham, Caswell, and Person counties in North Carolina. The project is expected to start construction in 2026 and to achieve project completion in 2027.
RENEWABLE POWER GENERATION
Sequoia Solar Project
On November 1, 2024, Enbridge announced that it has sanctioned the Sequoia Solar Project, a 815-megawatt solar farm located approximately 150 miles west of Dallas, Texas. The two-phased project is expected to achieve project completion in 2025 and 2026.
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LIQUIDITY AND CAPITAL RESOURCES
The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control, including but not limited to, financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to help ensure we maintain sufficient liquidity to meet routine operating and future capital requirements.
In the near term, we generally expect to utilize cash from operations together with commercial paper issuances and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures and acquisitions, fund debt retirements and pay common and preference share dividends. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.
We have signed capital obligation contracts for the purchase of services, pipe and other materials totaling approximately $2.6 billion, which are expected to be paid over the next five years.
Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives.
CAPITAL MARKET ACCESS
We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuances of long-term debt, equity and other forms of long-term capital when market conditions are attractive.
Credit Facilities and Liquidity
To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at September 30, 2024:
Maturity1
Total Facilities
Draws2
Available
(millions of Canadian dollars)
Enbridge Inc.
2025-2049
8,835
3,993
4,842
Enbridge (U.S.) Inc.
2026-2029
10,403
2,518
7,885
Enbridge Pipelines Inc.
2026
2,000
1,095
905
Enbridge Gas Inc.
2026
2,500
930
1,570
Total committed credit facilities
23,738
8,536
15,202
1Maturity date is inclusive of the one-year term out option for certain credit facilities.
2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
In March 2024, we entered into a delayed-draw term loan facility in support of sustainable retrofit projects for large buildings using decarbonization solutions for $200 million which matures in March 2049.
In June 2024, we entered into a five-year, non-revolving term loan facility of US$250 million which matures in June 2029.
In July 2024, we renewed approximately $8.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2026, which includes a one-year term out provision from July 2025. We also renewed approximately $7.8 billion of our five-year credit facilities, extending the maturity dates to July 2029. Further, we extended the maturity dates of our three-year credit facilities to July 2027.
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In July 2024, Enbridge Gas Ontario extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.
In July 2024, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2026, which includes a one-year term out provision from July 2025.
In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $859 million was unutilized as at September 30, 2024. As at December 31, 2023, we had $1.1 billion of uncommitted demand letter of credit facilities, of which $572 million was unutilized.
In October 2024, we increased our letter of credit facilities by $200 million.
As at September 30, 2024, our net available liquidity totaled $17.1 billion (December 31, 2023 - $23.0 billion), consisting of available credit facilities of $15.2 billion (December 31, 2023 - $17.1 billion) and unrestricted cash and cash equivalents of $1.9 billion (December 31, 2023 - $5.9 billion) as reported in the Consolidated Statements of Financial Position.
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at September 30, 2024, we were in compliance with all such debt covenant provisions.
LONG-TERM DEBT ISSUANCES
During the nine months ended September 30, 2024, we completed the following long-term debt issuances totaling US$5.1 billion and $1.8 billion:
Company
Issue Date
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
April 2024
5.25%
senior notes due April 2027
US$750
April 2024
5.30%
senior notes due April 2029
US$750
April 2024
5.63%
senior notes due April 2034
US$1,200
April 2024
5.95%
senior notes due April 2054
US$800
June 2024
7.38%
fixed-to-fixed subordinated notes due March 20551
US$500
June 2024
7.20%
fixed-to-fixed subordinated notes due June 20542
US$700
August 2024
4.21%
medium-term notes due February 2030
$600
August 2024
4.73%
medium-term notes due August 2034
$800
August 2024
5.32%
medium-term notes due August 2054
$400
Algonquin Gas Transmission, LLC
July 2024
5.95%
senior notes due July 2034
US$350
1For the initial 5.5 years, the notes carry a fixed interest rate. On March 15, 2030, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.12%.
2For the initial 9.75 years, the notes carry a fixed interest rate. On June 27, 2034, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 2.97%.
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LONG-TERM DEBT REPAYMENTS
During the nine months ended September 30, 2024, we completed the following long-term debt repayments totaling US$3.6 billion, $0.8 billion and €23 million:
Company
Repayment Date
Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
February 2024
Floating rate notes1
US$600
February 2024
2.15%
senior notes
US$400
March 2024
5.97%
senior notes2
US$700
June 2024
3.50%
senior notes
US$500
Enbridge Gas Inc.
August 2024
3.15
%
medium-term notes
$215
Enbridge Pipelines (Southern Lights) L.L.C.
June 2024
3.98%
senior notes
US$42
Enbridge Pipelines Inc.
February 2024
8.20%
debentures
$200
Enbridge Southern Lights LP
January and July 2024
4.01%
senior notes
$20
Westcoast Energy Inc.
September 2024
3.43%
medium-term notes
$350
Spectra Energy Partners, LP
March 2024
4.75%
senior notes
US$1,000
Blauracke GmbH
April 2024
2.10%
senior notes
€23
Algonquin Gas Transmission, LLC
July 2024
3.51%
senior notes
US$350
1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 63 basis points.
2The notes carried an original maturity date in March 2026, and were callable in March 2024, which was one year after their issuance.
Strong internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA.
There are no material restrictions on our cash. Total restricted cash of $133 million, as reported in the Consolidated Statements of Financial Position, primarily includes reinsurance security, cash collateral, future pipeline abandonment costs collected and held in trust, amounts received in respect of specific shipper commitments and capital projects. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us.
Excluding current maturities of long-term debt, as at September 30, 2024 and December 31, 2023, we had negative and positive working capital positions of $0.1 billion and $3.0 billion, respectively. During the nine months ended September 30, 2024, the major contributing factor to the negative working capital position was a decrease in cash as a result of the Acquisitions, while during the year ended December 31, 2023, the major contributing factor to the positive working capital position was due to the increase in cash associated with pre-funding of the Acquisitions. We maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due.
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SOURCES AND USES OF CASH
Nine months ended September 30,
2024
2023
(millions of Canadian dollars)
Operating activities
8,938
10,389
Investing activities
(15,915)
(3,503)
Financing activities
2,943
(5,146)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash
151
—
Net change in cash and cash equivalents and restricted cash
(3,883)
1,740
Significant sources and uses of cash for the nine months ended September 30, 2024 and 2023 are summarized below:
Operating Activities
The primary factors impacting cash provided by operating activities period-over-period include changes in our operating assets and liabilities in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments and cash receipts and payments generally. Cash provided by operating activities is also impacted by changes in earnings and certain infrequent or other non-operating factors, as discussed in Results of Operations, as well as Distributions from equity investments.
Investing Activities
Cash used in investing activities includes capital expenditures to execute our capital program, which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements. Cash used in investing activities is also impacted by acquisitions, dispositions and changes in contributions to, and distributions from, our equity investments. The increase in cash used in investing activities period-over-period was primarily due to the acquisitions of EOG, Questar, PSNC, and Tomorrow RNG, as well as our contributions to acquire an equity interest in the Whistler Parent JV, which were partially offset by proceeds received from the disposition of our interests in the Alliance Pipeline, Aux Sable and NRGreen.
Financing Activities
Cash provided by or used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, share redemptions and common share repurchases under our normal course issuer bid. Cash provided by or used in financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the increase in cash provided by financing activities period-over-period primarily include:
•net commercial paper and credit facility draws in 2024 when compared to net repayments during the same period in 2023;
•the ATM Program, resulting in the issuance of 51,298,629 common shares for aggregate net proceeds of $2.5 billion in 2024; and
•lower net repayments of short-term borrowings in 2024 when compared to the same period in 2023.
The factors above were partially offset by:
•higher long-term debt repayments and lower long-term debt issuances in 2024 when compared to the same period in 2023;
•the absence in 2024 of the public offering of common shares, which closed on September 8, 2023 for gross proceeds of $4.6 billion; and
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•increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding.
SUMMARIZED FINANCIAL INFORMATION
On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP) (together, the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes.
Consenting SEP notes and EEP notes under Guarantees
SEP Notes1
EEP Notes2
3.50% Senior Notes due 2025
5.88% Notes due 2025
3.38% Senior Notes due 2026
5.95% Notes due 2033
5.95% Senior Notes due 2043
6.30% Notes due 2034
4.50% Senior Notes due 2045
7.50% Notes due 2038
5.50% Notes due 2040
7.38% Notes due 2045
1As at September 30, 2024, the aggregate outstanding principal amount of SEP notes was approximately US$2.2 billion.
2As at September 30, 2024, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.
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Enbridge Notes under Guarantees
USD Denominated1
CAD Denominated2
2.50% Senior Notes due 2025
3.95% Senior Notes due 2024
2.50% Senior Notes due 2025
2.44% Senior Notes due 2025
4.25% Senior Notes due 2026
3.20% Senior Notes due 2027
1.60% Senior Notes due 2026
5.70% Senior Notes due 2027
5.90% Senior Notes due 2026
6.10% Senior Notes due 2028
3.70% Senior Notes due 2027
4.90% Senior Notes due 2028
5.25% Senior Notes due 2027
2.99% Senior Notes due 2029
6.00% Senior Notes due 2028
7.22% Senior Notes due 2030
3.13% Senior Notes due 2029
4.21% Senior Notes due 2030
5.30% Senior Notes due 2029
7.20% Senior Notes due 2032
6.20% Senior Notes due 2030
6.10% Sustainability-Linked Senior Notes due 2032
2.50% Sustainability-Linked Senior Notes due 2033
3.10% Sustainability-Linked Senior Notes due 2033
5.70% Sustainability-Linked Senior Notes due 2033
5.36% Sustainability-Linked Senior Notes due 2033
5.63% Senior Notes due 2034
4.73% Senior Notes due 2034
4.50% Senior Notes due 2044
5.57% Senior Notes due 2035
5.50% Senior Notes due 2046
5.75% Senior Notes due 2039
4.00% Senior Notes due 2049
5.12% Senior Notes due 2040
3.40% Senior Notes due 2051
4.24% Senior Notes due 2042
6.70% Senior Notes due 2053
4.57% Senior Notes due 2044
5.95% Senior Notes due 2054
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
1As at September 30, 2024, the aggregate outstanding principal amount of the Enbridge US dollar-denominated notes was approximately US$17.0 billion.
2As at September 30, 2024, the aggregate outstanding principal amount of the Enbridge Canadian dollar-denominated notes was approximately $12.8 billion.
Rule 3-10 of the US SEC Regulation S-X provides an exemption from the reporting requirements of the Exchange Act for fully consolidated subsidiary issuers of guaranteed securities and subsidiary guarantors and allows for summarized financial information in lieu of filing separate financial statements for each of the Partnerships.
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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
Nine months ended September 30,
2024
(millions of Canadian dollars)
Operating loss
(42)
Earnings
943
Earnings attributable to common shareholders
657
Summarized Combined Statements of Financial Position
September 30, 2024
December 31, 2023
(millions of Canadian dollars)
Cash and cash equivalents
1,712
6,525
Accounts receivable from affiliates
3,768
3,440
Short-term loans receivable from affiliates
3,388
3,291
Trade accounts receivable and unbilled revenue
45
—
Other current assets
363
491
Long-term loans receivable from affiliates
54,413
45,702
Other long-term assets
1,778
3,303
Accounts payable to affiliates
2,209
2,264
Short-term loans payable to affiliates
1,207
807
Trade payables and accrued liabilities
419
743
Other current liabilities
5,003
7,256
Long-term loans payable to affiliates
36,371
35,556
Other long-term liabilities
58,281
52,096
The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-Guarantors.
Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee:
•received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;
•was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
•intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.
The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under US federal or state law.
Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.
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Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:
•any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;
•the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;
•the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement;
•with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;
•with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or
•with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.
The guarantee obligations of Enbridge will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.
The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities.
LEGAL AND OTHER UPDATES
MICHIGAN LINE 5 DUAL PIPELINES - STRAITS OF MACKINAC EASEMENT
Michigan Attorney General Lawsuit
In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit Court (the Circuit Court) that requests the Circuit Court to declare the easement granted to Enbridge in 1953 for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits. On December 15, 2021, Enbridge removed the case to the US District Court in the Western District of Michigan (US District Court). The removal of the AG's case to federal court followed a November 16, 2021, ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force Line 5's shutdown raised important federal issues that should be heard in federal court. The AG subsequently filed various motions and appeals (opposed by Enbridge) to remand the case.
On June 17, 2024, the 6th Circuit Court of Appeals (6th Circuit) overturned the US District Court’s decision and remanded the AG's lawsuit against Enbridge back to the Circuit Court. On July 15, 2024, Enbridge filed a petition for rehearing, which was denied on August 16, 2024.
A decision on the merits of the AG's case is not anticipated in the next twelve months, as the matter is still in the pretrial motion stage of the case.
Enbridge Lawsuit
On November 24, 2020, Enbridge filed in the US District Court a Complaint for Declaratory and Injunctive Relief requesting that the US District Court enjoin the State of Michigan Officials from taking any action to prevent or impede the operation of Line 5. The Government of Canada has filed a supplemental brief reiterating that the 1977 Transit Pipelines Treaty between the US and Canada has been invoked and that the matter is of great importance to Canada. This matter remains in federal court.
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In January 2022, the State of Michigan Officials filed a motion to dismiss Enbridge's Complaint and Enbridge filed a motion for Summary Judgment. On July 5, 2024, the US District Court issued an Order denying the Michigan officials' motion to dismiss Enbridge's Complaint, and the State of Michigan Officials filed for an immediate appeal to the 6th Circuit. On August 29, 2024, the US District Court issued an order staying the case, pending the 6th Circuit’s decision, which is expected in 2025.
DAKOTA ACCESS PIPELINE
We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of the Dakota Access Pipeline (DAPL). The Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court for the District of Columbia (the DC District Court) contesting the lawfulness of the Army Corps easement for DAPL, including the adequacy of the Army Corps' environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018.
On June 14, 2017, the DC District Court found the Army Corps' environmental review to be deficient and ordered the Army Corps to conduct further study concerning spill risks from DAPL.
On March 25, 2020, in response to amended complaints from the Tribes, the DC District Court found that the Army Corps' subsequent environmental review completed in August 2018 was also deficient and ordered the Army Corps to prepare an Environmental Impact Statement (EIS) to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July 6, 2020, the DC District Court issued an order vacating the Army Corps' easement for DAPL and ordering that the pipeline be shut down by August 5, 2020. On that day, the US Court of Appeals for the District of Columbia Circuit stayed the DC District Court's July 6 order to shut down and empty the pipeline.
On January 26, 2021, the US Court of Appeals affirmed the DC District Court's decision, holding that the Army Corps is required to prepare an EIS and that the Army Corps' easement for DAPL is vacated. The US Supreme Court subsequently denied the request of Dakota Access, LLC to review the decision that an EIS is required. The US Court of Appeals also determined that, absent an injunction proceeding, the DC District Court could not order DAPL's operations to cease. While not an issue before, the US Court of Appeals also recognized that the Army Corps could consider whether to allow DAPL to continue to operate in the absence of an easement. The Army Corps earlier indicated that it did not intend to exercise its authority to bar DAPL's continued operation, notwithstanding the absence of an easement.
On September 8, 2023, the Army Corps issued its draft EIS, which assesses the impacts of DAPL under five alternative scenarios: denying the easement removing the pipeline; denying the easement and leaving the pipeline in place; granting the easement with the prior conditions (which allow for the ongoing operation, maintenance and ultimate removal of the pipeline and its related facilities); granting the easement with some new safety conditions; and rerouting the pipeline. The Army Corps did not identify a preferred alternative. The public comment period that commenced on the issuance of the draft EIS closed
on December 13, 2023.The pipeline remains operational while the environmental review process continues.
On October 15, 2024, the Standing Rock Sioux Tribe filed a complaint in the DC District Court against the Army Corps, among others, seeking a permanent injunction prohibiting the continued operation of DAPL. The main allegations of the complaint are that the Army Corps is unlawfully permitting DAPL to continue to operate without an easement and without a determination under the National Environmental Policy Act, and that the Army Corps has failed to require that a compliant Facility Response Plan be submitted.Several of the claims are similar to those in the litigation described above.
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OTHER LITIGATION
We and our subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.
TAX MATTERS
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.
CHANGES IN ACCOUNTING POLICIES
Refer to Part I. Item 1. Financial Statements - Note 2. Changes in Accounting Policies.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our exposure to market risk is described in Part II. Item 7A.Quantitative and Qualitative Disclosures About Market Risk of our annual report on Form 10-K for the year ended December 31, 2023. We believe our exposure to market risk has not changed materially since then.
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ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as at September 30, 2024, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.
Changes in Internal Control over Financial Reporting
Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended September 30, 2024 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
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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, 2023, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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ITEM 5. OTHER INFORMATION
Certain of our officers and directors have made elections to participate in, and are participating in, our compensation and benefit plans involving Enbridge stock, such as our 401(k) plan and directors' compensation plan, and may from time to time make elections which may be designed to satisfy the affirmative defense conditions of Rule 10b5-1 under the Exchange Act or may constitute non-Rule 10b5-1 trading arrangements (as defined in Item 408(c) of Regulation S-K).
ITEM 6. EXHIBITS
Each exhibit identified below is included as a part of this quarterly report. Exhibits included in this filing are designated by an asterisk ("*"); all exhibits not so designated are incorporated by reference to a prior filing as indicated. Exhibits designated with a "^" are furnished herewith.
Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included 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:
November 1, 2024
By:
/s/ Gregory L. Ebel
Gregory L. Ebel
President and Chief Executive Officer
(Principal Executive Officer)
Date:
November 1, 2024
By:
/s/ Patrick R. Murray
Patrick R. Murray
Executive Vice President and Chief Financial Officer