ITEM 1. FINANCIAL STATEMENTS
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| 2022 | 2021 | | 2022 | 2021 |
| (unaudited; millions of Canadian dollars, except per share amounts) | | | | | |
| Operating revenues | | | | | |
| Commodity sales | 6,415 | | 7,279 | | | 22,880 | | 20,042 | |
| Gas distribution sales | 695 | | 492 | | | 3,698 | | 2,769 | |
| Transportation and other services | 4,463 | | 3,695 | | | 13,307 | | 11,740 | |
Total operating revenues (Note 3) | 11,573 | | 11,466 | | | 39,885 | | 34,551 | |
| Operating expenses | | | | | |
| Commodity costs | 6,300 | | 7,347 | | | 22,772 | | 19,975 | |
| Gas distribution costs | 330 | | 120 | | | 2,242 | | 1,359 | |
| Operating and administrative | 2,089 | | 1,667 | | | 5,958 | | 4,710 | |
| Depreciation and amortization | 1,076 | | 944 | | | 3,195 | | 2,805 | |
| | | | | |
| Total operating expenses | 9,795 | | 10,078 | | | 34,167 | | 28,849 | |
| Operating income | 1,778 | | 1,388 | | | 5,718 | | 5,702 | |
| Income from equity investments | 536 | | 440 | | | 1,537 | | 1,187 | |
| Impairment of equity investments | — | | (111) | | | — | | (111) | |
| Other income/(expense) | | | | | |
| Net foreign currency gain/(loss) | (1,023) | | (165) | | | (1,235) | | 146 | |
Gain on joint venture merger transaction (Note 6) | 1,076 | | — | | | 1,076 | | — | |
| Other | 140 | | 109 | | | 311 | | 300 | |
| Interest expense | (806) | | (648) | | | (2,316) | | (1,923) | |
| Earnings before income taxes | 1,701 | | 1,013 | | | 5,091 | | 5,301 | |
Income tax expense | (318) | | (199) | | | (1,044) | | (952) | |
| Earnings | 1,383 | | 814 | | | 4,047 | | 4,349 | |
| Earnings attributable to noncontrolling interests | (21) | | (34) | | | (61) | | (93) | |
| Earnings attributable to controlling interests | 1,362 | | 780 | | | 3,986 | | 4,256 | |
| Preference share dividends | (83) | | (98) | | | (330) | | (280) | |
| Earnings attributable to common shareholders | 1,279 | | 682 | | | 3,656 | | 3,976 | |
Earnings per common share attributable to common shareholders (Note 5) | 0.63 | | 0.34 | | | 1.80 | | 1.97 | |
Diluted earnings per common share attributable to common shareholders (Note 5) | 0.63 | | 0.34 | | | 1.80 | | 1.96 | |
The accompanying notes are an integral part of these interim consolidated financial statements.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| | 2022 | 2021 | | 2022 | 2021 |
| (unaudited; millions of Canadian dollars) | | | | | |
| Earnings | 1,383 | | 814 | | | 4,047 | | 4,349 | |
| Other comprehensive income/(loss), net of tax | | | | | |
| Change in unrealized gain/(loss) on cash flow hedges | 171 | | (16) | | | 817 | | 197 | |
| Change in unrealized gain/(loss) on net investment hedges | (934) | | (206) | | | (1,187) | | 16 | |
| Other comprehensive loss from equity investees | (7) | | (30) | | | (7) | | (28) | |
| Excluded components of fair value hedges | (33) | | (1) | | | (38) | | (3) | |
| Reclassification to earnings of loss on cash flow hedges | 36 | | 55 | | | 145 | | 168 | |
| Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts | (2) | | 5 | | | (7) | | 16 | |
| Reclassification to earnings of loss on equity investees | 16 | | — | | | 16 | | — | |
| Foreign currency translation adjustments | 4,135 | | 1,281 | | | 5,308 | | (350) | |
| Other comprehensive income, net of tax | 3,382 | | 1,088 | | | 5,047 | | 16 | |
| Comprehensive income | 4,765 | | 1,902 | | | 9,094 | | 4,365 | |
| Comprehensive income attributable to noncontrolling interests | (116) | | (62) | | | (187) | | (68) | |
| Comprehensive income attributable to controlling interests | 4,649 | | 1,840 | | | 8,907 | | 4,297 | |
| Preference share dividends | (83) | | (98) | | | (330) | | (280) | |
| Comprehensive income attributable to common shareholders | 4,566 | | 1,742 | | | 8,577 | | 4,017 | |
The accompanying notes are an integral part of these interim consolidated financial statements.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| | 2022 | 2021 | | 2022 | 2021 |
| (unaudited; millions of Canadian dollars, except per share amounts) | | | | | |
| Preference shares | | | | | |
| Balance at beginning of period | 6,818 | | 7,747 | | | 7,747 | | 7,747 | |
| Redemption of preference shares | — | | — | | | (929) | | — | |
| Balance at end of period | 6,818 | | 7,747 | | | 6,818 | | 7,747 | |
| Common shares | | | | | |
| Balance at beginning of period | 64,755 | | 64,780 | | | 64,799 | | 64,768 | |
| Shares issued on exercise of stock options | 2 | | 10 | | | 50 | | 22 | |
| Share purchases at stated value | — | | — | | | (88) | | — | |
| Other | — | | — | | | (4) | | — | |
| Balance at end of period | 64,757 | | 64,790 | | | 64,757 | | 64,790 | |
| Additional paid-in capital | | | | | |
| Balance at beginning of period | 305 | | 324 | | | 365 | | 277 | |
| Stock-based compensation | 9 | | 7 | | | 27 | | 23 | |
| Options exercised | (2) | | (7) | | | (47) | | (15) | |
| Change in reciprocal interest | — | | — | | | — | | 39 | |
| Other | — | | — | | | (33) | | — | |
| Balance at end of period | 312 | | 324 | | | 312 | | 324 | |
| Deficit | | | | | |
| Balance at beginning of period | (10,418) | | (8,388) | | | (10,989) | | (9,995) | |
| Earnings attributable to controlling interests | 1,362 | | 780 | | | 3,986 | | 4,256 | |
| Preference share dividends | (83) | | (98) | | | (330) | | (280) | |
| Common share dividends declared | (1,741) | | (1,692) | | | (3,484) | | (3,384) | |
| Dividends paid to reciprocal shareholder | — | | 1 | | | — | | 6 | |
| Share purchases in excess of stated value | — | | — | | | (63) | | — | |
| | | | | |
| Balance at end of period | (10,880) | | (9,397) | | | (10,880) | | (9,397) | |
Accumulated other comprehensive income/(loss) (Note 8) | | | | | |
| Balance at beginning of period | 538 | | (2,420) | | | (1,096) | | (1,401) | |
| Other comprehensive income attributable to common shareholders, net of tax | 3,287 | | 1,060 | | | 4,921 | | 41 | |
| Balance at end of period | 3,825 | | (1,360) | | | 3,825 | | (1,360) | |
| Reciprocal shareholding | | | | | |
| Balance at beginning of period | — | | (17) | | | — | | (29) | |
| Change in reciprocal interest | — | | — | | | — | | 12 | |
| Balance at end of period | — | | (17) | | | — | | (17) | |
| Total Enbridge Inc. shareholders’ equity | 64,832 | | 62,087 | | | 64,832 | | 62,087 | |
| Noncontrolling interests | | | | | |
| Balance at beginning of period | 2,539 | | 2,870 | | | 2,542 | | 2,996 | |
| Earnings attributable to noncontrolling interests | 21 | | 34 | | | 61 | | 93 | |
| Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax | | | | | |
| Change in unrealized loss on cash flow hedges | (8) | | (9) | | | (14) | | (15) | |
| Foreign currency translation adjustments | 103 | | 37 | | | 140 | | (10) | |
| | 95 | | 28 | | | 126 | | (25) | |
| Comprehensive income attributable to noncontrolling interests | 116 | | 62 | | | 187 | | 68 | |
| Distributions | (62) | | (67) | | | (189) | | (210) | |
| Contributions | 2 | | 4 | | | 10 | | 13 | |
| Redemption of noncontrolling interests | — | | (293) | | | — | | (293) | |
| Other | 3 | | (1) | | | 48 | | 1 | |
| Balance at end of period | 2,598 | | 2,575 | | | 2,598 | | 2,575 | |
| Total equity | 67,430 | | 64,662 | | | 67,430 | | 64,662 | |
| Dividends paid per common share | 0.860 | | 0.835 | | | 2.580 | | 2.505 | |
The accompanying notes are an integral part of these interim consolidated financial statements.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | |
| Nine months ended
September 30, |
| | 2022 | 2021 |
| (unaudited; millions of Canadian dollars) | | |
| Operating activities | | |
| Earnings | 4,047 | | 4,349 | |
| Adjustments to reconcile earnings to net cash provided by operating activities: | | |
| Depreciation and amortization | 3,195 | | 2,805 | |
| Deferred income tax expense | 600 | | 789 | |
Unrealized derivative fair value loss, net (Note 9) | 1,691 | | 86 | |
| Income from equity investments | (1,537) | | (1,187) | |
| Distributions from equity investments | 1,293 | | 1,197 | |
| Impairment of equity investments | — | | 111 | |
| | |
Gain on joint venture merger transaction (Note 6) | (1,076) | | — | |
| Other | 6 | | (128) | |
| Changes in operating assets and liabilities | (602) | | (656) | |
| Net cash provided by operating activities | 7,617 | | 7,366 | |
| Investing activities | | |
| Capital expenditures | (3,204) | | (5,887) | |
| Long-term investments and restricted long-term investments | (566) | | (241) | |
| Distributions from equity investments in excess of cumulative earnings | 426 | | 295 | |
| Additions to intangible assets | (131) | | (185) | |
Acquisition (Note 6) | (295) | | — | |
Proceeds from joint venture merger transaction (Note 6) | 522 | | — | |
| Proceeds from disposition | — | 122 |
| Affiliate loans, net | 90 | | 19 | |
| Other | — | | (30) | |
| Net cash used in investing activities | (3,158) | | (5,907) | |
| Financing activities | | |
| Net change in short-term borrowings | 367 | | 84 | |
| Net change in commercial paper and credit facility draws | 386 | | (32) | |
| Debenture and term note issues, net of issue costs | 4,739 | | 6,135 | |
| Debenture and term note repayments | (2,244) | | (1,888) | |
| Contributions from noncontrolling interests | 10 | | 13 | |
| Distributions to noncontrolling interests | (189) | | (210) | |
| Common shares issued | 3 | | 3 | |
| Common shares repurchased | (151) | | — | |
| Preference share dividends | (254) | | (274) | |
| Common share dividends | (5,226) | | (5,074) | |
| Redemption of preferred shares held by subsidiary | — | | (115) | |
| Redemption of preference shares | (1,003) | | — | |
| Other | (223) | | (64) | |
| Net cash used in financing activities | (3,785) | | (1,422) | |
Effect of translation of foreign denominated cash and cash equivalents and restricted cash | 63 | | (12) | |
| Net change in cash and cash equivalents and restricted cash | 737 | | 25 | |
| Cash and cash equivalents and restricted cash at beginning of period | 320 | | 490 | |
| Cash and cash equivalents and restricted cash at end of period | 1,057 | | 515 | |
The accompanying notes are an integral part of these interim consolidated financial statements.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
| | | | | | | | |
| September 30,
2022 | December 31,
2021 |
| (unaudited; millions of Canadian dollars; number of shares in millions) | | |
| Assets | | |
| Current assets | | |
| Cash and cash equivalents | 1,021 | | 286 | |
| Restricted cash | 36 | | 34 | |
| Accounts receivable and other | 7,168 | | 6,862 | |
| Accounts receivable from affiliates | 236 | | 107 | |
| Inventory | 2,346 | | 1,670 | |
| 10,807 | | 8,959 | |
| Property, plant and equipment, net | 105,251 | | 100,067 | |
| Long-term investments | 15,346 | | 13,324 | |
| Restricted long-term investments | 569 | | 630 | |
| Deferred amounts and other assets | 9,941 | | 8,613 | |
| Intangible assets, net | 4,124 | | 4,008 | |
| Goodwill | 35,274 | | 32,775 | |
| Deferred income taxes | 463 | | 488 | |
| Total assets | 181,775 | | 168,864 | |
| | |
| Liabilities and equity | | |
| Current liabilities | | |
| Short-term borrowings | 1,882 | | 1,515 | |
| Accounts payable and other | 8,867 | | 9,767 | |
| Accounts payable to affiliates | 144 | | 90 | |
| Interest payable | 641 | | 693 | |
| Current portion of long-term debt | 6,376 | | 6,164 | |
| 17,910 | | 18,229 | |
| Long-term debt | 73,960 | | 67,961 | |
| Other long-term liabilities | 9,133 | | 7,617 | |
| Deferred income taxes | 13,342 | | 11,689 | |
| 114,345 | | 105,496 | |
Contingencies (Note 12) | | |
| Equity | | |
| Share capital | | |
| Preference shares | 6,818 | | 7,747 | |
Common shares (2,025 and 2,026 outstanding at September 30, 2022 and December 31, 2021, respectively) | 64,757 | | 64,799 | |
| Additional paid-in capital | 312 | | 365 | |
| Deficit | (10,880) | | (10,989) | |
Accumulated other comprehensive income/(loss) (Note 8) | 3,825 | | (1,096) | |
| | |
| Total Enbridge Inc. shareholders’ equity | 64,832 | | 60,826 | |
| Noncontrolling interests | 2,598 | | 2,542 | |
| 67,430 | | 63,368 | |
| Total liabilities and equity | 181,775 | | 168,864 | |
The accompanying notes are an integral part of these interim consolidated financial statements.
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. BASIS OF PRESENTATION
The accompanying unaudited interim consolidated financial statements of Enbridge Inc. (“we”, “our”, “us” and “Enbridge”) have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2021. 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, 2021, except for the adoption of new standards (Note 2). Amounts are stated in Canadian dollars unless otherwise noted.
Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as supply of and demand for crude oil and natural gas, and may not be indicative of annual results.
Certain comparative figures in our interim consolidated financial statements have been reclassified to conform to the current year's presentation.
2. CHANGES IN ACCOUNTING POLICIES
ADOPTION OF NEW ACCOUNTING STANDARDS
Disclosures About Government Assistance
Effective January 1, 2022, we adopted Accounting Standards Update (ASU) 2021-10 on a prospective basis. The new standard was issued in November 2021 to increase the transparency of government assistance to business entities. The ASU adds new disclosure requirements for transactions with governments that are accounted for using a grant or contribution accounting model by analogy. The required disclosures include information about the nature of transactions, accounting policy applied, impacted financial statement line items and significant terms and conditions. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Accounting for Certain Lessor Leases with Variable Lease Payments
Effective January 1, 2022, we adopted ASU 2021-05 on a prospective basis. The new standard was issued in July 2021 to amend lessor accounting for certain leases with variable lease payments that do not depend on a reference index or a rate and would have resulted in the recognition of a loss at lease commencement if classified as a sales-type or a direct financing lease. The ASU amends the classification requirements of such leases for lessors to result in an operating lease classification. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Accounting for Modifications or Exchanges of Certain Equity-Classified Contracts
Effective January 1, 2022, we adopted ASU 2021-04 on a prospective basis. The new standard was issued in May 2021 to clarify issuer accounting for modifications or exchanges of freestanding equity-classified written call options that remain equity classified after modification or exchange. The ASU requires an issuer to determine the accounting for the modification or exchange based on the economic substance of the modification or exchange. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity
Effective January 1, 2022, we adopted ASU 2020-06 on a modified retrospective basis. The new standard was issued in August 2020 to simplify accounting for certain financial instruments. The ASU eliminates the current models that require separation of beneficial conversion and cash conversion features from convertible instruments and simplifies the derivative scope exception guidance pertaining to equity classification of contracts in an entity’s own equity. The ASU also introduces additional disclosures for convertible debt and freestanding instruments that are indexed to and settled in an entity’s own equity. The ASU amends the diluted earnings per share guidance, including the requirement to use if-converted method for all convertible instruments and an update for instruments that can be settled in either cash or shares. The adoption of this ASU did not have a material impact on our consolidated financial statements.
3. REVENUE
REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
| | | | | | | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated |
Three months ended
September 30, 2022 |
| (millions of Canadian dollars) | | | | | | | |
| Transportation revenue | 2,962 | | 1,264 | | 143 | | — | | — | | — | | 4,369 | |
| Storage and other revenue | 58 | | 91 | | 63 | | — | | — | | — | | 212 | |
| | | | | | | |
| Gas distribution revenue | — | | — | | 699 | | — | | — | | — | | 699 | |
| Electricity and transmission revenue | — | | — | | — | | 68 | | — | | — | | 68 | |
| | | | | | | |
Total revenue from contracts with customers | 3,020 | | 1,355 | | 905 | | 68 | | — | | — | | 5,348 | |
| Commodity sales | — | | — | | — | | — | | 6,415 | | — | | 6,415 | |
Other revenue1,2 | (258) | | 10 | | 3 | | 54 | | — | | 1 | | (190) | |
| Intersegment revenue | 137 | | 1 | | 1 | | (2) | | 4 | | (141) | | — | |
| Total revenue | 2,899 | | 1,366 | | 909 | | 120 | | 6,419 | | (140) | | 11,573 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated |
Three months ended
September 30, 2021 |
| (millions of Canadian dollars) | | | | | | | |
| Transportation revenue | 2,340 | | 1,081 | | 128 | | — | | — | | — | | 3,549 | |
| Storage and other revenue | 33 | | 58 | | 50 | | — | | — | | — | | 141 | |
| Gas gathering and processing revenue | — | | 15 | | — | | — | | — | | — | | 15 | |
| Gas distribution revenue | — | | — | | 496 | | — | | — | | — | | 496 | |
| Electricity and transmission revenue | — | | — | | — | | 44 | | — | | — | | 44 | |
| | | | | | | |
Total revenue from contracts with customers | 2,373 | | 1,154 | | 674 | | 44 | | — | | — | | 4,245 | |
| Commodity sales | — | | — | | — | | — | | 7,279 | | — | | 7,279 | |
Other revenue1,2 | (143) | | 4 | | 24 | | 78 | | (1) | | (20) | | (58) | |
| Intersegment revenue | 140 | | 1 | | (11) | | — | | 12 | | (142) | | — | |
| Total revenue | 2,370 | | 1,159 | | 687 | | 122 | | 7,290 | | (162) | | 11,466 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated |
Nine months ended
September 30, 2022 |
| (millions of Canadian dollars) | | | | | | | |
| Transportation revenue | 8,212 | | 3,658 | | 551 | | — | | — | | — | | 12,421 | |
| Storage and other revenue | 173 | | 258 | | 209 | | — | | — | | — | | 640 | |
| Gas gathering and processing revenue | — | | 21 | | — | | — | | — | | — | | 21 | |
| Gas distribution revenue | — | | — | | 3,716 | | — | | — | | — | | 3,716 | |
| Electricity and transmission revenue | — | | — | | — | | 211 | | — | | — | | 211 | |
| | | | | | | |
Total revenue from contracts with customers | 8,385 | | 3,937 | | 4,476 | | 211 | | — | | — | | 17,009 | |
| Commodity sales | — | | — | | — | | — | | 22,880 | | — | | 22,880 | |
Other revenue1,2 | (225) | | 28 | | (30) | | 222 | | — | | 1 | | (4) | |
| Intersegment revenue | 432 | | 2 | | 12 | | (2) | | 14 | | (458) | | — | |
| Total revenue | 8,592 | | 3,967 | | 4,458 | | 431 | | 22,894 | | (457) | | 39,885 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated |
Nine months ended
September 30, 2021 |
| (millions of Canadian dollars) | | | | | | | |
| Transportation revenue | 6,826 | | 3,248 | | 494 | | — | | — | | — | | 10,568 | |
| Storage and other revenue | 96 | | 195 | | 159 | | — | | — | | — | | 450 | |
| Gas gathering and processing revenue | — | | 32 | | — | | — | | — | | — | | 32 | |
| Gas distribution revenue | — | | — | | 2,755 | | — | | — | | — | | 2,755 | |
| Electricity and transmission revenue | — | | — | | — | | 125 | | — | | — | | 125 | |
| | | | | | | |
Total revenue from contracts with customers | 6,922 | | 3,475 | | 3,408 | | 125 | | — | | — | | 13,930 | |
| Commodity sales | — | | — | | — | | — | | 20,042 | | — | | 20,042 | |
Other revenue1,2 | 284 | | 25 | | 42 | | 246 | | — | | (18) | | 579 | |
| Intersegment revenue | 410 | | 1 | | 13 | | — | | 26 | | (450) | | — | |
| Total revenue | 7,616 | | 3,501 | | 3,463 | | 371 | | 20,068 | | (468) | | 34,551 | |
1Includes mark-to-market losses from our hedging program for the three months ended September 30, 2022 and 2021 of $345 million and $225 million, respectively. For the nine months ended September 30, 2022 and 2021, Other revenue includes a $483 million mark-to-market loss and a $36 million mark-to-market gain, respectively.
2Includes revenues from lease contracts for the three months ended September 30, 2022 and 2021 of $128 million and $140 million, respectively, and for the nine months ended September 30, 2022 and 2021 of $435 million and $442 million, respectively.
We disaggregate revenues into categories which represent our principal performance obligations within each business segment. These revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.
Contract Balances
| | | | | | | | | | | |
| Contract Receivables | Contract Assets | Contract Liabilities |
| (millions of Canadian dollars) | | | |
| Balance as at September 30, 2022 | 2,307 | | 233 | | 2,201 | |
| Balance as at December 31, 2021 | 2,369 | | 213 | | 1,898 | |
Contract receivables represent the amount of receivables derived from contracts with customers.
Contract assets represent the amount of revenues which have been recognized in advance of payments received for performance obligations we have fulfilled (or 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, 2022 included in contract liabilities at the beginning of the period is $57 million and $139 million, respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenues, during the three and nine months ended September 30, 2022 were $138 million and $366 million, respectively.
Performance Obligations
There were no material revenues recognized in the three and nine months ended September 30, 2022 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 are $59.3 billion, of which $1.9 billion and $6.4 billion are expected to be recognized during the remaining three months ending December 31, 2022 and the year ending December 31, 2023, 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.
Variable Consideration
During the three and nine months ended September 30, 2022, revenue for the Canadian Mainline has been recognized in accordance with the terms of the Competitive Tolling Settlement, which expired on June 30, 2021. The tolls in place on June 30, 2021 continue on an interim basis until a new commercial arrangement is implemented and are subject to finalization and adjustment applicable to the interim period, if any. Due to the uncertainty of adjustment to tolling pursuant to a Canada Energy Regulator (CER) decision and potential customer negotiations, interim toll revenue recognized during the three and nine months ended September 30, 2022 is considered variable consideration.
Recognition and Measurement of Revenues
| | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | | Consolidated |
| Three months ended September 30, 2022 |
| (millions of Canadian dollars) | | | | | | |
Revenues from products transferred at a point in time | — | | — | | 41 | | — | | | 41 | |
Revenues from products and services transferred over time1 | 3,020 | | 1,355 | | 864 | | 68 | | | 5,307 | |
Total revenue from contracts with customers | 3,020 | | 1,355 | | 905 | | 68 | | | 5,348 | |
| | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | | Consolidated |
| Three months ended September 30, 2021 |
| (millions of Canadian dollars) | | | | | | |
Revenues from products transferred at a point in time | — | | — | | 13 | | — | | | 13 | |
Revenues from products and services transferred over time1 | 2,373 | | 1,154 | | 661 | | 44 | | | 4,232 | |
Total revenue from contracts with customers | 2,373 | | 1,154 | | 674 | | 44 | | | 4,245 | |
| | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | | Consolidated |
| Nine months ended September 30, 2022 |
| (millions of Canadian dollars) | | | | | | |
Revenues from products transferred at a point in time | — | | — | | 77 | | — | | | 77 | |
Revenues from products and services transferred over time1 | 8,385 | | 3,937 | | 4,399 | | 211 | | | 16,932 | |
Total revenue from contracts with customers | 8,385 | | 3,937 | | 4,476 | | 211 | | | 17,009 | |
| | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | | Consolidated |
| Nine months ended September 30, 2021 |
| (millions of Canadian dollars) | | | | | | |
Revenues from products transferred at a point in time | — | | — | | 47 | | — | | | 47 | |
Revenues from products and services transferred over time1 | 6,922 | | 3,475 | | 3,361 | | 125 | | | 13,883 | |
Total revenue from contracts with customers | 6,922 | | 3,475 | | 3,408 | | 125 | | | 13,930 | |
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
| | | | | | | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated |
Three months ended
September 30, 2022 |
| (millions of Canadian dollars) | | | | | | | |
| Operating revenues | 2,899 | | 1,366 | | 909 | | 120 | | 6,419 | | (140) | | 11,573 | |
| Commodity and gas distribution costs | 27 | | — | | (327) | | (5) | | (6,465) | | 140 | | (6,630) | |
| Operating and administrative | (1,173) | | (545) | | (311) | | (58) | | (9) | | 7 | | (2,089) | |
| | | | | | | |
| | | | | | | |
| Income from equity investments | 193 | | 321 | | — | | 22 | | — | | — | | 536 | |
| | | | | | | |
Gain on joint venture merger transaction (Note 6) | — | | 1,076 | | — | | — | | — | | — | | 1,076 | |
| Other income/(expense) | — | | 33 | | 15 | | 26 | | (15) | | (942) | | (883) | |
| Earnings/(loss) before interest, income taxes and depreciation and amortization | 1,946 | | 2,251 | | 286 | | 105 | | (70) | | (935) | | 3,583 | |
| Depreciation and amortization | | | | | | | (1,076) | |
| Interest expense | | | | | | | (806) | |
| Income tax expense | | | | | | | (318) | |
| Earnings | | | | | | | 1,383 | |
Capital expenditures1 | 268 | | 525 | | 405 | | 9 | | — | | 8 | | 1,215 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated |
| Three months ended September 30, 2021 |
| (millions of Canadian dollars) | | | | | | | |
| Operating revenues | 2,370 | | 1,159 | | 687 | | 122 | | 7,290 | | (162) | | 11,466 | |
| Commodity and gas distribution costs | (6) | | — | | (135) | | — | | (7,485) | | 159 | | (7,467) | |
| Operating and administrative | (919) | | (445) | | (280) | | (51) | | (13) | | 41 | | (1,667) | |
| | | | | | | |
| | | | | | | |
| Income/(loss) from equity investments | 226 | | 211 | | (12) | | 15 | | — | | — | | 440 | |
| Impairment of equity investments | — | | (111) | | — | | — | | — | | — | | (111) | |
| Other income/(expense) | 2 | | 70 | | 22 | | 5 | | 4 | | (159) | | (56) | |
| Earnings/(loss) before interest, income taxes and depreciation and amortization | 1,673 | | 884 | | 282 | | 91 | | (204) | | (121) | | 2,605 | |
| Depreciation and amortization | | | | | | | (944) | |
| Interest expense | | | | | | | (648) | |
| Income tax expense | | | | | | | (199) | |
| Earnings | | | | | | | 814 | |
Capital expenditures1 | 1,203 | | 602 | | 359 | | — | | 1 | | 20 | | 2,185 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Nine months ended
September 30, 2022 | Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated |
| (millions of Canadian dollars) | | | | | | | |
| Operating revenues | 8,592 | | 3,967 | | 4,458 | | 431 | | 22,894 | | (457) | | 39,885 | |
| Commodity and gas distribution costs | — | | — | | (2,258) | | (13) | | (23,197) | | 454 | | (25,014) | |
| Operating and administrative | (3,096) | | (1,620) | | (891) | | (159) | | (34) | | (158) | | (5,958) | |
| | | | | | | |
| | | | | | | |
| Income/(loss) from equity investments | 561 | | 877 | | 1 | | 100 | | — | | (2) | | 1,537 | |
| | | | | | | |
Gain on joint venture merger transaction (Note 6) | — | | 1,076 | | — | | — | | — | | — | | 1,076 | |
| Other income/(expense) | 36 | | 84 | | 58 | | 30 | | (11) | | (1,121) | | (924) | |
| Earnings/(loss) before interest, income taxes and depreciation and amortization | 6,093 | | 4,384 | | 1,368 | | 389 | | (348) | | (1,284) | | 10,602 | |
| Depreciation and amortization | | | | | | | (3,195) | |
| Interest expense | | | | | | | (2,316) | |
| Income tax expense | | | | | | | (1,044) | |
| Earnings | | | | | | | 4,047 | |
Capital expenditures1 | 1,086 | | 1,087 | | 1,005 | | 26 | | — | | 32 | | 3,236 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Nine months ended
September 30, 2021 | Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated |
| (millions of Canadian dollars) | | | | | | | |
| Operating revenues | 7,616 | | 3,501 | | 3,463 | | 371 | | 20,068 | | (468) | | 34,551 | |
| Commodity and gas distribution costs | (16) | | — | | (1,392) | | — | | (20,405) | | 479 | | (21,334) | |
| Operating and administrative | (2,411) | | (1,303) | | (794) | | (131) | | (36) | | (35) | | (4,710) | |
| | | | | | | |
| | | | | | | |
| Income from equity investments | 560 | | 525 | | 37 | | 65 | | — | | — | | 1,187 | |
| Impairment of equity investments | — | | (111) | | | | — | | | (111) | |
| Other income/(expense) | 7 | | 113 | | 60 | | 57 | | (6) | | 215 | | 446 | |
| Earnings/(loss) before interest, income taxes and depreciation and amortization | 5,756 | | 2,725 | | 1,374 | | 362 | | (379) | | 191 | | 10,029 | |
| Depreciation and amortization | | | | | | | (2,805) | |
| Interest expense | | | | | | | (1,923) | |
| Income tax expense | | | | | | | (952) | |
| Earnings | | | | | | | 4,349 | |
Capital expenditures1 | 3,385 | | 1,631 | | 878 | | 7 | | 1 | | 42 | | 5,944 | |
1Includes allowance for equity 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. On December 30, 2021, we closed the sale of our minority ownership in Noverco Inc. (Noverco). For both the three and nine months ended September 30, 2021, the weighted average number of common shares outstanding was reduced by our pro-rata weighted average interest in our own common shares of approximately 2 million, resulting from our reciprocal investment in Noverco.
DILUTED
The treasury stock method is used to determine the dilutive impact of stock options and restricted stock units (RSU). This method assumes any proceeds from the exercise of stock options and vesting of 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 share are as follows:
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| | 2022 | 2021 | | 2022 | 2021 |
| (number of shares in millions) | | | | | |
| Weighted average shares outstanding | 2,025 | | 2,024 | | | 2,026 | | 2,023 | |
| Effect of dilutive options and RSUs | 3 | | 2 | | | 3 | | 2 | |
| Diluted weighted average shares outstanding | 2,028 | | 2,026 | | | 2,029 | | 2,025 | |
For the three months ended September 30, 2022 and 2021, 11.4 million and 13.3 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $56.49 and $56.16, respectively, were excluded from the diluted earnings per common share calculation.
For the nine months ended September 30, 2022 and 2021, 9.2 million and 20.5 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $56.63 and $52.19, respectively, were excluded from the diluted earnings per common share calculation.
DIVIDENDS PER SHARE
On November 2, 2022, our Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2022 to shareholders of record on November 15, 2022.
| | | | | |
| Dividend per share |
Common Shares1 | $0.86000 | |
| Preference Shares, Series A | $0.34375 | |
Preference Shares, Series B2 | $0.32513 | |
| Preference Shares, Series D | $0.27875 | |
| Preference Shares, Series F | $0.29306 | |
| Preference Shares, Series H | $0.27350 | |
Preference Shares, Series L3 | US$0.36612 | |
| Preference Shares, Series N | $0.31788 | |
| Preference Shares, Series P | $0.27369 | |
| Preference Shares, Series R | $0.25456 | |
| Preference Shares, Series 1 | US$0.37182 | |
| Preference Shares, Series 3 | $0.23356 | |
| Preference Shares, Series 5 | US$0.33596 | |
| Preference Shares, Series 7 | $0.27806 | |
| Preference Shares, Series 9 | $0.25606 | |
| Preference Shares, Series 11 | $0.24613 | |
| Preference Shares, Series 13 | $0.19019 | |
| Preference Shares, Series 15 | $0.18644 | |
| |
| Preference Shares, Series 19 | $0.30625 | |
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1The quarterly dividend per common share was increased 3% to $0.86 from $0.835, effective March 1, 2022.
2The quarterly dividend per share paid on Preference Shares, Series B was increased to $0.32513 from $0.21340 on June 1, 2022 due to reset of the annual dividend on June 1, 2022. On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B.
3The quarterly dividend per share paid on Preference Shares, Series L was increased to US$0.36612 from US$0.30993 on September 1, 2022 due to reset of the annual dividend on September 1, 2022.
PREFERENCE SHARE REDEMPTIONS
On March 1, 2022, we redeemed our $750 million outstanding Cumulative Redeemable Minimum Rate Reset Preference Shares, Series 17. On June 1, 2022, we also redeemed our US$200 million outstanding Cumulative Redeemable Preference Shares, Series J. Dividends are cumulative, payable quarterly and are included in Preference share dividends in the Consolidated Statements of Earnings.
6. ACQUISITIONS AND DISPOSITIONS
DCP MIDSTREAM, LLC
On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 (P66) resulting in a single joint venture, DCP Midstream, LLC, holding both our and P66's indirect ownership interests in Gray Oak Pipeline, LLC (Gray Oak) and DCP Midstream, LP (DCP). Our ownership in DCP Midstream, LLC consists of Class A and Class B Interests which track to our investments in DCP, included in the Gas Transmission and Midstream segment, and Gray Oak, included in the Liquids Pipelines segment, respectively. Through our investment in DCP Midstream, LLC, we increased our indirect economic interest in Gray Oak to 58.5% from 22.8% and reduced our indirect economic interest in DCP to 13.2% from 28.3%. As a result of the transaction, Enbridge will assume operatorship of Gray Oak in the second quarter of 2023.
We determined the fair value of our decrease in economic interest in DCP based on the unadjusted quoted market price of DCP’s publicly traded common units on the transaction closing date. The fair value of our increased economic interest in Gray Oak was determined using the fair value prescribed to the change in our economic interest in DCP. As a result of the merger transaction and the realignment of our economic interests in DCP and Gray Oak, we also received cash consideration of approximately $522 million (US$404 million) and recorded an accounting gain of $1.1 billion (US$832 million) to Gain on joint venture merger transaction in the Consolidated Statements of Earnings. Both DCP and Gray Oak continue to be accounted for as equity method investments.
TRI GLOBAL ENERGY, LLC
On September 27, 2022, through a wholly-owned United States (US) subsidiary, we acquired all of the outstanding common units in Tri Global Energy, LLC (TGE) for cash consideration of $295 million (US$215 million) plus potential contingent payments of up to $72 million (US$53 million) dependent on the achievement of performance milestones by TGE (the Acquisition). The Acquisition is subject to customary closing and working capital adjustments. TGE is an onshore renewable project developer in the US with a development portfolio of wind and solar projects. The Acquisition enhances Enbridge's renewable power platform and accelerates our North American growth strategy.
We accounted for the Acquisition using the acquisition method as prescribed by ASC 805 Business
Combinations. In accordance with valuation methodologies described in ASC 820 Fair Value
Measurements, the acquired assets and assumed liabilities are recorded at their estimated fair values
as at the date of acquisition.
The following table summarizes the estimated preliminary fair values that were assigned to the net assets
of TGE:
| | | | | |
| September 27, 2022 |
| (millions of Canadian dollars) | |
| Fair value of net assets acquired: | |
| Current assets | 5 | |
| Property, plant and equipment | 3 | |
| Long-term investments | 8 | |
| Intangible assets (a) | 117 | |
| Long-term assets | 3 | |
| Current liabilities | 61 | |
| Long-term liabilities (b) | 123 | |
| Goodwill (c) | 392 | |
| Purchase price: | |
| Cash | 295 | |
| Contingent consideration (d) | 49 | |
| 344 | |
a) Intangible assets consist of compensation expected to be earned by TGE on existing development contracts once certain project development milestones are met. Fair value was determined using a discounted cash flow method which is an income-based approach to valuation that estimates the present value of future projected benefits from the contracts. The intangible assets will be amortized on a straight-line basis over an expected useful life of two and a half years.
b) Long-term liabilities consist primarily of obligations payable to third parties which are contingent on milestones being met for certain projects. Fair value represents the present value of the future cash flow payments at the date of the Acquisition.
c) Goodwill is primarily attributable to expected future returns from new opportunities to develop wind and solar projects, as well as enhanced scale and operational diversity of our renewable projects portfolio. The goodwill balance recognized has been assigned to our Renewable Power Generation segment and is tax deductible over 15 years.
d) We agreed to pay additional contingent consideration of up to US$53 million to TGE's former
common unit holders if performance milestones are met on certain projects. The US$36 million of contingent consideration recognized in the purchase price represents the fair value of contingent
consideration at the date of acquisition. The fair value was determined using an income-based approach.
Upon completion of the Acquisition, we began consolidating TGE. For the period beginning September 27, 2022 through to September 30, 2022, operating revenues and earnings attributable to common shareholders generated by TGE 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, 2022 and 2021, as if the Acquisition had been completed on January 1, 2021, was also immaterial.
ATHABASCA REGIONAL OIL SANDS SYSTEM
On September 28, 2022, we entered into an agreement to sell an 11.6% non-operating interest in seven pipelines in the Athabasca region of northern Alberta from our Regional Oil Sands System to Athabasca Indigenous Investments Limited Partnership, an entity representing 23 First Nation and Métis communities. We will maintain an 88.4% controlling interest in these assets, which are a component of our Liquids Pipelines segment, and continue to manage, operate and provide administrative services to them. On October 5, 2022, we closed the sale for total consideration of approximately $1.1 billion, less customary closing adjustments.
7. DEBT
CREDIT FACILITIES
The following table provides details of our committed credit facilities as at September 30, 2022:
| | | | | | | | | | | | | | |
| Maturity1 | Total
Facilities | Draws2 | Available |
| (millions of Canadian dollars) | | | | |
| Enbridge Inc. | 2023-2027 | 10,949 | | 9,451 | | 1,498 | |
| Enbridge (U.S.) Inc. | 2024-2027 | 8,245 | | 3,909 | | 4,336 | |
| Enbridge Pipelines Inc. | 2024 | 2,000 | | 858 | | 1,142 | |
| Enbridge Gas Inc. | 2024 | 2,000 | | 1,885 | | 115 | |
| Total committed credit facilities | | 23,194 | | 16,103 | | 7,091 | |
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.
On February 10, 2022, we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025.
On May 17, 2022, we entered into a three year term loan with a syndicate of Japanese banks for approximately $806 million (¥84.8 billion), which will mature in May 2025 and replaces the approximately $499 million (¥52.5 billion) term loan that matured in May 2022. Additionally, on May 24, 2022, we entered into a 364-day term loan for approximately $1.9 billion, which will mature in May 2023.
On June 23, 2022, we renewed approximately $5.5 billion of our 364-day extendible credit facilities to July 2024, which includes a one-year term out provision from July 2023.
In July and August 2022, we renewed $12.7 billion of our credit facilities, extending the maturity dates of our 364-day credit facilities to July 2024, inclusive of a one-year term out provision from July 2023, and our five year facilities out to July 2027. As a part of the renewals, we increased our credit facilities by approximately $641 million.
In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $780 million was unutilized as at September 30, 2022. As at December 31, 2021, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $854 million was unutilized.
Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2024 to 2027.
As at September 30, 2022 and December 31, 2021, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $11.9 billion and $11.3 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.
LONG-TERM DEBT ISSUANCES
During the nine months ended September 30, 2022, we completed the following long-term debt issuances totaling $1.4 billion and US$2.6 billion:
| | | | | | | | | | | | | | |
| Company | Issue Date | | | Principal Amount |
| (millions of Canadian dollars unless otherwise stated) | |
| Enbridge Inc. | | | |
| January 2022 | 5.00% | fixed-to-fixed subordinated notes due January 20821 | $750 |
| February 2022 | Floating rate senior notes due February 20242 | US$600 |
| February 2022 | 2.15% | senior notes due February 2024 | US$400 |
| February 2022 | 2.50% | senior notes due February 2025 | US$500 |
| September 2022 | 7.38% | fixed-to-fixed subordinated notes due January 20833 | US$500 |
| September 2022 | 7.63% | fixed-to-fixed subordinated notes due January 20834 | US$600 |
| Enbridge Gas Inc. | | | |
| August 2022 | 4.15 | % | medium-term notes due August 2032 | $325 |
| August 2022 | 4.55 | % | medium-term notes due August 2052 | $325 |
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1For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 3.54%. Subsequent to year 10, every five years, the Five Year Government of Canada bond yield is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.29%.
2Notes carry an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 63 basis points.
3For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be set to equal to the Five-Year US Treasury rate plus a margin of 3.71%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.96%. Subsequent to year 10, every five years, the Five Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.71%.
4For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.42%. Subsequent to year 10, every five years, the Five-Year US Treasury rate will be reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.17%.
LONG-TERM DEBT REPAYMENTS
During the nine months ended September 30, 2022, we completed the following long-term debt repayments totaling US$1.5 billion and $0.3 billion:
| | | | | | | | | | | | | | |
| Company | Repayment Date | | | Principal Amount |
| (millions of Canadian dollars unless otherwise stated) | |
| Enbridge Inc. | | | |
| February 2022 | Floating rate notes1 | US$750 |
| February 2022 | 4.85% | medium-term notes | $200 |
| July 2022 | 2.90% | senior notes due July 2022 | US$700 |
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| Enbridge Gas Inc. | | | |
| April 2022 | 4.85% | medium-term notes | $125 |
| Enbridge Pipelines (Southern Lights) L.L.C. | |
| June 2022 | 3.98% | senior notes | US$34 |
| Enbridge Southern Lights LP | | | |
| June 2022 | 4.01% | senior notes | $9 |
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1Notes carried an interest rate set to equal the three-month London Interbank Offered Rate plus a margin of 50 basis points.
SUBORDINATED TERM NOTES
As at September 30, 2022 and December 31, 2021, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $10.4 billion and $7.7 billion, respectively.
FAIR VALUE ADJUSTMENT
As at September 30, 2022 and December 31, 2021, the net fair value adjustments to total debt assumed in a historical acquisition were $630 million and $667 million, respectively.
During the three and nine months ended September 30, 2022, amortization of the fair value adjustment recorded as a reduction to Interest expense in the Consolidated Statements of Earnings was $11 million (September 30, 2021 - $11 million) and $33 million (September 30, 2021 - $36 million), respectively.
DEBT COVENANTS
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we are to default on payment or violate certain covenants. As at September 30, 2022, we are in compliance with all covenant provisions.
8. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
Changes in Accumulated other comprehensive income/(loss) (AOCI) attributable to our common shareholders for the nine months ended September 30, 2022 and 2021 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, 2022 | (897) | | — | | (166) | | 56 | | (5) | | (84) | | (1,096) | |
Other comprehensive income/(loss) retained in AOCI | 1,073 | | (38) | | (1,187) | | 5,168 | | (6) | | — | | 5,010 | |
| Other comprehensive loss/(income) reclassified to earnings | | | | | | | |
Interest rate contracts1 | 187 | | — | | — | | — | | — | | — | | 187 | |
| | | | | | | |
Foreign exchange contracts2 | (4) | | — | | — | | — | | — | | — | | (4) | |
Other contracts3 | 3 | | — | | — | | — | | — | | — | | 3 | |
Amortization of pension and OPEB actuarial gain4 | — | | — | | — | | — | | — | | (9) | | (9) | |
| Other | — | | — | | — | | — | | 16 | | — | | 16 | |
| 1,259 | | (38) | | (1,187) | | 5,168 | | 10 | | (9) | | 5,203 | |
| Tax impact | | | | | | | |
| Income tax on amounts retained in AOCI | (242) | | — | | — | | — | | (1) | | — | | (243) | |
| Income tax on amounts reclassified to earnings | (41) | | — | | — | | — | | — | | 2 | | (39) | |
| (283) | | — | | — | | — | | (1) | | 2 | | (282) | |
| | | | | | | |
| Balance as at September 30, 2022 | 79 | | (38) | | (1,353) | | 5,224 | | 4 | | (91) | | 3,825 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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, 2021 | (1,326) | | 5 | | (215) | | 568 | | 66 | | (499) | | (1,401) | |
Other comprehensive income/(loss) retained in AOCI | 284 | | (3) | | 18 | | (340) | | (33) | | — | | (74) | |
| Other comprehensive loss/(income) reclassified to earnings | | | | | | | |
Interest rate contracts1 | 218 | | — | | — | | — | | — | | — | | 218 | |
Foreign exchange contracts2 | 4 | | — | | — | | — | | — | | — | | 4 | |
Other contracts3 | 1 | | — | | — | | — | | — | | — | | 1 | |
Commodity contracts5 | (4) | | — | | — | | — | | — | | — | | (4) | |
Amortization of pension and OPEB actuarial loss4 | — | | — | | — | | — | | — | | 21 | | 21 | |
| Other | 17 | | — | | — | | (20) | | 3 | | — | | — | |
| 520 | | (3) | | 18 | | (360) | | (30) | | 21 | | 166 | |
| Tax impact | | | | | | | |
| Income tax on amounts retained in AOCI | (72) | | — | | (2) | | — | | 5 | | — | | (69) | |
| Income tax on amounts reclassified to earnings | (51) | | — | | — | | — | | — | | (5) | | (56) | |
| (123) | | — | | (2) | | — | | 5 | | (5) | | (125) | |
| | | | | | | |
| Balance as at September 30, 2021 | (929) | | 2 | | (199) | | 208 | | 41 | | (483) | | (1,360) | |
1Reported within Interest expense in the Consolidated Statements of Earnings.
2Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
3Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
4These components are included in the computation of net periodic benefit (credit)/cost and are reported within Other income/(expense) in the Consolidated Statements of Earnings.
5Reported within Transportation and other services revenues, Commodity sales revenue, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
9. 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 cash flow, fair value and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge certain net investments in US dollar denominated investments and subsidiaries using US dollar denominated debt.
Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via execution of floating-to-fixed interest rate swaps. These hedges have an average fixed rate of 2.5%.
We are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in the fair value of fixed rate debt via execution of fixed-to-floating interest rate swaps. As at September 30, 2022, we did not have any pay floating-receive fixed interest rate swaps outstanding.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. 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 2.1%.
Commodity Price Risk
Our earnings and cash flows 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 services 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 revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.
TOTAL DERIVATIVE INSTRUMENTS
We generally 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 table summarizes 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. All amounts are presented gross in the Consolidated Statements of Financial Position.
| | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2022 | 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) | | | | | | | | |
| Accounts receivable and other | | | | | | | | |
| Foreign exchange contracts | — | | | — | | 65 | | 65 | | | (37) | | 28 | |
| Interest rate contracts | 127 | | | — | | 1 | | 128 | | | (17) | | 111 | |
| Commodity contracts | — | | | — | | 414 | | 414 | | | (230) | | 184 | |
| Other contracts | 1 | | | — | | 5 | | 6 | | | — | | 6 | |
| 128 | | | — | | 485 | | 613 | | 1 | (284) | | 329 | |
| Deferred amounts and other assets | | | | | | | | |
| Foreign exchange contracts | — | | | 117 | | 203 | | 320 | | | (164) | | 156 | |
| Interest rate contracts | 830 | | | — | | — | | 830 | | | — | | 830 | |
| Commodity contracts | — | | | — | | 66 | | 66 | | | (26) | | 40 | |
| Other contracts | 1 | | | — | | — | | 1 | | | (1) | | — | |
| 831 | | | 117 | | 269 | | 1,217 | | | (191) | | 1,026 | |
| Accounts payable and other | | | | | | | | |
| Foreign exchange contracts | — | | | (37) | | (693) | | (730) | | | 37 | | (693) | |
| Interest rate contracts | (1) | | | — | | (16) | | (17) | | | 17 | | — | |
| Commodity contracts | (32) | | | — | | (380) | | (412) | | | 230 | | (182) | |
| Other contracts | — | | | — | | — | | — | | | — | | — | |
| (33) | | | (37) | | (1,089) | | (1,159) | | 1 | 284 | | (875) | |
| Other long-term liabilities | | | | | | | | |
| Foreign exchange contracts | — | | | (6) | | (1,423) | | (1,429) | | | 164 | | (1,265) | |
| Interest rate contracts | (3) | | | — | | — | | (3) | | | — | | (3) | |
| Commodity contracts | (27) | | | — | | (145) | | (172) | | | 26 | | (146) | |
| Other contracts | (1) | | | — | | — | | (1) | | | 1 | | — | |
| (31) | | | (6) | | (1,568) | | (1,605) | | | 191 | | (1,414) | |
| Total net derivative assets/(liabilities) | | | | | | | | |
| Foreign exchange contracts | — | | | 74 | | (1,848) | | (1,774) | | | — | | (1,774) | |
| Interest rate contracts | 953 | | | — | | (15) | | 938 | | | — | | 938 | |
| Commodity contracts | (59) | | | — | | (45) | | (104) | | | — | | (104) | |
| Other contracts | 1 | | | — | | 5 | | 6 | | | — | | 6 | |
| 895 | | | 74 | | (1,903) | | (934) | | | — | | (934) | |
1As at September 30, 2022, $28 million and $36 million were reported within Accounts receivable from affiliates and Accounts payable to affiliates, respectively, in the Consolidated Statements of Financial Position.
| | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 | 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) | | | | | | | |
| Accounts receivable and other | | | | | | | |
| Foreign exchange contracts | — | | | — | | 259 | | 259 | | (41) | | 218 | |
| Interest rate contracts | 64 | | | — | | — | | 64 | | — | | 64 | |
| Commodity contracts | — | | | — | | 204 | | 204 | | (129) | | 75 | |
| Other contracts | — | | | — | | 2 | | 2 | | — | | 2 | |
| 64 | | | — | | 465 | | 529 | | (170) | | 359 | |
| Deferred amounts and other assets | | | | | | | |
| Foreign exchange contracts | — | | | — | | 240 | | 240 | | (61) | | 179 | |
| Interest rate contracts | 88 | | | — | | — | | 88 | | (1) | | 87 | |
| Commodity contracts | — | | | — | | 29 | | 29 | | (13) | | 16 | |
| Other contracts | — | | | — | | 3 | | 3 | | — | | 3 | |
| 88 | | | — | | 272 | | 360 | | (75) | | 285 | |
| Accounts payable and other | | | | | | | |
| Foreign exchange contracts | (15) | | | (112) | | (176) | | (303) | | 41 | | (262) | |
| Interest rate contracts | (150) | | | — | | — | | (150) | | — | | (150) | |
| Commodity contracts | (14) | | | — | | (250) | | (264) | | 129 | | (135) | |
| | | | | | | |
| (179) | | | (112) | | (426) | | (717) | | 170 | | (547) | |
| Other long-term liabilities | | | | | | | |
| Foreign exchange contracts | — | | | — | | (423) | | (423) | | 61 | | (362) | |
| Interest rate contracts | (1) | | | — | | (23) | | (24) | | 1 | | (23) | |
| Commodity contracts | (17) | | | — | | (67) | | (84) | | 13 | | (71) | |
| | | | | | | |
| (18) | | | — | | (513) | | (531) | | 75 | | (456) | |
| Total net derivative assets/(liabilities) | | | | | | | |
| Foreign exchange contracts | (15) | | | (112) | | (100) | | (227) | | — | | (227) | |
| Interest rate contracts | 1 | | | — | | (23) | | (22) | | — | | (22) | |
| Commodity contracts | (31) | | | — | | (84) | | (115) | | — | | (115) | |
| Other contracts | — | | | — | | 5 | | 5 | | — | | 5 | |
| (45) | | | (112) | | (202) | | (359) | | — | | (359) | |
The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2022 | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | Total | |
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) | 799 | | 4 | | 1,000 | | 500 | | — | | — | | 2,303 | | |
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) | 3,017 | | 7,185 | | 6,134 | | 4,361 | | 3,761 | | 1,481 | | 25,939 | | |
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) | 7 | | 29 | | 30 | | 30 | | 28 | | 32 | | 156 | | |
| | | | | | | | |
Foreign exchange contracts - Euro forwards - sell (millions of Euro) | 23 | | 92 | | 91 | | 86 | | 85 | | 343 | | 720 | | |
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) | — | | — | | — | | 84,800 | | — | | — | | 84,800 | | |
Interest rate contracts - short-term debt pay fixed rate (millions of Canadian dollars) | 2,715 | | 3,190 | | 241 | | 31 | | 26 | | 64 | | 6,267 | | |
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars) | 900 | | 4,099 | | 1,781 | | 594 | | — | | — | | 7,374 | | |
Equity contracts (millions of Canadian dollars) | — | | 36 | | 31 | | 11 | | — | | — | | 78 | | |
Commodity contracts - natural gas (billions of cubic feet)1 | 33 | | 49 | | 21 | | 13 | | 3 | | — | | 119 | | |
Commodity contracts - crude oil (millions of barrels)1 | 3 | | — | | — | | — | | — | | — | | 3 | | |
| | | | | | | | |
Commodity contracts - power (megawatt per hour) (MW/H) | 5 | | (25) | | (33) | | (43) | | — | | — | | (31) | | 2 |
1Total is a net purchase/(sale) of underlying commodity.
2Total is an average net purchase/(sale) of power.
Fair Value Derivatives
For foreign exchange derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative is included in Net foreign currency gain/(loss) 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 Net foreign currency gain/(loss) 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, |
| 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
| Unrealized gain on derivative | 122 | | 50 | | | 221 | | 15 | |
| Unrealized loss on hedged item | (122) | | (50) | | | (211) | | (22) | |
| Realized loss on derivative | (5) | | (1) | | | (101) | | (40) | |
| Realized gain on hedged item | — | | — | | | 85 | | 45 | |
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 consolidated comprehensive income, before the effect of income taxes:
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
Amount of unrealized gain/(loss) recognized in OCI | | | | | |
Cash flow hedges | | | | | |
Foreign exchange contracts | 1 | | 4 | | | 3 | | (21) | |
Interest rate contracts | 230 | | (1) | | | 1,087 | | 293 | |
Commodity contracts | (16) | | (21) | | | (27) | | (25) | |
Other contracts | (4) | | (2) | | | (4) | | 2 | |
Fair value hedges | | | | | |
Foreign exchange contracts | (33) | | (1) | | | (38) | | (3) | |
| | | | | |
| | | | | |
| 178 | | (21) | | | 1,021 | | 246 | |
| Amount of (gain)/loss reclassified from AOCI to earnings | | | | | |
Foreign exchange contracts1 | — | | 1 | | | 13 | | 4 | |
Interest rate contracts2 | 45 | | 76 | | | 187 | | 218 | |
| Commodity contracts | — | | (4) | | | — | | (4) | |
Other contracts3 | 1 | | — | | | 3 | | 1 | |
| 46 | | 73 | | | 203 | | 219 | |
1Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
2Reported within Interest expense in the Consolidated Statements of Earnings.
3Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
We estimate that a gain of $57 million of AOCI related to unrealized 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 39 months as at September 30, 2022.
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, |
| 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
Foreign exchange contracts1 | (1,379) | | (436) | | | (1,752) | | 18 | |
Interest rate contracts2 | 17 | | 2 | | | 1 | | 4 | |
Commodity contracts3 | 89 | | (102) | | | 59 | | (120) | |
Other contracts4 | (3) | | 2 | | | 1 | | 12 | |
| Total unrealized derivative fair value loss, net | (1,276) | | (534) | | | (1,691) | | (86) | |
1For the respective nine months ended periods, reported within Transportation and other services revenues (2022 - $375 million loss; 2021 - $71 million gain) and Net foreign currency gain/(loss) (2022 - $1,377 million loss; 2021 - $53 million loss) in the Consolidated Statements of Earnings.
2Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.
3For the respective nine months ended periods, reported within Transportation and other services revenues (2022 - $12 million gain; 2021 - nil), Commodity sales (2022 - $151 million gain; 2021 - $5 million loss), Commodity costs (2022 - $116 million loss; 2021 - $124 million loss) and Operating and administrative expense (2022 - $12 million gain; 2021 - $8 million gain) 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 are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at September 30, 2022. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.
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 maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.
We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:
| | | | | | | | |
| September 30,
2022 | December 31,
2021 |
| (millions of Canadian dollars) | | |
| Canadian financial institutions | 637 | | 424 | |
| US financial institutions | 361 | | 130 | |
| European financial institutions | 441 | | 181 | |
| Asian financial institutions | 208 | | 30 | |
Other1 | 165 | | 122 | |
| 1,812 | | 887 | |
1Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at September 30, 2022, 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, 2022 and December 31, 2021.
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, assessment of credit ratings and netting arrangements. Within Enbridge Gas Inc., 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 derivative and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.
FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our financial instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.
Level 1
Level 1 includes financial instruments measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a financial instrument is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations, US and Canadian treasury bills, investments in exchange-traded equity funds held by our captive insurance subsidiaries, as well as restricted long-term investments in Canadian equity securities that are held in trust in accordance with the CER's regulatory requirements under the Land Matters Consultation Initiative (LMCI).
Level 2
Level 2 includes financial instrument valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Financial instruments in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the financial instrument. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.
We have also categorized the fair value of our long-term debt, investments in debt securities held by our captive insurance subsidiaries, and restricted long-term investments in Canadian government bonds held in trust in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our available-for-sale preferred share investment is based on the redemption value, which equals the face value plus accrued and unpaid interest periodically reset based on market interest rates. 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 extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power, NGL and natural gas contracts, basis swaps, commodity swaps, and power and energy swaps, as well as physical forward commodity contracts. We do not have any other financial instruments categorized in Level 3.
We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value.
We have categorized our derivative assets and liabilities measured at fair value as follows:
| | | | | | | | | | | | | | |
| September 30, 2022 | Level 1 | Level 2 | Level 3 | Total Gross
Derivative
Instruments |
| (millions of Canadian dollars) | | | | |
| Financial assets | | | | |
| Current derivative assets | | | | |
| Foreign exchange contracts | — | | 65 | | — | | 65 | |
| Interest rate contracts | — | | 128 | | — | | 128 | |
| Commodity contracts | 120 | | 142 | | 152 | | 414 | |
| Other contracts | — | | 6 | | — | | 6 | |
| | 120 | | 341 | | 152 | | 613 | |
| Long-term derivative assets | | | | |
| Foreign exchange contracts | — | | 320 | | — | | 320 | |
| Interest rate contracts | — | | 830 | | — | | 830 | |
| Commodity contracts | — | | 24 | | 42 | | 66 | |
| Other contracts | — | | 1 | | — | | 1 | |
| | — | | 1,175 | | 42 | | 1,217 | |
| Financial liabilities | | | | |
| Current derivative liabilities | | | | |
| Foreign exchange contracts | — | | (730) | | — | | (730) | |
| Interest rate contracts | — | | (17) | | — | | (17) | |
| Commodity contracts | (56) | | (188) | | (168) | | (412) | |
| Other contracts | — | | — | | — | | — | |
| | (56) | | (935) | | (168) | | (1,159) | |
| Long-term derivative liabilities | | | | |
| Foreign exchange contracts | — | | (1,429) | | — | | (1,429) | |
| Interest rate contracts | — | | (3) | | — | | (3) | |
| Commodity contracts | — | | (49) | | (123) | | (172) | |
| Other contracts | — | | (1) | | — | | (1) | |
| — | | (1,482) | | (123) | | (1,605) | |
| Total net financial assets/(liabilities) | | | | |
| Foreign exchange contracts | — | | (1,774) | | — | | (1,774) | |
| Interest rate contracts | — | | 938 | | — | | 938 | |
| Commodity contracts | 64 | | (71) | | (97) | | (104) | |
| Other contracts | — | | 6 | | — | | 6 | |
| | 64 | | (901) | | (97) | | (934) | |
| | | | | | | | | | | | | | |
| December 31, 2021 | Level 1 | Level 2 | Level 3 | Total Gross
Derivative
Instruments |
| (millions of Canadian dollars) | | | | |
| Financial assets | | | | |
| Current derivative assets | | | | |
| Foreign exchange contracts | — | | 259 | | — | | 259 | |
| Interest rate contracts | — | | 64 | | — | | 64 | |
| Commodity contracts | 38 | | 71 | | 95 | | 204 | |
| Other contracts | — | | 2 | | — | | 2 | |
| | 38 | | 396 | | 95 | | 529 | |
| Long-term derivative assets | | | | |
| Foreign exchange contracts | — | | 240 | | — | | 240 | |
| Interest rate contracts | — | | 88 | | — | | 88 | |
| Commodity contracts | — | | 21 | | 8 | | 29 | |
| Other contracts | — | | 3 | | — | | 3 | |
| — | | 352 | | 8 | | 360 | |
| Financial liabilities | | | | |
| Current derivative liabilities | | | | |
| Foreign exchange contracts | — | | (303) | | — | | (303) | |
| Interest rate contracts | — | | (150) | | — | | (150) | |
| Commodity contracts | (52) | | (66) | | (146) | | (264) | |
| | | | |
| (52) | | (519) | | (146) | | (717) | |
| Long-term derivative liabilities | | | | |
| Foreign exchange contracts | — | | (423) | | — | | (423) | |
| Interest rate contracts | — | | (24) | | — | | (24) | |
| Commodity contracts | — | | (19) | | (65) | | (84) | |
| | | | |
| — | | (466) | | (65) | | (531) | |
| Total net financial assets/(liabilities) | | | | |
| Foreign exchange contracts | — | | (227) | | — | | (227) | |
| Interest rate contracts | — | | (22) | | — | | (22) | |
| Commodity contracts | (14) | | 7 | | (108) | | (115) | |
| Other contracts | — | | 5 | | — | | 5 | |
| | (14) | | (237) | | (108) | | (359) | |
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
| | | | | | | | | | | | | | | | | | | | |
| September 30, 2022 | Fair
Value | Unobservable
Input | Minimum
Price | Maximum
Price | Weighted
Average Price | Unit of
Measurement |
| (fair value in millions of Canadian dollars) | | | | | | |
Commodity contracts - financial1 | | | | | | |
Natural gas | 9 | | Forward gas price | 5.41 | | 12.51 | | 7.75 | | $/mmbtu2 |
Crude | 5 | | Forward crude price | 64.09 | | 108.87 | | 77.06 | | $/barrel |
| | | | | | |
Power | (80) | | Forward power price | 35.56 | | 207.09 | | 93.98 | | $/MW/H |
Commodity contracts - physical1 | | | | | | |
Natural gas | (66) | | Forward gas price | 3.43 | | 22.01 | | 7.11 | | $/mmbtu2 |
Crude | 24 | | Forward crude price | 72.52 | | 125.74 | | 90.39 | | $/barrel |
| | | | | | |
| Power | 11 | | Forward power price | 37.08 | | 175.52 | | 81.95 | | $/MW/H |
| (97) | | | | | | |
1Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2One million British thermal units (mmbtu).
3
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 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, |
| | 2022 | 2021 |
| (millions of Canadian dollars) | | |
| Level 3 net derivative liability at beginning of period | (108) | | (191) | |
| Total gain/(loss) | | |
Included in earnings1 | 41 | | (181) | |
Included in OCI | (28) | | (29) | |
| Settlements | (2) | | 167 | |
| Level 3 net derivative liability at end of period | (97) | | (234) | |
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, 2022 or December 31, 2021.
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, 2022 and 2021, we recognized an unrealized foreign exchange loss of $1,191 million and gain of $18 million, respectively, on the translation of US dollar denominated debt. During the nine months ended September 30, 2022 and 2021, we recognized nil on the change in fair value of our outstanding foreign exchange forward contracts in OCI and nil in OCI associated with the settlement of foreign exchange forward contracts or with the settlement of US dollar denominated debt that had matured during the period.
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 $102 million and $52 million as at September 30, 2022 and December 31, 2021, respectively.
We have Restricted long-term investments held in trust totaling $219 million and $217 million as at September 30, 2022 and December 31, 2021, respectively, which are classified as Level 1 in the fair value hierarchy. We also have Restricted long-term investments held in trust totaling $350 million and $413 million as at September 30, 2022 and December 31, 2021, respectively, which are classified as Level 2 in the fair value hierarchy. These securities are classified as restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with regulatory requirements. There were unrealized holding gains of $11 million and losses of $120 million for the three and nine months ended September 30, 2022, respectively (2021 - losses of $16 million and $41 million, respectively).
We have wholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures in the US and Canada of our operating subsidiaries and certain equity investments. As at September 30, 2022, the fair value of short- and long-term investments in equity funds and debt securities held by our captive insurance subsidiaries was $108 million and $400 million, respectively (December 31, 2021 - $14 million and $290 million, respectively). 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 Accounts receivable and other and Long-term investments, respectively, in the Consolidated Statements of Financial Position. There were unrealized holding losses in equity funds and debt securities of $13 million and $40 million for the three and nine months ended September 30, 2022, respectively (2021 - gains of $1 million and $4 million, respectively).
As at September 30, 2022 and December 31, 2021, our long-term debt had a carrying value of $80.7 billion and $74.4 billion, respectively, before debt issuance costs and a fair value of $74.2 billion and $82.0 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at September 30, 2022 and December 31, 2021, the non-current notes receivable had a carrying value of $752 million and $954 million, respectively, which also approximates their fair value.
The fair value of financial assets and liabilities other than derivative instruments, long-term investments, restricted long-term investments, long-term debt and non-current notes receivable described above approximate their carrying value due to the short period to maturity.
10. INCOME TAXES
The effective income tax rates for the three months ended September 30, 2022 and 2021 were 18.7% and 19.6%, respectively, and for the nine months ended September 30, 2022 and 2021 were 20.5% and 18.0%, respectively.
The period-over-period changes in the effective income tax rates are due to the effect of rate-regulated accounting for income taxes and other permanent differences relative to earnings, an increase in US minimum tax, offset by a statutory rate decrease in Pennsylvania and an adjustment to 2020 regulatory
balances in the three-month period of the prior year.
11. PENSION AND OTHER POSTRETIREMENT BENEFITS
| | | | | | | | | | | | | | | | | |
| Three months ended September 30, | | Nine months ended September 30, |
| 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
| Service cost | 46 | | 48 | | | 136 | | 144 | |
Interest cost1 | 40 | | 32 | | | 122 | | 96 | |
Expected return on plan assets1 | (98) | | (84) | | | (294) | | (252) | |
Amortization of actuarial (gain)/loss1 | (1) | | 14 | | | (3) | | 42 | |
| Net periodic benefit (credit)/cost | (13) | | 10 | | | (39) | | 30 | |
1Reported within Other income/(expense) in the Consolidated Statements of Earnings.
12. CONTINGENCIES
We and our subsidiaries are involved in 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.
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, 2021.
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
Joint Venture Merger Transaction to Advance US Gulf Coast Oil Strategy
On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 (P66) resulting in a single joint venture, DCP Midstream LLC, holding both Enbridge Inc.'s (Enbridge) and P66's indirect ownership interests in Gray Oak Pipeline, LLC (Gray Oak) and DCP Midstream, LP (DCP), as well as an agreement to realign our respective economic and governance interests in the underlying business operations. Our indirect economic interest in Gray Oak has increased to 58.5% from 22.8% and we will assume operatorship of Gray Oak in the second quarter of 2023. Simultaneously, our indirect economic interest in DCP has been reduced to 13.2% from 28.3%. We received approximately $522 million (US$404 million) in cash proceeds and recorded an accounting gain of $1.1 billion (US$832 million) on the Consolidated Statements of Earnings as a result of the transaction.
Acquisition of Tri Global Energy LLC
On September 27, 2022, we acquired Tri Global Energy LLC (TGE), a leading US renewable power project developer, for approximately US$270 million in cash and assumed debt. The acquisition of TGE enhances our renewable power platform and further builds on our inventory of North American growth opportunities.
Athabasca Indigenous Investments Partnership
On October 5, 2022, we completed a transaction with Athabasca Indigenous Investments Limited Partnership (Aii), a newly created entity representing 23 First Nation and Métis communities, pursuant to which Aii acquired an 11.6% non-operating interest in seven Regional Oil Sands pipelines in northern Alberta for $1.1 billion.
CEO Transition
On October 3, 2022, we announced Al Monaco's retirement as President and Chief Executive Officer and from our Board of Directors effective January 1, 2023. Concurrent with this announcement, the Board of Directors appointed Greg Ebel, currently Chair of our Board of Directors, to succeed Mr. Monaco as President and Chief Executive Officer. Mr. Ebel will also continue as a member of the Board of Directors. A new independent Board Chair will be named prior to January 1, 2023. To support Mr. Ebel through the transition, Mr. Monaco will serve as an advisor to March 1, 2023.
GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS
Texas Eastern Transmission
Texas Eastern Transmission, LP (Texas Eastern) filed two rate cases in the third quarter of 2021. These two rate proceedings have since been consolidated and settlement negotiations began during the first quarter of 2022. An uncontested settlement in principle was reached on July 7, 2022. Texas Eastern filed an uncontested Stipulation and Agreement on September 8, 2022 to resolve all issues from the rate proceeding. The comment and reply period ended October 11, 2022 and the Stipulation and Agreement is now with the Federal Energy Regulatory Commission for approval.
Maritimes & Northeast Pipeline
In December 2021, the Canada Energy Regulator (CER) approved interim rates for the Canadian portion of Maritimes & Northeast (M&N) Pipeline effective January 1, 2022, which were based on the negotiated 2022 rates in the 2022-2023 settlement agreement and unanimously supported by shippers. The 2022-2023 M&N Canada settlement agreement was approved by the CER in February 2022.
British Columbia Pipeline
The settlement agreement for our British Columbia Pipeline (BC Pipeline) System expired in December 2021. The CER has approved 2022 interim tolls for BC Pipeline effective January 1, 2022. In August 2022, an agreement in principle was reached with BC Pipeline shippers on a 2022-2026 rate settlement, and we expect a settlement agreement to be executed with shippers and filed with the CER in the fourth quarter of 2022.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
2022 Rate Application
In June 2021, Enbridge Gas Inc. (Enbridge Gas) filed Phase 1 of the application with the Ontario Energy Board (OEB) for the setting of rates for 2022 (the 2022 Application). The 2022 Application was filed in accordance with the parameters of Enbridge Gas' OEB approved Price Cap Incentive Regulation (IR) rate setting mechanism and represents the fourth year of a five-year term. In October 2021, the OEB approved a Phase 1 Settlement Proposal and Interim Rate Order effective January 1, 2022. In April 2022, the OEB issued its decision on Phase 2 of the 2022 Application filed in October 2021, addressing incremental capital module (ICM) funding requirements, under which $127 million of Enbridge Gas' requested capital funding was approved and incorporated into final rates, effective July 1, 2022.
2023 Rate Application
In June 2022, Enbridge Gas filed Phase 1 of the application with the OEB for the setting of rates for 2023 (the 2023 Application). The 2023 Application was filed in accordance with the parameters of Enbridge Gas' approved Price Cap IR rate setting mechanism and represents the final year of a five-year term. In November 2022, the OEB approved the Phase 1 Settlement Proposal and Interim Rate Order effective January 1, 2023. In addition, Enbridge Gas does not anticipate 2023 capital investments to require incremental funding during the final year of its current Price Cap IR term, and as such Enbridge Gas will not be making a Phase 2 ICM request as part of the 2023 Application.
Incentive Regulation Rate Application
In October 2022, Enbridge Gas filed its application to establish a 2024 through 2028 IR rate setting framework. The application and framework seeks approval to establish 2024 base rates on a cost of service basis and to establish a price cap rate setting mechanism to be used for the remainder of the IR term (2025 – 2028). An OEB decision is expected on the application in the second half of 2023.
Purchase Gas Variance
The Purchase Gas Variance Account (PGVA) captures the difference between actual and forecasted natural gas prices reflected in rates. Account balances are typically recovered or refunded over a prospective 12-month period through Quarterly Rate Adjustment Mechanism (QRAM) applications.
In March and June 2022, the OEB approved Enbridge Gas' April 1, 2022 and July 1, 2022 QRAM applications, respectively. Due to the significant increase in natural gas prices, the approvals have also included rate mitigation plans intended to ease bill impacts to ratepayers. Specifically, the approved rate mitigation plans extended the PGVA recovery period from 12 months to 24 months in both applications. As an additional mitigation measure, as part of the April 1, 2022 QRAM, a portion of the PGVA balance was deferred for recovery, which was subsequently approved for recovery as part of the July 1, 2022 QRAM. The October 1, 2022 QRAM application was filed and approved by the OEB with no adjustments to the prior period rate mitigation plans and it did not include any additional rate mitigation measures.
As at September 30, 2022, Enbridge Gas' PGVA balance was $693 million.
FINANCING UPDATE
On January 19, 2022, we closed a $750 million private placement of non-call 10-year fixed-to-fixed subordinated notes which mature on January 19, 2082. The net proceeds from the offering were used to redeem Preference Shares, Series 17 at par on March 1, 2022.
On February 17, 2022, we closed a three tranche offering of aggregate US$1.5 billion senior notes consisting of US$600 million two-year floating rate notes, US$400 million two-year notes and US$500 million three-year notes. Each tranche is payable semi-annually in arrears and matures on February 16, 2024, February 16, 2024 and February 14, 2025, respectively.
On May 17, 2022, we entered into a three year term loan with a syndicate of Japanese banks for approximately $806 million (¥84.8 billion), which will mature in May 2025 and replaces the approximately $499 million (¥52.5 billion) term loan that matured in May 2022. Additionally, on May 24, 2022, we entered into a 364-day term loan for approximately $1.9 billion, which will mature in May 2023.
In July and August 2022, we increased our credit facilities by approximately $641 million.
On August 17, 2022, Enbridge Gas closed a $650 million dual-tranche medium-term note offering in the Canadian debt capital markets, split evenly across a 10-year tranche and a 30-year tranche, payable semi-annually in arrears due August 17, 2032 and August 17, 2052, respectively.
On September 20, 2022, we closed a US$1.1 billion dual-tranche hybrid note offering consisting of 60-year non-call 5-year fixed-to-fixed subordinated notes and 60-year non-call 10-year fixed-to-fixed subordinated notes, both of which mature on January 15, 2083.
These financing activities, in combination with the financing activities executed in 2021, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects 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, 2022, after adjusting for the impact of floating-to-fixed interest rate swap hedges, approximately 10% of our total debt is exposed to floating rates. Refer to Part I. Item I. Financial Statements - Note 9. Risk Management and Financial Instruments for more information on our interest rate hedging program.
RESULTS OF OPERATIONS
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| | 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1 | | | | | |
Liquids Pipelines | 1,946 | | 1,673 | | | 6,093 | | 5,756 | |
Gas Transmission and Midstream | 2,251 | | 884 | | | 4,384 | | 2,725 | |
Gas Distribution and Storage | 286 | | 282 | | | 1,368 | | 1,374 | |
Renewable Power Generation | 105 | | 91 | | | 389 | | 362 | |
Energy Services | (70) | | (204) | | | (348) | | (379) | |
Eliminations and Other | (935) | | (121) | | | (1,284) | | 191 | |
Earnings before interest, income taxes and depreciation and amortization1 | 3,583 | | 2,605 | | | 10,602 | | 10,029 | |
Depreciation and amortization | (1,076) | | (944) | | | (3,195) | | (2,805) | |
Interest expense | (806) | | (648) | | | (2,316) | | (1,923) | |
| Income tax expense | (318) | | (199) | | | (1,044) | | (952) | |
| Earnings attributable to noncontrolling interests | (21) | | (34) | | | (61) | | (93) | |
Preference share dividends | (83) | | (98) | | | (330) | | (280) | |
| Earnings attributable to common shareholders | 1,279 | | 682 | | | 3,656 | | 3,976 | |
| Earnings per common share attributable to common shareholders | 0.63 | | 0.34 | | | 1.80 | | 1.97 | |
| Diluted earnings per common share attributable to common shareholders | 0.63 | | 0.34 | | | 1.80 | | 1.96 | |
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
Three months ended September 30, 2022, compared with the three months ended September 30, 2021
Earnings attributable to common shareholders were positively impacted by $415 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•a gain of $1,076 million ($732 million after-tax) on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP;
•a deferred tax benefit of $95 million recognized in the quarter as a result of the reduced Pennsylvania state corporate income tax;
•the absence of the $111 million ($83 million after-tax) impairment loss in 2021 to our investment in the PennEast Pipeline Company, LLC (PennEast) pipeline project after a decision by project partners to cease development;
•a net positive adjustment of $85 million ($75 million after-tax) due to the release of reserves associated with our enterprise insurance strategy; and
•non-cash, unrealized gains of $58 million ($44 million after-tax) in 2022, compared with unrealized losses of $88 million ($67 million after-tax) in 2021, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices; partially offset by
•non-cash, net unrealized derivative fair value losses of $1,334 million ($1,021 million after-tax) in 2022, compared with unrealized losses of $436 million ($332 million after-tax) in 2021, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks.
The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of our comprehensive economic hedging program to mitigate foreign exchange 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 $182 million increase in earnings attributable to common shareholders is primarily explained by:
•higher throughput within our Liquids Pipelines segment driven by higher demand and incremental Line 3 Replacement (L3R) capacity that came into service October 2021;
•increased earnings within our Liquids Pipelines segment from the implementation of the full L3R surcharge when compared to the lower surcharge on the Canadian portion of the project in effect prior to October 2021, as well as from new export assets acquired in October 2021;
•increased earnings from our Gas Transmission and Midstream segment primarily as a result of higher commodity prices benefiting our investments in DCP and Aux Sable Midstream LLC (Aux Sable), as well as higher contributions from projects placed into service in November 2021; and
•recognition of revenues attributable to the Texas Eastern rate case resulting from an uncontested Stipulation and Agreement; partially offset by
•higher interest expense primarily due to reduced capitalized interest associated with the US portion of the L3R Project placed into service in the fourth quarter of 2021, as well as higher average principal and higher interest rates; and
•higher depreciation and amortization expense as a result of several projects placed into service in the fourth quarter of 2021, as well as for new export assets acquired in October 2021.
Nine months ended September 30, 2022, compared with the nine months ended September 30, 2021
Earnings attributable to common shareholders were negatively impacted by $566 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•non-cash, net unrealized derivative fair value losses of $1,751 million ($1,340 million after-tax) in 2022, compared with unrealized gains of $85 million ($65 million after-tax) in 2021, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;
•a net negative adjustment to crude oil and natural gas inventories in our Energy Services business segment of $67 million ($50 million after-tax);
•the absence in 2022 of a $57 million ($43 million after-tax) property tax settlement received in 2021 related to the resolution of Minnesota property tax appeals for 2012-2018;
•an impairment of $44 million ($34 million after-tax) for lease assets due to office relocation plans; and
•an asset impairment loss of $40 million ($30 million after-tax) relating to MacKay River line within our Alberta Regional Oil Sands System; partially offset by
•a gain of $1,076 million ($732 million after-tax) on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP;
•a deferred tax benefit of $95 million recognized in the quarter as a result of the reduced Pennsylvania state corporate income tax;
•non-cash, unrealized gains of $22 million ($17 million after-tax) in 2022, compared with unrealized losses of $102 million ($78 million after-tax) in 2021, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices; and
•a non-cash, net negative equity earnings adjustment of $30 million ($22 million after-tax) in 2022, compared to a net negative adjustment of $104 million ($79 million after-tax) in 2021 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable.
After taking into consideration the factors above, the remaining $246 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:
•higher throughput within our Liquids Pipelines segment driven by higher demand and incremental L3R capacity that came into service October 2021;
•increased earnings within our Liquids Pipelines segment from the implementation of the full L3R surcharge when compared to the lower surcharge on the Canadian portion of the project in effect prior to October 2021, as well as from new export assets acquired in October 2021;
•increased earnings from our Gas Transmission and Midstream segment primarily as a result of higher commodity prices benefiting our investments in DCP and Aux Sable, as well as higher contributions from projects placed into service in November 2021; and
•recognition of revenues attributable to the Texas Eastern rate case resulting from an uncontested Stipulation and Agreement; partially offset by
•the recognition of a provision against the interim Mainline International Joint Tariff (IJT) for barrels shipped in 2022;
•higher interest expense primarily due to higher average principal and higher interest rates, as well as reduced capitalized interest associated with the US portion of the L3R Project placed into service in the fourth quarter of 2021; and
•higher depreciation and amortization expense as a result of several projects placed into service in the fourth quarter of 2021, as well as for new export assets acquired in October 2021.
BUSINESS SEGMENTS
LIQUIDS PIPELINES
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| | 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
Earnings before interest, income taxes and depreciation and amortization1 | 1,946 | | 1,673 | | | 6,093 | | 5,756 | |
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.
Three months ended September 30, 2022, compared with the three months ended September 30, 2021
EBITDA was negatively impacted by $98 million due to certain infrequent or other non-operating factors, primarily explained by non-cash, net unrealized losses of $290 million in 2022, compared with unrealized losses of $222 million in 2021, 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 risks.
After taking into consideration the factors above, the remaining $371 million increase is primarily explained by the following significant business factors:
•higher Mainline System ex-Gretna average throughput of 3.0 million barrels per day (mmbpd) in 2022 as compared to 2.7 mmbpd in 2021 driven by higher demand and incremental L3R capacity that came into service October 2021;
•implementation of the full L3R surcharge when compared to the lower surcharge on the Canadian portion of the project in effect prior to October 2021;
•higher contributions from the Gulf Coast and Mid-Continent System due primarily to the acquisition of the Enbridge Ingleside Energy Center (EIEC) and related assets in the fourth quarter of 2021, as well as higher volumes from our Flanagan South Pipeline (FSP), and increased indirect economic interest in the Gray Oak pipeline during the third quarter of 2022;
•higher contributions from the Bakken System due to higher volumes; and
•the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2022 compared to the same period in 2021; partially offset by
•the recognition of a provision against the interim Mainline IJT for barrels shipped in 2022;
•lower contributions from the Seaway Crude Pipeline System, as well as from the Cushing and Hardisty storage assets as a result of lower demand; and
•higher power costs as a result of increased volumes and power prices.
Nine months ended September 30, 2022, compared with the nine months ended September 30, 2021
EBITDA was negatively impacted by $621 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•non-cash, net unrealized losses of $364 million in 2022, compared with unrealized gains of $84 million in 2021, 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 risks;
•an asset impairment loss of $40 million relating to MacKay River line within our Alberta Regional Oil Sands System; and
•the absence in 2022 of a $57 million property tax settlement received in 2021 related to the resolution of Minnesota property tax appeals for 2012-2018.
After taking into consideration the factors above, the remaining $958 million increase is primarily explained by the following significant business factors:
•higher Mainline System ex-Gretna average throughput of 2.9 mmbpd in 2022 as compared to 2.7 mmbpd in 2021 driven by higher demand and incremental L3R capacity that came into service October 2021;
•implementation of the full L3R surcharge when compared to the lower surcharge on the Canadian portion of the project in effect prior to October 2021;
•higher contributions from the Gulf Coast and Mid-Continent System due primarily to the acquisition of the EIEC and related assets in the fourth quarter of 2021, as well as higher volumes from FSP, and increased indirect economic interest in the Gray Oak pipeline during the third quarter of 2022;
•higher contributions from the Bakken System due to higher volumes; and
•the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2022 compared to the same period in 2021; partially offset by
•the recognition of a provision against the interim Mainline IJT for barrels shipped in 2022;
•lower contributions from the Seaway Crude Pipeline System, as well as from the Cushing and Hardisty storage assets as a result of lower demand; and
•higher power costs as a result of increased volumes and power prices.
GAS TRANSMISSION AND MIDSTREAM
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| | 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
Earnings before interest, income taxes and depreciation and amortization1 | 2,251 | | 884 | | | 4,384 | | 2,725 | |
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.
Three months ended September 30, 2022, compared with the three months ended September 30, 2021
EBITDA was positively impacted by $1,195 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•a gain of $1,076 million on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP; and
•the absence of the $111 million impairment loss in 2021 to our investment in the PennEast pipeline project after a decision by project partners to cease development.
The remaining $172 million increase is primarily explained by the following significant business factors:
•contributions from the T-South and Spruce Ridge expansion projects after service commenced in November 2021;
•higher AECO-Chicago basis differential and lower costs benefiting earnings from our investment in Alliance Pipeline (Alliance);
•higher commodity prices benefiting our DCP and Aux Sable joint ventures;
•recognition of revenues attributable to the Texas Eastern rate case resulting from an uncontested Stipulation and Agreement;
•contributions from the Cameron Extension, Middlesex Extension, and the Appalachia to Market projects placed into service in the fourth quarter of 2021; and
•the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2022 compared to the same period in 2021; partially offset by
•a reduction in earnings from our investment in DCP as a result of our decreased interest due to the joint venture merger transaction with P66 that closed during the quarter.
Nine months ended September 30, 2022, compared with the nine months ended September 30, 2021
EBITDA was positively impacted by $1,287 million due to certain infrequent or other non-operating factors, primarily explained by the following:
•a gain of $1,076 million on the closing of the joint venture merger transaction with P66 realigning our indirect economic interests in Gray Oak and DCP;
•the absence of the $111 million impairment loss in 2021 to our investment in the PennEast pipeline project after a decision by project partners to cease development; and
•a non-cash, net negative equity earnings adjustment of $30 million in 2022, compared to a net negative adjustment of $104 million in 2021 relating to our share of changes in the mark-to-market value of derivative financial instruments of our equity method investees, DCP and Aux Sable.
The remaining $372 million increase is primarily explained by the following significant business factors:
•higher commodity prices benefiting our DCP and Aux Sable joint ventures;
•higher AECO-Chicago basis differential and lower costs benefiting earnings from our investment in Alliance;
•contributions from the T-South and Spruce Ridge expansion projects after service commenced in November 2021;
•recognition of revenues attributable to the Texas Eastern rate case resulting from an uncontested Stipulation and Agreement;
•contributions from the Cameron Extension, Middlesex Extension, and the Appalachia to Market projects placed into service in the fourth quarter of 2021; and
•the favorable effect of translating US dollar EBITDA at a higher average exchange rate in 2022 compared to the same period in 2021; partially offset by
•higher operating costs; and
•a reduction in earnings from our investment in DCP, as a result of our decreased interest due to the joint venture merger transaction with P66 that closed during the quarter.
GAS DISTRIBUTION AND STORAGE
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
Earnings before interest, income taxes and depreciation and amortization1 | 286 | | 282 | | | 1,368 | | 1,374 | |
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.
Three months ended September 30, 2022, compared with the three months ended September 30, 2021
EBITDA remained consistent year over year for the same three-month period due to higher distribution charges at Enbridge Gas, resulting from increases in rates and customer base, that were offset by higher operating and administrative costs related to higher maintenance and integrity spend, as well as timing of expenditures.
Nine months ended September 30, 2022, compared with the nine months ended September 30, 2021
EBITDA was negatively impacted by $6 million primarily explained by:
•the absence of earnings from Noverco Inc. due to the sale of our minority investment in December 2021; and
•higher operating costs at Enbridge Gas largely driven by higher maintenance and integrity spend, as well as the timing of expenditures; partially offset by
•higher distribution charges at Enbridge Gas resulting from increases in rates and customer base, as well as higher demand in the contract market; and
•when compared with the normal weather forecast embedded in rates, colder than normal weather in 2022 positively impacted Enbridge Gas 2022 EBITDA by approximately $28 million while warmer than normal weather in 2021 negatively impacted 2021 EBITDA by approximately $24 million.
RENEWABLE POWER GENERATION
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| | 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
Earnings before interest, income taxes and depreciation and amortization1 | 105 | | 91 | | | 389 | | 362 | |
1 Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.
Three months ended September 30, 2022, compared with the three months ended September 30, 2021
EBITDA was positively impacted by $14 million primarily due to higher energy pricing at European offshore wind facilities.
Nine months ended September 30, 2022, compared with the nine months ended September 30, 2021
EBITDA was positively impacted by $27 million primarily due to the following significant business factors:
•stronger wind resources at Canadian and US onshore wind facilities;
•higher energy pricing at European offshore wind facilities; and
•the absence in 2022 of the adverse effects from the major winter storm in Texas during February 2021; partially offset by
•the absence in 2022 of a promote fee received in the first quarter of 2021 associated with the closing of the sale of 49% of our interest in three European offshore wind projects to Canada Pension Plan Investment Board.
ENERGY SERVICES
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| | 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
Loss before interest, income taxes and depreciation and amortization1 | (70) | | (204) | | | (348) | | (379) | |
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.
EBITDA from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.
Three months ended September 30, 2022, compared with the three months ended September 30, 2021
EBITDA was positively impacted by $150 million due to certain non-operating factors, primarily explained by non-cash, unrealized gains of $58 million in 2022, compared with unrealized losses of $88 million in 2021, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as to manage the exposure to movements in commodity prices.
After taking into consideration the factor above, the remaining $16 million decrease is primarily explained by more pronounced market structure backwardation and significant compression of location differentials in certain markets as compared to the same period of 2021.
Nine months ended September 30, 2022, compared with the nine months ended September 30, 2021
EBITDA was positively impacted by $56 million due to certain non-operating factors, primarily explained by:
•non-cash, unrealized gains of $22 million in 2022, compared with unrealized losses of $102 million in 2021, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices; partially offset by
•a net negative adjustment to crude oil and natural gas inventories of $67 million.
After taking into consideration the factors above, the remaining $25 million decrease is primarily explained by the following significant business factors:
•more pronounced market structure backwardation and significant compression of location differentials in certain markets as compared to the same period of 2021; partially offset by
•the absence in 2022 of adverse impacts from the major winter storm experienced across the US Midwest during February 2021.
ELIMINATIONS AND OTHER
| | | | | | | | | | | | | | | | | |
| Three months ended
September 30, | | Nine months ended
September 30, |
| 2022 | 2021 | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
Earnings/(loss) before interest, income taxes and depreciation and amortization1 | (935) | | (121) | | | (1,284) | | 191 | |
1 Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.
Eliminations and Other includes operating and administrative costs and the impact of foreign exchange hedge settlements, which are not allocated to business segments. Eliminations and Other also includes the impact of new business development activities and corporate investments.
Three months ended September 30, 2022, compared with the three months ended September 30, 2021
EBITDA was negatively impacted by $755 million due to certain infrequent or non-operating factors, primarily explained by:
•non-cash, net unrealized losses of $1,046 million in 2022, compared with unrealized losses of $214 million in 2021, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk; partially offset by
•a net positive adjustment of $85 million due to the release of reserves associated with our enterprise insurance strategy.
After taking into consideration the non-operating factors above, the remaining $59 million decrease is primarily explained by lower realized foreign exchange gains on hedge settlements in 2022, as well as the timing of certain operating and administrative cost recoveries from the business units.
Nine months ended September 30, 2022, compared with the nine months ended September 30, 2021
EBITDA was negatively impacted by $1,446 million due to certain infrequent or non-operating factors, primarily explained by:
•non-cash, net unrealized losses of $1,393 million in 2022, compared with unrealized losses of $17 million in 2021, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;
•an impairment of $44 million for lease assets due to office relocation plans in Houston; and
•a net negative expense of $15 million associated with our enterprise insurance strategy.
After taking into consideration the non-operating factors above, the remaining $29 million decrease is primarily explained by the timing of certain operating and administrative cost recoveries from the business units, partially offset by higher realized foreign exchange gains on hedge settlements in 2022.
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 AND MIDSTREAM | | | |
| 1. | Gulfstream Phase VI | 50 | % | US$0.1 billion | US$0.1 billion | Complete | In-service |
| 2. | Vito Gas & Oil | 100 | % | US$0.3 billion | US$0.2 billion | Under construction | 4Q - 2022 |
| 3. | Texas Eastern Venice Extension Project3 | 100 | % | US$0.4 billion | No significant expenditures to date | Pre-construction | 2023 - 2024 |
| 4. | Texas Eastern Modernization | 100 | % | US$0.4 billion | No significant expenditures to date | Pre-construction | 2024 - 2025 |
| 5. | Appalachia to Market II | 100 | % | US$0.1 billion | No significant expenditures to date | Pre-construction | 2025 |
| 6. | T-North Expansion | 100 | % | $1.2 billion | No significant expenditures to date | Pre-construction | 2026 |
| 7. | Woodfibre LNG4 | 30 | % | US$1.5 billion | No significant expenditures to date | Pre-construction | 2027 |
| 8. | T-South Expansion | 100 | % | $3.6 billion | No significant expenditures to date | Pre-construction | 2028 |
| GAS DISTRIBUTION AND STORAGE | | | |
| 9. | Storage Enhancements5 | 100 | % | $0.1 billion | $0.1 billion | Under construction | 4Q - 2022 |
| 10. | System Enhancement Project | 100 | % | $0.1 billion | $0.1 billion | Under construction | 4Q - 2022 |
| 11. | Natural Gas Expansion Program6 | 100 | % | $0.1 billion | No significant expenditures to date | Pre-construction | 2022 - 2027 |
| 12. | Panhandle Regional Expansion | 100 | % | $0.3 billion | No significant expenditures to date | Pre-construction | 2023 - 2024 |
| RENEWABLE POWER GENERATION | | |
| 13. | East-West Tie Line | 25 | % | $0.2 billion | $0.2 billion | Complete | In-service |
| 14. | Saint-Nazaire France Offshore Wind Project7 | 25.5 | % | $0.9 billion | $0.7 billion | Under construction | 4Q - 2022 |
| (€0.6 billion) | (€0.5 billion) |
| 15. | Fécamp Offshore Wind Project8 | 17.9 | % | $0.7 billion | $0.3 billion | Under construction | 2023 |
| (€0.5 billion) | (€0.2 billion) |
| 16. | Provence Grand Large Floating Offshore Wind Project8 | 25 | % | $0.1 billion | $0.1 billion | Under construction | 2023 |
| (€0.1 billion) | (€0.1 billion) |
| 17. | Solar Self-Power Projects | 100 | % | US$0.2 billion | US$0.1 billion | Under construction | 2023 - 2024 |
| 18 | Calvados Offshore Wind Project7 | 21.7 | % | $0.9 billion | $0.3 billion | Under construction | 2025 |
| (€0.6 billion) | (€0.2 billion) |
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, 2022.
3This includes the Gator Express Project with an estimated capital cost of $31 million.
4Our equity contribution is US $0.9 billion, with the remainder of the project financed through non-recourse project level debt.
5The Storage Enhancements project commenced service on October 4, 2022.
6Represents Phase 2 of the Natural Gas Expansion Program and the estimated capital cost is presented net of the maximum funding assistance we expect to receive from the Government of Ontario. The expected in-service dates represent the expected completion dates of the leave to construct requirements.
7Our equity contribution is $0.2 billion for each project, with the remainder of each project financed through non-recourse project level debt.
8Our equity contribution is $0.1 billion for each project, with the remainder of each project financed through non-recourse project level debt.
A full description of each of our projects is provided in our annual report on Form 10-K for the year ended December 31, 2021. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.
GAS TRANSMISSION AND MIDSTREAM
•Texas Eastern Venice Extension Project – A reversal and expansion of Texas Eastern’s Line 40 from its existing New Roads compressor station to a new delivery point with the proposed Gator Express pipeline just south of Texas Eastern’s Larose compressor station. The project is expected to deliver 1.5 billion cubic feet per day (bcf/d) of natural gas to Venture Global Plaquemines LNG, LLC’s LNG export facility located in Plaquemines Parish, Louisiana and is underpinned by long-term take or pay contracts.
•T-North Expansion – An expansion of Westcoast Energy Inc.'s (WEI) BC Pipeline in northern BC that includes pipeline looping, additional compressor units and other ancillary station modifications to support 535 million cubic feet per day (MMcf/d) of additional capacity. The project will be underpinned by a cost-of-service commercial model with a target in-service date of 2026.
•Woodfibre LNG – Construction of liquefaction and floating storage facilities in Squamish, BC, as well as an expansion of the BC Pipeline System. The project is expected to be placed into service in 2027.
•T-South Expansion – An expansion of WEI's BC Pipeline's T-South section that includes pipeline looping, additional compressor units and other ancillary station modifications to support 300 MMcf/d of additional capacity. The project is expected to be placed in service in 2028 and will be underpinned by a cost-of-service commercial model.
GAS DISTRIBUTION AND STORAGE
•Panhandle Regional Expansion Project – Expansion of the Panhandle Transmission System, which supplies natural gas from the Dawn Hub to customers in Southern Ontario west of Dawn. The project consists of construction on Panhandle Loop and Leamington interconnect, and is expected to receive a full cost-of-service regulated return upon OEB approval with target in-service dates of November 2023 and November 2024.
•System Enhancement Project – On May 3, 2022, the OEB issued a Decision and Order denying the leave to construct application for the St. Laurent project. Subsequent to this decision, Enbridge Gas has continued to assess the condition of the line through integrity work, ensuring the ongoing safety and reliability of the line. As a result, the project has been excluded from the Growth Projects table.
RENEWABLE POWER GENERATION
•Calvados Offshore Wind Project – The Calvados Offshore Wind Project has experienced modest schedule pressures. The revised expected in-service date is 2025.
•Solar Self-Power Projects – The Solar Self-Power Projects have experienced modest schedule pressures. The revised expected in-service date is 2023-2024.
OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT
The following projects have been announced by us during the quarter, but have not yet met our criteria to be classified as commercially secured:
GAS TRANSMISSION AND MIDSTREAM
•Valley Crossing Expansion Project – On January 10, 2022, we executed a precedent agreement with Texas LNG Brownsville LLC (Texas LNG) under which, via an expansion of our Valley Crossing Pipeline, we will provide 0.72 bcf/d firm transportation capacity to Texas LNG’s proposed LNG liquefaction and export facility in the Port of Brownsville, Texas for a term of at least 20 years. Expansion of the pipeline will be subject to Texas LNG’s export facility reaching a final investment decision.
We also have a portfolio of additional projects under development that have not yet progressed to the point of securement.
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 issuance and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures, fund debt retirements, share redemptions, execute share repurchases under our normal course issuer bid (NCIB) and pay common and preference share dividends. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.
We have signed capital obligation contracts for the purchase of services, pipe and other materials totaling approximately $1.1 billion, which are expected to be paid over the next five years.
Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives. Our current financing plan does not include any issuances of additional common equity.
CAPITAL MARKET ACCESS
We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance 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, 2022:
| | | | | | | | | | | | | | |
| Maturity1 | Total
Facilities | Draws2 | Available |
| (millions of Canadian dollars) | | | | |
| Enbridge Inc. | 2023-2027 | 10,949 | | 9,451 | | 1,498 | |
| Enbridge (U.S.) Inc. | 2024-2027 | 8,245 | | 3,909 | | 4,336 | |
| Enbridge Pipelines Inc. | 2024 | 2,000 | | 858 | | 1,142 | |
| Enbridge Gas Inc. | 2024 | 2,000 | | 1,885 | | 115 | |
| Total committed credit facilities | | 23,194 | | 16,103 | | 7,091 | |
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.
On February 10, 2022, we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025.
On May 17, 2022, we entered into a three year term loan with a syndicate of Japanese banks for approximately $806 million (¥84.8 billion), which will mature in May 2025 and replaces the approximately $499 million (¥52.5 billion) term loan that matured in May 2022. Additionally, on May 24, 2022, we entered into a 364-day term loan for approximately $1.9 billion, which will mature in May 2023.
On June 23, 2022, we renewed approximately $5.5 billion of our 364-day extendible credit facilities to July 2024, which includes a one-year term out provision from July 2023.
In July and August 2022, we renewed $12.7 billion of our credit facilities, extending the maturity dates of our 364-day credit facilities to July 2024, inclusive of a one-year term out provision from July 2023, and our five year facilities out to July 2027. As a part of the renewals, we increased our credit facilities by approximately $641 million.
In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $780 million was unutilized as at September 30, 2022. As at December 31, 2021, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $854 million was unutilized.
As at September 30, 2022, our net available liquidity totaled $8.1 billion (December 31, 2021 - $6.5 billion), consisting of available credit facilities of $7.1 billion (December 31, 2021 - $6.2 billion) and was inclusive of unrestricted cash and cash equivalents of $1.0 billion (December 31, 2021 - $286 million) as reported in the Consolidated Statements of Financial Position.
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we are to default on payment or violate certain covenants. As at September 30, 2022, we are in compliance with all covenant provisions.
LONG-TERM DEBT ISSUANCES
During the nine months ended September 30, 2022, we completed the following long-term debt issuances totaling $1.4 billion and US$2.6 billion:
| | | | | | | | | | | | | | |
| Company | Issue Date | | | Principal Amount |
| (millions of Canadian dollars unless otherwise stated) | |
| Enbridge Inc. | | | |
| January 2022 | 5.00% | fixed-to-fixed subordinated notes due January 20821 | $750 |
| February 2022 | Floating rate senior notes due February 20242 | US$600 |
| February 2022 | 2.15% | senior notes due February 2024 | US$400 |
| February 2022 | 2.50% | senior notes due February 2025 | US$500 |
| September 2022 | 7.38% | fixed-to-fixed subordinated notes due January 20833 | US$500 |
| September 2022 | 7.63% | fixed-to-fixed subordinated notes due January 20834 | US$600 |
| Enbridge Gas Inc. | | | |
| August 2022 | 4.15 | % | medium-term notes due August 2032 | $325 |
| August 2022 | 4.55 | % | medium-term notes due August 2052 | $325 |
| | | |
| | | | |
| | | | |
| |
| | | | |
1For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 3.54%. Subsequent to year 10, every five years, the Five Year Government of Canada bond yield is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.29%.
2Notes carry an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 63 basis points.
3For the initial five years, the notes carry a fixed interest rate. At year five the interest rate will be set to equal to the Five-Year US Treasury rate plus a margin of 3.71%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 3.96%. Subsequent to year 10, every five years, the Five Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.71%.
4For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.42%. Subsequent to year 10, every five years, the Five-Year US Treasury rate will be reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.17%.
LONG-TERM DEBT REPAYMENTS
During the nine months ended September 30, 2022, we completed the following long-term debt repayments totaling US$1.5 billion and $0.3 billion:
| | | | | | | | | | | | | | |
| Company | Repayment Date | | | Principal Amount |
| (millions of Canadian dollars unless otherwise stated) | |
| Enbridge Inc. | | | |
| February 2022 | Floating rate notes1 | US$750 |
| February 2022 | 4.85% | medium-term notes | $200 |
| July 2022 | 2.90% | senior notes due July 2022 | US$700 |
| |
| | | | |
| Enbridge Gas Inc. | | | |
| April 2022 | 4.85% | medium-term notes | $125 |
| Enbridge Pipelines (Southern Lights) L.L.C. | |
| June 2022 | 3.98% | senior notes | US$34 |
| Enbridge Southern Lights LP | | | |
| June 2022 | 4.01% | senior notes | $9 |
| |
| | | | |
1Notes carried an interest rate set to equal the three-month London Interbank Offered Rate plus a margin of 50 basis points.
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 $36 million, as reported on the Consolidated Statements of Financial Position, primarily includes 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, 2022 and December 31, 2021, we had negative working capital position of $0.7 billion and $3.1 billion. In both periods, the major contributing factor to the negative working capital position was the ongoing funding of our growth capital program. We maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due.
SOURCES AND USES OF CASH
| | | | | | | | | | | |
| | | Nine months ended
September 30, |
| | | | | 2022 | 2021 |
| (millions of Canadian dollars) | | | | | |
| Operating activities | | | | 7,617 | | 7,366 | |
| Investing activities | | | | (3,158) | | (5,907) | |
| Financing activities | | | | (3,785) | | (1,422) | |
Effect of translation of foreign denominated cash and cash equivalents and restricted cash | | | | 63 | | (12) | |
| Net change in cash and cash equivalents and restricted cash | | | | 737 | | 25 | |
Significant sources and uses of cash for the nine months ended September 30, 2022 and 2021 are summarized below:
Operating Activities
Typically, the primary factors impacting cash flow from 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, as well as timing of 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 under Results of Operations.
Investing Activities
Cash used in investing activities primarily relates to capital expenditures to execute our capital program, which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements. Factors impacting the decrease in cash used in investing activities period-over-period primarily include:
•lower capital expenditures due to the US L3R Program that was placed into service in the fourth quarter of 2021; and
•proceeds from the completion of a joint venture merger transaction for DCP Midstream LLC in August 2022.
The factors above were partially offset by:
•increased contributions made to our equity investment in Bakken Pipeline System due to debt servicing requirements;
•our acquisition of TGE in September 2022; and
•increased investments held by our wholly-owned captive insurance subsidiaries.
Financing Activities
Cash used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, share redemptions and common share repurchases under our NCIB. Cash flow from financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the increase in cash used in financing activities period-over-period primarily include:
•the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022, respectively;
•lower long-term debt issuances and higher long-term debt repayments in 2022, when compared to the same period in 2021;
•the repurchase and cancellation of 2,737,965 common shares under our NCIB for approximately $151 million during the period; and
•common share dividend payments increased period-over-period primarily due to the 3% increase in our common share dividend rate.
The factors above were partially offset by:
•net commercial paper and credit facility draws in 2022 when compared to net repayments in the same period in 2021;
•higher short-term borrowings in 2022 when compared to the same period in 2021; and
•the absence of the redemption of WEI's preferred shares in the first quarter of 2021.
SUMMARIZED FINANCIAL INFORMATION
On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP) (the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes.
Consenting SEP notes and EEP notes under Guarantee
| | | | | |
SEP Notes1 | EEP Notes2 |
| 4.750% Senior Notes due 2024 | 5.875% Notes due 2025 |
| 3.500% Senior Notes due 2025 | 5.950% Notes due 2033 |
| 3.375% Senior Notes due 2026 | 6.300% Notes due 2034 |
| 5.950% Senior Notes due 2043 | 7.500% Notes due 2038 |
| 4.500% Senior Notes due 2045 | 5.500% Notes due 2040 |
| |
| 7.375% Notes due 2045 |
1As at September 30, 2022, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.
2As at September 30, 2022, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.
Enbridge Notes under Guarantees
| | | | | |
USD Denominated1 | CAD Denominated2 |
| Floating Rate Senior Notes due 2023 | 3.190% Senior Notes due 2022 |
| Floating Rate Senior Notes due 2024 | 3.940% Senior Notes due 2023 |
| 4.000% Senior Notes due 2023 | 3.940% Senior Notes due 2023 |
| 0.550% Senior Notes due 2023 | 3.950% Senior Notes due 2024 |
| 3.500% Senior Notes due 2024 | 2.440% Senior Notes due 2025 |
| 2.150% Senior Notes due 2024 | 3.200% Senior Notes due 2027 |
| 2.500% Senior Notes due 2025 | 6.100% Senior Notes due 2028 |
| 2.500% Senior Notes due 2025 | 2.990% Senior Notes due 2029 |
| 4.250% Senior Notes due 2026 | 7.220% Senior Notes due 2030 |
| 1.600% Senior Notes due 2026 | 7.200% Senior Notes due 2032 |
| 3.700% Senior Notes due 2027 | 3.100% Sustainability-Linked Senior Notes due 2033 |
| 3.125% Senior Notes due 2029 | 5.570% Senior Notes due 2035 |
| 2.500% Sustainability-Linked Senior Notes due 2033 | 5.750% Senior Notes due 2039 |
| 4.500% Senior Notes due 2044 | 5.120% Senior Notes due 2040 |
| 5.500% Senior Notes due 2046 | 4.240% Senior Notes due 2042 |
| 4.000% Senior Notes due 2049 | 4.570% Senior Notes due 2044 |
| 3.400% Senior Notes due 2051 | 4.870% Senior Notes due 2044 |
| 4.100% Senior Notes due 2051 |
| 4.560% Senior Notes due 2064 |
1As at September 30, 2022, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$11.0 billion.
2As at September 30, 2022, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $9.0 billion.
Rule 3-10 of the US SEC Regulation S-X provides an exemption from the reporting requirements of the Exchange Act for fully consolidated subsidiary issuers of guaranteed securities and subsidiary guarantors and allows for summarized financial information in lieu of filing separate financial statements for each of the Partnerships.
The following Summarized Combined Statement of Earnings and Summarized Combined Statements of Financial Position combines the balances of EEP, SEP and Enbridge.
Summarized Combined Statement of Earnings
| | | | | |
| Nine months ended September 30, | 2022 |
| (millions of Canadian dollars) | |
| |
| Operating loss | (124) | |
| Earnings | 333 | |
| Earnings attributable to common shareholders | 3 | |
Summarized Combined Statements of Financial Position
| | | | | | | | | | |
| | September 30,
2022 | | December 31,
2021 |
| (millions of Canadian dollars) | | | | |
| Accounts receivable from affiliates | | 2,482 | | | 3,442 | |
| Short-term loans receivable from affiliates | | 8,613 | | | 4,947 | |
| Other current assets | | 433 | | | 605 | |
| Long-term loans receivable from affiliates | | 45,857 | | | 51,983 | |
| Other long-term assets | | 4,609 | | | 3,732 | |
| Accounts payable to affiliates | | 1,339 | | | 1,982 | |
| Short-term loans payable to affiliates | | 3,368 | | | 2,891 | |
| Other current liabilities | | 6,097 | | | 8,110 | |
| Long-term loans payable to affiliates | | 39,208 | | | 41,370 | |
| Other long-term liabilities | | 48,842 | | | 41,353 | |
The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-Guarantors.
Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee:
•received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;
•was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
•intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.
The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under US federal or state law.
Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.
Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:
•any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;
•the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;
•the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement;
•with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;
•with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or
•with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.
The guarantee obligations of Enbridge will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.
The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities.
LEGAL AND OTHER UPDATES
LIQUIDS PIPELINES
Line 5 Easement
On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a complaint in the United States District Court for the Western District of Wisconsin (the Court) over our Line 5 pipeline and right-of-way across the Bad River Reservation (the Reservation). Only a small portion of the total easements across 12 miles of the Reservation are at issue. The Band alleges that our continued use of Line 5 to transport crude oil and related liquids across the Reservation is a public nuisance under federal and state law and that the pipeline is in trespass on certain tracts of land in which the Band possesses ownership interests. The complaint seeks an order prohibiting us from using Line 5 to transport crude oil and related liquids across the Reservation and requiring removal of the pipeline from the Reservation. Subsequently amended versions of the complaint also seek recovery of profits-based damages based on an unjust enrichment theory. Enbridge has responded to each claim in the initial and amended complaints with an answer, defenses and counterclaims.
On August 29, 2022, the Government of Canada released a statement formally invoking the dispute settlement provisions of the 1977 Transit Pipelines Treaty in respect of this litigation; reiterating its concerns about the uninterrupted transmission of hydrocarbons through Line 5. On September 7, 2022, the Court issued a decision on cross-motions for summary judgment. The Court determined that the Band’s nuisance claim raised factual issues that could not be resolved on summary judgment. The Court further determined that Enbridge is in trespass on certain tracts on the Reservation and that the Band is entitled to some measure of profits-based damages and to an injunction, with the level of damages and scope of the injunction to be determined at trial, which occurred between October 24 and November 1, 2022. While the Court reserved judgment at the conclusion of the trial, the summary judgment decision and subsequent pre-trial decisions provide that the Court will assess trespass damages calculated using a pro-rata share of Enbridge’s profits from the operation of the pipeline attributable to the 12 disputed parcels compared to the pipeline as a whole rather than the profits associated with the entire length of the pipeline, as the Band sought. The Court has also stated that any injunction will not result in the immediate closure of the pipeline but also will not allow the pipeline to operate indefinitely.
Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement
In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit Court (the Circuit Court) that requests the Circuit Court to declare the easement granted in 1953 that we have for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits. On December 15, 2021, we removed the case to the US District Court in the Western District of Michigan (US District Court), where it was assigned to Judge Janet T. Neff. The removal of the AG’s case to federal court follows a November 16, 2021 ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force Line 5’s shutdown raised important federal issues that should be heard in federal court. On December 21, 2021, the AG made a request to file a remand motion and on December 28, 2021, we responded to her request to file that motion. On January 5, 2022, the court issued an Order allowing the AG to file a motion to
remand the 2019 case. The AG’s motion and brief were filed on January 14, 2022, and our response was filed on February 11, 2022. The motion was fully briefed in March 2022. On August 18, 2022, Judge Neff denied the AG’s motion to remand which now remains in the US District Court. On August 30, 2022, the AG filed a motion to certify the US District Court’s August 18 Order to pursue an appeal on the jurisdictional issue, which Enbridge opposed. We anticipate a decision on the jurisdictional issue in 2022.
OTHER LITIGATION
We and our subsidiaries are involved in various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.
TAX MATTERS
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.
CHANGES IN ACCOUNTING POLICIES
Refer to Part I. Item 1. Financial Statements - Note 2. Changes in Accounting Policies.