UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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| ☒ | | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 20182023
OR
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o
☐ | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-10934
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ENBRIDGE INC. |
| (Exact Name of Registrant as Specified in Its Charter) |
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| Canada | | None98-0377957 |
(State or Other Jurisdiction of Incorporation or Organization) | | (I.R.S. Employer Identification No.) |
200, 425 - 1st Street S.W.
Calgary, Alberta, CanadaT2P 3L8
(Address of Principal Executive Offices) (Zip Code)
(403) 231-3900
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
| Common Shares | | ENB | | New York Stock Exchange |
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesx Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesx Noo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer | x | | Accelerated filer | | Accelerated filer o
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Non-accelerated filero (Do not check if a smaller reporting company) | ☐ |
| Smaller reporting companyo | ☐ |
Emerging growth companyo | ☐ | | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso ☐ Nox
The registrant had 1,704,740,1772,024,676,423 common shares outstanding as of May 4, 2018.at April 28, 2023.
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| PART I | PAGE |
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| Item 1. | | |
| Item 2. | | |
| Item 3. | | |
| Item 4. | | |
| PART II | |
| PART II | |
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| Item 1. | | |
| Item 1A. | | |
| Item 2. | | |
| Item 3. | | |
| Item 4. | | |
| Item 5. | | |
| Item 6. | | |
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GLOSSARY
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| AG | Attorney General |
| AOCI | Accumulated other comprehensive income/(loss) |
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AOCI | Accumulated other comprehensive income/(loss) |
ALJ | Administrative Law Judge |
ASU | Accounting Standards Update |
Canadian L3R Program | Canadian portion of the Line 3 Replacement Program |
CIACsDAPL | Contributions in Aid of ConstructionDakota Access Pipeline |
EBITDADCP | DCP Midstream, LP |
| EBITDA | Earnings before interest, income taxes and depreciation and amortization |
Eddystone Rail | Eddystone Rail Company, LLC |
| EEP | Enbridge Energy Partners, L.P. |
EGD | |
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| EIS | Environmental Impact Statement |
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| Enbridge | Enbridge Inc. |
| Enbridge Gas | Enbridge Gas Distribution Inc. |
Enbridge | Enbridge Inc. |
FERC | Federal Energy Regulatory Commission |
IDRsExchange Act | Incentive distribution rightsUnited States Securities Exchange Act of 1934, as amended |
Line 10 | Line 10 crude oil pipeline |
MNPUC | Minnesota Public Utilities Commission |
NGL | |
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| NCIB | Normal course issuer bid |
| NGL | Natural gas liquids |
OCI | |
| OCI | Other comprehensive income/(loss) |
Route Permit | United States Line 3 Replacement Program route permit |
Sabal Trail | Sabal Trail Transmission, LLC |
SEPOPEB | Other postretirement benefits |
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| SEP | Spectra Energy Partners, LP |
TCJA | Tax Cuts and Jobs Act |
Texas Express NGL pipeline system | Texas Express PL LLC and Texas Express Gathering LLC |
the Merger Transaction | The stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp |
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| Texas Eastern | Texas Eastern Transmission, LP |
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| Tres Palacios | Tres Palacios Holdings LLC |
| US | United States |
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CONVENTIONS
The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge.
Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to “dollars”, “$”"dollars" or “C$”"$" are to Canadian dollars and all references to “US$”"US$" are to United States (US) dollars. All amounts are provided on a before taxbefore-tax basis, unless otherwise stated.
FORWARD-LOOKING INFORMATION
Forward-looking information, or forward-looking statements, have been included in this quarterly report on Form 10-Q to provide information about us and our subsidiaries and affiliates, including management’s assessment of Enbridgeour and itsour subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: our corporate vision and strategy, including strategic priorities and enablers; expected earnings before interest, income taxessupply of, demand for, exports of and depreciationprices of crude oil, natural gas, natural gas liquids (NGL), liquified natural gas (LNG) and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows; expected performancerenewable energy; energy transition and lower-carbon energy, and our approach thereto; environmental, social and governance goals, practices and performance; industry and market conditions; anticipated utilization of the Liquids Pipelines, Gas Transmissionour assets; dividend growth and Midstream, Gas Distribution, Green Power and Transmission, and Energy Services businesses;payout policy; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected strategic priorities and performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation and Energy Services businesses; expected costs, benefits and in-service dates related to announced projects and projects under construction; expected in-service dates for announced projectscapital expenditures; investable capacity and projectscapital allocation priorities; share repurchases under construction;expected capital expenditures;our normal course issuer bid; expected equity funding requirements for our commercially secured growth program; expected future growth, development and expansion opportunities; expected optimization and efficiency opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions;estimated future dividends; recoverydispositions and the timing thereof; expected benefits of the costs of the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program);transactions; expected future actions of regulators; expected costs relatedregulators and courts, and the timing and impact thereof; toll and rate cases discussions and proceedings and anticipated timeline and impact therefrom, including Mainline Tolling and those relating to leak remediationthe Gas Transmission and Midstream and Gas Distribution and Storage businesses; operational, industry, regulatory, climate change and other risks associated with our businesses; and our assessment of the potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction) including our combined scale, financial flexibility, growth program, future business prospects and performance; impact of the Canadian L3R Program on existing integrity programs; the sponsored vehicle strategy; dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of hedging program; and expectations resulting from the successful execution of our 2018-2020 Strategic Plan.various risk factors identified herein.
Although we believe these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of, and demand for, crude oil, natural gas, natural gas liquids (NGL)export of and renewable energy; prices of crude oil, natural gas, NGL, LNG and renewable energy; anticipated utilization of assets; exchange rates; inflation; interest rates; availability and price of labor and construction materials; the stability of our supply chain; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the timing and closing of acquisitions and dispositions; the realization of anticipated benefits and synergies of the Merger Transaction;transactions; governmental legislation; acquisitionslitigation; estimated future dividends and the timing thereof; the success of integration plans;impact of theour dividend policy on our future cash flows; our credit ratings; capital project funding; hedging program; expected EBITDA;earnings before interest, income taxes, and depreciation and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per share; expected future cash flowsflows; and estimated future dividends.expected distributable cash flow. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL, LNG and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty,particularly with respect to the impact of the Merger Transaction on us,expected EBITDA, earnings/(loss), earnings/(loss) per share, or estimated future dividends. The most relevant assumptions associated with forward-looking statements onregarding announced projects and projects under
construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the stability of
our supply chain; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.
Our forward-looking statements are subject to risks and uncertainties pertaining to the impactsuccessful execution of our strategic priorities, operating performance; legislative and regulatory parameters; litigation; acquisitions, dispositions and other transactions and the Merger Transaction, operating performance, regulatory parameters,realization of anticipated benefits therefrom; operational dependence on third parties; dividend policy,policy; project approval and support,support; renewals of rights-of-way, weather,rights-of-way; weather; economic and competitive conditions,conditions; public opinion,opinion; changes in tax laws and tax rates, changes in trade agreements,rates; exchange rates,rates; inflation; interest rates,rates; commodity prices,prices; access to and cost of capital; political decisionsdecisions; global geopolitical conditions; and the supply of, and demand for and prices of commodities and other alternative energy, including but not limited to, those risks and uncertainties discussed in this quarterly report on Form 10-Q and in our other filings with Canadian and United StatesUS securities regulators. The impact of any one assumption, risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge Inc. assumes no obligation to publicly update or revise any forward-looking statementsstatement made in this quarterly report on Form 10-Q or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.
NON-GAAP AND OTHER FINANCIAL MEASURES
Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this quarterly report on Form 10-Q makes reference to non-GAAP and other financial measures, including EBITDA. EBITDA is defined as earnings before interest, income taxes and depreciation and amortization. Management uses EBITDA to assess performance of Enbridge and to set targets. Management believes the presentation of EBITDA gives useful information to investors as it provides increased transparency and insight into the performance of Enbridge.
The non-GAAP and other financial measures are not measures that have a standardized meaning prescribed by the accounting principles generally accepted in the United States of America (US GAAP) and are not US GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. A reconciliation of historical non-GAAP and other financial measures to the most directly comparable GAAP measures is set out in this MD&A and is available on our website. Additional information on non-GAAP and other financial measures may be found on our website, www.sedar.com or www.sec.gov.
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS
| | | | Three months ended
March 31, | | | Three months ended
March 31, |
| | 2018 |
| 2017 |
| | | 2023 | 2022 |
| (unaudited; millions of Canadian dollars, except per share amounts) | |
| |
| (unaudited; millions of Canadian dollars, except per share amounts) | | | |
| Operating revenues | |
| |
| Operating revenues | | | |
| Commodity sales | 7,268 |
| 6,866 |
| Commodity sales | | 4,783 | | 8,325 | |
| Gas distribution sales | 1,926 |
| 1,363 |
| Gas distribution sales | | 2,279 | | 2,098 | |
| Transportation and other services | 3,532 |
| 2,917 |
| Transportation and other services | | 5,013 | | 4,674 | |
Total operating revenues (Note 3) | 12,726 |
| 11,146 |
| |
Total operating revenues (Note 2) | | Total operating revenues (Note 2) | | 12,075 | | 15,097 | |
| Operating expenses | | | Operating expenses | | | |
| Commodity costs | 6,997 |
| 6,550 |
| Commodity costs | | 4,636 | | 8,291 | |
| Gas distribution costs | 1,324 |
| 1,015 |
| Gas distribution costs | | 1,594 | | 1,456 | |
| Operating and administrative | 1,641 |
| 1,551 |
| Operating and administrative | | 2,037 | | 1,875 | |
| Depreciation and amortization | 824 |
| 672 |
| Depreciation and amortization | | 1,146 | | 1,055 | |
Asset impairment (Note 6) | 1,062 |
| — |
| |
| | Total operating expenses | 11,848 |
| 9,788 |
| Total operating expenses | | 9,413 | | 12,677 | |
| Operating income | 878 |
| 1,358 |
| Operating income | | 2,662 | | 2,420 | |
| Income from equity investments | 335 |
| 236 |
| Income from equity investments | | 517 | | 491 | |
| Other income/(expense) | | | |
| Net foreign currency loss | (185 | ) | (5 | ) | |
| Other | 65 |
| 40 |
| |
| Other income (Note 9) | | Other income (Note 9) | | 102 | | 458 | |
| Interest expense | (656 | ) | (486 | ) | Interest expense | | (905) | | (719) | |
| Earnings before income taxes | 437 |
| 1,143 |
| Earnings before income taxes | | 2,376 | | 2,650 | |
Income tax recovery/(expense) (Note 11) | 73 |
| (198 | ) | |
| Income tax expense | | Income tax expense | | (510) | | (593) | |
| Earnings | 510 |
| 945 |
| Earnings | | 1,866 | | 2,057 | |
| (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests | 24 |
| (224 | ) | |
| Earnings attributable to noncontrolling interests | | Earnings attributable to noncontrolling interests | | (49) | | (28) | |
| Earnings attributable to controlling interests | 534 |
| 721 |
| Earnings attributable to controlling interests | | 1,817 | | 2,029 | |
| Preference share dividends | (89 | ) | (83 | ) | Preference share dividends | | (84) | | (102) | |
| Earnings attributable to common shareholders | 445 |
| 638 |
| Earnings attributable to common shareholders | | 1,733 | | 1,927 | |
Earnings per common share attributable to common shareholders (Note 5)
| 0.26 |
| 0.54 |
| |
Diluted earnings per common share attributable to common shareholders (Note 5) | 0.26 |
| 0.54 |
| |
Earnings per common share attributable to common shareholders (Note 4) | | Earnings per common share attributable to common shareholders (Note 4) | | 0.86 | | 0.95 | |
Diluted earnings per common share attributable to common shareholders (Note 4) | | Diluted earnings per common share attributable to common shareholders (Note 4) | | 0.85 | | 0.95 | |
SeeThe accompanying notes to theare an integral part of these interim consolidated financial statements.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| | | | Three months ended
March 31, | | | Three months ended
March 31, |
| | 2018 |
| 2017 |
| | | 2023 | 2022 |
| (unaudited; millions of Canadian dollars) | |
| |
| (unaudited; millions of Canadian dollars) | | | |
| Earnings | 510 |
| 945 |
| Earnings | | 1,866 | | 2,057 | |
| Other comprehensive income/(loss), net of tax | | | Other comprehensive income/(loss), net of tax | | | |
| Change in unrealized gain/(loss) on cash flow hedges | 66 |
| (2 | ) | Change in unrealized gain/(loss) on cash flow hedges | | (45) | | 294 | |
| Change in unrealized gain/(loss) on net investment hedges | (184 | ) | 49 |
| |
| Other comprehensive income from equity investees | 14 |
| 6 |
| |
| Change in unrealized gain on net investment hedges | | Change in unrealized gain on net investment hedges | | 15 | | 133 | |
| | Excluded components of fair value hedges | | Excluded components of fair value hedges | | 7 | | (1) | |
| Reclassification to earnings of loss on cash flow hedges | 37 |
| 41 |
| Reclassification to earnings of loss on cash flow hedges | | 7 | | 57 | |
| Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts | (39 | ) | 4 |
| Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts | | (4) | | (2) | |
| | Foreign currency translation adjustments | 1,579 |
| 432 |
| Foreign currency translation adjustments | | (59) | | (708) | |
| Other comprehensive income, net of tax | 1,473 |
| 530 |
| |
| Other comprehensive loss, net of tax | | Other comprehensive loss, net of tax | | (79) | | (227) | |
| Comprehensive income | 1,983 |
| 1,475 |
| Comprehensive income | | 1,787 | | 1,830 | |
| Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests | (147 | ) | (374 | ) | |
| Comprehensive income attributable to noncontrolling interests | | Comprehensive income attributable to noncontrolling interests | | (64) | | (13) | |
| Comprehensive income attributable to controlling interests | 1,836 |
| 1,101 |
| Comprehensive income attributable to controlling interests | | 1,723 | | 1,817 | |
| Preference share dividends | (89 | ) | (83 | ) | Preference share dividends | | (84) | | (102) | |
| Comprehensive income attributable to common shareholders | 1,747 |
| 1,018 |
| Comprehensive income attributable to common shareholders | | 1,639 | | 1,715 | |
SeeThe accompanying notes to theare an integral part of these interim consolidated financial statements.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (unaudited; millions of Canadian dollars, except per share amounts) | |
| |
|
| Preference shares | | |
| Balance at beginning and end of period | 7,747 |
| 7,255 |
|
| Common shares | |
| |
|
| Balance at beginning of period | 50,737 |
| 10,492 |
|
| Common shares issued in Merger Transaction | — |
| 37,428 |
|
| Dividend Reinvestment and Share Purchase Plan | 374 |
| 194 |
|
| Shares issued on exercise of stock options | 16 |
| 33 |
|
| Balance at end of period | 51,127 |
| 48,147 |
|
| Additional paid-in capital | |
| |
|
| Balance at beginning of period | 3,194 |
| 3,399 |
|
| Stock-based compensation | 17 |
| 35 |
|
| Fair value of outstanding earned stock-based compensation from Merger Transaction | — |
| 77 |
|
| Options exercised | (6 | ) | (49 | ) |
Dilution gain on Spectra Energy Partners, LP restructuring (Note 9) | 1,136 |
| — |
|
| Dilution loss and other | (28 | ) | (36 | ) |
| Balance at end of period | 4,313 |
| 3,426 |
|
| Deficit | |
| |
|
| Balance at beginning of period | (2,468 | ) | (716 | ) |
| Earnings attributable to controlling interests | 534 |
| 721 |
|
| Preference share dividends | (89 | ) | (83 | ) |
| Common share dividends declared | — |
| (548 | ) |
| Dividends paid to reciprocal shareholder | 7 |
| 7 |
|
Retrospective adoption of accounting standard (Note 2) | (86 | ) | — |
|
| Redemption value adjustment attributable to redeemable noncontrolling interests | 120 |
| 152 |
|
| Adjustment for the recognition of unutilized tax deductions for stock-based compensation expense | — |
| 41 |
|
| Balance at end of period | (1,982 | ) | (426 | ) |
Accumulated other comprehensive income/(loss) (Note 8) | |
| |
|
| Balance at beginning of period | (973 | ) | 1,058 |
|
| Other comprehensive income attributable to common shareholders, net of tax | 1,302 |
| 380 |
|
| Balance at end of period | 329 |
| 1,438 |
|
| Reciprocal shareholding | |
| |
|
| Balance at beginning and end of period | (102 | ) | (102 | ) |
| Total Enbridge Inc. shareholders’ equity | 61,432 |
| 59,738 |
|
| Noncontrolling interests | |
| |
|
| Balance at beginning of period | 7,597 |
| 577 |
|
| Earnings attributable to noncontrolling interests | 23 |
| 192 |
|
| Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax | | |
| Change in unrealized gain/(loss) on cash flow hedges | 4 |
| (1 | ) |
| Foreign currency translation adjustments | 152 |
| 141 |
|
| Reclassification to earnings of loss on cash flow hedges | 8 |
| 10 |
|
| | 164 |
| 150 |
|
| Comprehensive income attributable to noncontrolling interests | 187 |
| 342 |
|
| Noncontrolling interests resulting from Merger Transaction | — |
| 8,792 |
|
| Enbridge Energy Company, Inc. common control transaction | — |
| 43 |
|
| Distributions | (209 | ) | (191 | ) |
| Contributions | 8 |
| 215 |
|
Spectra Energy Partners, LP restructuring (Note 9) | (1,486 | ) | — |
|
| Other | (15 | ) | 3 |
|
| Balance at end of period | 6,082 |
| 9,781 |
|
| Total equity | 67,514 |
| 69,519 |
|
| Dividends paid per common share | 0.671 |
| 0.583 |
|
See | | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | | 2023 | 2022 |
| (unaudited; millions of Canadian dollars, except per share amounts) | | | | | |
| Preference shares | | | | | |
| Balance at beginning of period | | | | 6,818 | | 7,747 | |
| Redemption of preference shares | | | | — | | (737) | |
| Balance at end of period | | | | 6,818 | | 7,010 | |
| Common shares | | | | | |
| Balance at beginning of period | | | | 64,760 | | 64,799 | |
| Shares issued on exercise of stock options | | | | 2 | | 36 | |
| Shares issued on vesting of restricted stock units (RSU) | | | | 12 | | — | |
| Share purchases at stated value | | | | — | | (30) | |
| Other | | | | — | | (4) | |
| Balance at end of period | | | | 64,774 | | 64,801 | |
| Additional paid-in capital | | | | | |
| Balance at beginning of period | | | | 275 | | 365 | |
| Stock-based compensation | | | | — | | 13 | |
| Options exercised | | | | (1) | | (34) | |
| | | | | |
| Other | | | | — | | (28) | |
| Balance at end of period | | | | 274 | | 316 | |
| Deficit | | | | | |
| Balance at beginning of period | | | | (15,486) | | (10,989) | |
| Earnings attributable to controlling interests | | | | 1,817 | | 2,029 | |
| Preference share dividends | | | | (84) | | (102) | |
| | | | | |
| | | | | |
| Share purchases in excess of stated value | | | | — | | (20) | |
| | | | | |
| Balance at end of period | | | | (13,753) | | (9,082) | |
Accumulated other comprehensive income/(loss) (Note 6) | | | | | |
| Balance at beginning of period | | | | 3,520 | | (1,096) | |
| Other comprehensive loss attributable to common shareholders, net of tax | | | | (94) | | (212) | |
| Balance at end of period | | | | 3,426 | | (1,308) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Total Enbridge Inc. shareholders’ equity | | | | 61,539 | | 61,737 | |
| Noncontrolling interests | | | | | |
| Balance at beginning of period | | | | 3,511 | | 2,542 | |
| Earnings attributable to noncontrolling interests | | | | 49 | | 28 | |
| Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax | | | | | |
| Change in unrealized gain on cash flow hedges | | | | 17 | | 2 | |
| Foreign currency translation adjustments | | | | (2) | | (17) | |
| | | | | 15 | | (15) | |
| Comprehensive income attributable to noncontrolling interests | | | | 64 | | 13 | |
| Distributions | | | | (92) | | (60) | |
| Contributions | | | | 4 | | 6 | |
| | | | | |
| Other | | | | (1) | | 35 | |
| Balance at end of period | | | | 3,486 | | 2,536 | |
| Total equity | | | | 65,025 | | 64,273 | |
| Dividends paid per common share | | | | 0.888 | | 0.860 | |
The accompanying notes to theare an integral part of these interim consolidated financial statements.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | Three months ended
March 31, | | Three months ended
March 31, |
| | 2018 |
| 2017 |
| | 2023 | 2022 |
| (unaudited; millions of Canadian dollars) | | | (unaudited; millions of Canadian dollars) | | |
| Operating activities | | | Operating activities | | |
| Earnings | 510 |
| 945 |
| Earnings | 1,866 | | 2,057 | |
| Adjustments to reconcile earnings to net cash provided by operating activities: | |
| |
| Adjustments to reconcile earnings to net cash provided by operating activities: | | |
| Depreciation and amortization | 824 |
| 672 |
| Depreciation and amortization | 1,146 | | 1,055 | |
| Deferred income tax expense | (147 | ) | 161 |
| Deferred income tax expense | 484 | | 423 | |
Changes in unrealized (gain)/loss on derivative instruments, net (Note 10) | 260 |
| (418 | ) | |
| Earnings from equity investments | (335 | ) | (236 | ) | |
Unrealized derivative fair value gain, net (Note 7) | | Unrealized derivative fair value gain, net (Note 7) | (520) | | (369) | |
| Income from equity investments | | Income from equity investments | (517) | | (491) | |
| Distributions from equity investments | 320 |
| 214 |
| Distributions from equity investments | 453 | | 394 | |
| Asset impairment | 1,062 |
| — |
| |
| Gain on dispositions | — |
| (14 | ) | |
| | Other | 78 |
| 112 |
| Other | 40 | | 47 | |
| Changes in operating assets and liabilities | 622 |
| 340 |
| Changes in operating assets and liabilities | 914 | | (177) | |
| Net cash provided by operating activities | 3,194 |
| 1,776 |
| Net cash provided by operating activities | 3,866 | | 2,939 | |
| Investing activities | |
| |
| Investing activities | | |
| Capital expenditures | (1,635 | ) | (1,642 | ) | Capital expenditures | (1,129) | | (1,048) | |
| Long-term investments | (209 | ) | (2,537 | ) | |
| Long-term investments and restricted long-term investments | | Long-term investments and restricted long-term investments | (413) | | (314) | |
| Distributions from equity investments in excess of cumulative earnings | 57 |
| 11 |
| Distributions from equity investments in excess of cumulative earnings | 100 | | 97 | |
| Restricted long-term investments | (13 | ) | (15 | ) | |
| Additions to intangible assets | (258 | ) | (233 | ) | Additions to intangible assets | (66) | | (53) | |
| Cash acquired in Merger Transaction | — |
| 681 |
| |
| Proceeds from dispositions | — |
| 289 |
| |
| | Affiliate loans, net | (10 | ) | (2 | ) | Affiliate loans, net | 71 | | — | |
| | Net cash used in investing activities | (2,068 | ) | (3,448 | ) | Net cash used in investing activities | (1,437) | | (1,318) | |
| Financing activities | |
| |
| Financing activities | | |
| Net change in short-term borrowings | (443 | ) | 110 |
| Net change in short-term borrowings | (559) | | 89 | |
| Net change in commercial paper and credit facility draws | (465 | ) | 2,662 |
| Net change in commercial paper and credit facility draws | (2,921) | | (283) | |
| Debenture and term note issues, net of issue costs | 2,061 |
| — |
| Debenture and term note issues, net of issue costs | 4,111 | | 2,643 | |
| Debenture and term note repayments | (996 | ) | (513 | ) | Debenture and term note repayments | (968) | | (1,155) | |
| Debt extinguishment costs | (63 | ) | — |
| |
| Contributions from noncontrolling interests | 8 |
| 215 |
| Contributions from noncontrolling interests | 4 | | 6 | |
| Distributions to noncontrolling interests | (209 | ) | (271 | ) | Distributions to noncontrolling interests | (92) | | (60) | |
| Contributions from redeemable noncontrolling interests | 20 |
| 11 |
| |
| Distributions to redeemable noncontrolling interests | (84 | ) | (54 | ) | |
| Common shares issued | 13 |
| 4 |
| Common shares issued | — | | 2 | |
| Common shares repurchased | | Common shares repurchased | — | | (50) | |
| Preference share dividends | (87 | ) | (83 | ) | Preference share dividends | (84) | | (91) | |
| Common share dividends | (764 | ) | (768 | ) | Common share dividends | (1,798) | | (1,742) | |
| Net cash provided by/(used in) financing activities | (1,009 | ) | 1,313 |
| |
| Redemption of preference shares | | Redemption of preference shares | — | | (750) | |
| Affiliate loans, net | | Affiliate loans, net | 51 | | — | |
| Other | | Other | (33) | | (92) | |
| Net cash used in financing activities | | Net cash used in financing activities | (2,289) | | (1,483) | |
| Effect of translation of foreign denominated cash and cash equivalents and restricted cash | 19 |
| (9 | ) | Effect of translation of foreign denominated cash and cash equivalents and restricted cash | 4 | | (4) | |
| Net increase/(decrease) in cash and cash equivalents and restricted cash | 136 |
| (368 | ) | |
| Net change in cash and cash equivalents and restricted cash | | Net change in cash and cash equivalents and restricted cash | 144 | | 134 | |
| Cash and cash equivalents and restricted cash at beginning of period | 587 |
| 1,562 |
| Cash and cash equivalents and restricted cash at beginning of period | 907 | | 320 | |
| Cash and cash equivalents and restricted cash at end of period | 723 |
| 1,194 |
| Cash and cash equivalents and restricted cash at end of period | 1,051 | | 454 | |
| Supplementary cash flow information | | | |
| Property, plant and equipment non-cash accruals | 754 |
| 1,019 |
| |
SeeThe accompanying notes to theare an integral part of these interim consolidated financial statements.
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
| | | | March 31,
2018 |
| December 31,
2017 |
| | March 31,
2023 | December 31,
2022 |
| (unaudited; millions of Canadian dollars; number of shares in millions) | |
| |
| (unaudited; millions of Canadian dollars; number of shares in millions) | | |
| Assets | |
| |
| Assets | | |
| Current assets | |
| |
| Current assets | | |
| Cash and cash equivalents | 610 |
| 480 |
| Cash and cash equivalents | 976 | | 861 | |
| Restricted cash | 113 |
| 107 |
| Restricted cash | 75 | | 46 | |
| Accounts receivable and other | 6,271 |
| 7,053 |
| |
| Trade receivables and unbilled revenues | | Trade receivables and unbilled revenues | 4,755 | | 5,616 | |
| Other current assets | | Other current assets | 2,701 | | 3,255 | |
| Accounts receivable from affiliates | 48 |
| 47 |
| Accounts receivable from affiliates | 100 | | 114 | |
| Inventory | 872 |
| 1,528 |
| Inventory | 1,311 | | 2,255 | |
| | 7,914 |
| 9,215 |
| | 9,918 | | 12,147 | |
| Property, plant and equipment, net | 92,521 |
| 90,711 |
| Property, plant and equipment, net | 104,251 | | 104,460 | |
| Long-term investments | 17,360 |
| 16,644 |
| Long-term investments | 16,320 | | 15,936 | |
| Restricted long-term investments | 280 |
| 267 |
| Restricted long-term investments | 646 | | 593 | |
| Deferred amounts and other assets | 5,614 |
| 6,442 |
| Deferred amounts and other assets | 9,148 | | 9,542 | |
| Intangible assets, net | 3,455 |
| 3,267 |
| Intangible assets, net | 3,913 | | 4,018 | |
| Goodwill | 35,168 |
| 34,457 |
| Goodwill | 32,411 | | 32,440 | |
| Deferred income taxes | 1,182 |
| 1,090 |
| Deferred income taxes | 463 | | 472 | |
| Total assets | 163,494 |
| 162,093 |
| Total assets | 177,070 | | 179,608 | |
| | | | | | |
| Liabilities and equity | |
| |
| Liabilities and equity | | |
| Current liabilities | |
| |
| Current liabilities | | |
| Short-term borrowings | 1,004 |
| 1,444 |
| Short-term borrowings | 1,437 | | 1,996 | |
| Accounts payable and other | 6,823 |
| 9,478 |
| |
| Trade payables and accrued liabilities | | Trade payables and accrued liabilities | 4,098 | | 6,172 | |
| Other current liabilities | | Other current liabilities | 3,051 | | 5,220 | |
| Accounts payable to affiliates | 168 |
| 157 |
| Accounts payable to affiliates | 47 | | 105 | |
| Interest payable | 592 |
| 634 |
| Interest payable | 709 | | 763 | |
| Environmental liabilities | 33 |
| 40 |
| |
| Current portion of long-term debt | 4,152 |
| 2,871 |
| Current portion of long-term debt | 7,436 | | 6,045 | |
| | 12,772 |
| 14,624 |
| | 16,778 | | 20,301 | |
| Long-term debt | 61,191 |
| 60,865 |
| Long-term debt | 71,740 | | 72,939 | |
| Other long-term liabilities | 8,390 |
| 7,510 |
| Other long-term liabilities | 9,235 | | 9,189 | |
| Deferred income taxes | 9,812 |
| 9,295 |
| Deferred income taxes | 14,292 | | 13,781 | |
| | 92,165 |
| 92,294 |
| | 112,045 | | 116,210 | |
Contingencies (Note 13) |
|
|
|
| |
| Redeemable noncontrolling interests | 3,815 |
| 4,067 |
| |
Contingencies (Note 10) | | Contingencies (Note 10) | | |
| Equity | |
| |
| Equity | | |
| Share capital | |
| |
| Share capital | | |
| Preference shares | 7,747 |
| 7,747 |
| Preference shares | 6,818 | | 6,818 | |
Common shares (1,705 and 1,695 outstanding at March 31, 2018 and December 31, 2017, respectively) | 51,127 |
| 50,737 |
| |
Common shares (2,025 outstanding at March 31, 2023 and December 31, 2022) | | Common shares (2,025 outstanding at March 31, 2023 and December 31, 2022) | 64,774 | | 64,760 | |
| Additional paid-in capital | 4,313 |
| 3,194 |
| Additional paid-in capital | 274 | | 275 | |
| Deficit | (1,982 | ) | (2,468 | ) | Deficit | (13,753) | | (15,486) | |
Accumulated other comprehensive income/(loss) (Note 8) | 329 |
| (973 | ) | |
| Reciprocal shareholding | (102 | ) | (102 | ) | |
Accumulated other comprehensive income (Note 6) | | Accumulated other comprehensive income (Note 6) | 3,426 | | 3,520 | |
| | Total Enbridge Inc. shareholders’ equity | 61,432 |
| 58,135 |
| Total Enbridge Inc. shareholders’ equity | 61,539 | | 59,887 | |
| Noncontrolling interests | 6,082 |
| 7,597 |
| Noncontrolling interests | 3,486 | | 3,511 | |
| | 67,514 |
| 65,732 |
| | 65,025 | | 63,398 | |
| Total liabilities and equity | 163,494 |
| 162,093 |
| Total liabilities and equity | 177,070 | | 179,608 | |
SeeThe accompanying notes to theare an integral part of these interim consolidated financial statements.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 (U.S.(US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by U.S.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, 2017 included in our Annual Report on Form 10-K.2022. 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 annualaudited consolidated financial statements for the year ended December 31, 2017, except for the adoption of new standards (Note 2) and the presentation of Cash and cash equivalents to include Bank indebtedness, as discussed below. 2022. 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 the supply of and demand for crude oil and natural gas, and may not be indicative of annual results.
Effective September 30, 2017, we combined Cash and cash equivalents and amounts previously presented as Bank indebtedness where the corresponding bank accounts are subject to cash pooling arrangements. As at March 31, 2018 and December 31, 2017, $0.9 billion and $0.6 billion of Bank indebtedness has been combined within Cash and cash equivalents in our Consolidated Statements of Financial Position, respectively. Net cash provided by financing activities in our Consolidated Statements of Cash Flows for the three months period ended March 31, 2017 have been reduced by $0.2 billion to reflect this change.
Certain comparative figures in our Consolidated Statement of Cash Flowsinterim consolidated financial statements have been reclassified to conform withto the current year's presentation. In addition, activities
2. REVENUES
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
March 31, 2023 |
| (millions of Canadian dollars) | | | | | | | |
| Transportation revenue | 2,942 | | 1,384 | | 276 | | — | | — | | — | | 4,602 | |
| Storage and other revenue | 64 | | 95 | | 99 | | — | | — | | — | | 258 | |
| | | | | | | |
| Gas distribution revenue | — | | — | | 2,287 | | — | | — | | — | | 2,287 | |
| Electricity revenue | — | | — | | — | | 66 | | — | | — | | 66 | |
| | | | | | | |
| Total revenue from contracts with customers | 3,006 | | 1,479 | | 2,662 | | 66 | | — | | — | | 7,213 | |
| Commodity sales | — | | — | | — | | — | | 4,783 | | — | | 4,783 | |
Other revenue1,2 | 30 | | 11 | | (40) | | 78 | | — | | — | | 79 | |
| Intersegment revenue | 129 | | 1 | | 3 | | — | | 18 | | (151) | | — | |
| Total revenue | 3,165 | | 1,491 | | 2,625 | | 144 | | 4,801 | | (151) | | 12,075 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated |
Three months ended
March 31, 2022 |
| (millions of Canadian dollars) | | | | | | | |
| Transportation revenue | 2,685 | | 1,194 | | 251 | | — | | — | | — | | 4,130 | |
| Storage and other revenue | 51 | | 84 | | 47 | | — | | — | | — | | 182 | |
| Gas gathering and processing revenue | — | | 15 | | — | | — | | — | | — | | 15 | |
| Gas distribution revenue | — | | — | | 2,098 | | — | | — | | — | | 2,098 | |
| Electricity revenue | — | | — | | — | | 62 | | — | | — | | 62 | |
| | | | | | | |
| Total revenue from contracts with customers | 2,736 | | 1,293 | | 2,396 | | 62 | | — | | — | | 6,487 | |
| Commodity sales | — | | — | | — | | — | | 8,325 | | — | | 8,325 | |
Other revenue1,2 | 178 | | 7 | | 4 | | 94 | | 2 | | — | | 285 | |
| Intersegment revenue | 141 | | — | | 11 | | — | | 10 | | (162) | | — | |
| Total revenue | 3,055 | | 1,300 | | 2,411 | | 156 | | 8,337 | | (162) | | 15,097 | |
1Includes realized and unrealized gains and losses from our hedging program which for the three months ended March 31, 2017 relating to distributions to noncontrolling interests in relation to the Merger Transaction have been reclassified, resulting in an increase to investing activities of $672023 were a net $55 million and a decrease to financing activities of $67 million.loss (2022 - $94 million gain).
2. CHANGES IN ACCOUNTING POLICIES
ADOPTION OF NEW STANDARDS
Reclassification of Certain Tax Effects2 Includes revenues from Accumulated Other Comprehensive Income
Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2018-02 to address a specific consequence of the Tax Cuts and Jobs Act (TCJA) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allow a reclassification from accumulated other comprehensive income to retained earningslease contracts for stranded tax effects resulting from the TCJA. The amendments will eliminate the stranded tax effects as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements.
Clarifying Guidance on the Application of Modification Accounting on Stock Compensation
Effective January 1, 2018, we adopted ASU 2017-09 and applied the standard on a prospective basis. The new standard was issued to clarify the scope of modification accounting. Under the new guidance, modification accounting is required for all changes to share based payment awards, unless all of the
following conditions are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The adoption of this accounting update is not expected to have a material impact on our consolidated financial statements.
Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans
Effective January 1, 2018, we adopted ASU 2017-07 which was issued primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. Upon adoption of this accounting update, our consolidated statement of earnings presents the current service cost within Operating and administrative expenses and the other components of net benefit cost within Other income/(expense). Previously, all components of net benefit cost were presented within Operating and administrative expenses. In addition, only the service cost component of net benefit cost will be capitalized on a prospective basis. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements.
Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets
Effective January 1, 2018, we adopted ASU 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our consolidated financial statements.
Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows
Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents.
Simplifying Cash Flow Classification
Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements.
Recognition and Measurement of Financial Assets and Liabilities
Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial instruments for disclosure purposes is measured using exit price. The adoption of this accounting update did not have a material impact on our consolidated financial statements.
Revenue from Contracts with Customers
Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards.
In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied obligations.
The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item along with explanations of those effects. For the three months ended March 31, 2018, the effect2023 and 2022 of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. $144 million and $164 million, respectively.
|
| | | | | | |
| | Balance at December 31, 2017 | Adjustments Due to ASC 606 | Balance at January 1, 2018 |
| (millions of Canadian dollars) | | | |
| Assets | | | |
Deferred amounts and other assets1,2 | 6,442 |
| (170 | ) | 6,272 |
|
Property, plant and equipment, net2 | 90,711 |
| 112 |
| 90,823 |
|
| Liabilities and equity | | | |
Accounts payable and other1,2 | 9,478 |
| 62 |
| 9,540 |
|
Other long-term liabilities2 | 7,510 |
| 66 |
| 7,576 |
|
Deferred income taxes1,2 | 9,295 |
| (62 | ) | 9,233 |
|
Redeemable noncontrolling interests1,2 | 4,067 |
| (38 | ) | 4,029 |
|
Deficit1,2 | (2,468 | ) | (86 | ) | (2,554 | ) |
| |
1 | Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract. |
| |
2 | Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment. |
FUTURE ACCOUNTING POLICY CHANGES
Improvements to Accounting for Hedging Activities
ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective
basis. We are currently assessing the impact of the new standard on our consolidated financial statements.
Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.
Recognition of Leases
ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are currently gathering a complete inventory of our lease contracts in order to assess the impact of the new standard on our consolidated financial statements. We will adopt the new standard on January 1, 2019 and we are currently evaluating options with respect to the transition practical expedients offered in connection with this update.
Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements.
3. REVENUE
REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
|
| | | | | | | | | | | | | | |
| | Liquids Pipelines |
| Gas Transmission and Midstream |
| Gas Distribution |
| Green Power and Transmission |
| Energy Services |
| Eliminations and Other |
| Consolidated |
|
Three months ended
March 31, 2018 |
| (millions of Canadian dollars) | |
| | |
| |
| |
| |
| |
|
| Transportation revenue | 2,058 |
| 952 |
| 239 |
| — |
| — |
| — |
| 3,249 |
|
| Storage and other revenue | 40 |
| 60 |
| 66 |
| — |
| — |
| — |
| 166 |
|
| Gas gathering and processing revenue | — |
| 205 |
| — |
| — |
| — |
| — |
| 205 |
|
| Gas distribution revenue | — |
| — |
| 1,926 |
| — |
| — |
| — |
| 1,926 |
|
| Electricity and transmission revenue | — |
| — |
| — |
| 154 |
| — |
| — |
| 154 |
|
| Commodity sales | — |
| 693 |
| — |
| — |
| — |
| — |
| 693 |
|
| Total revenue from contracts with customers | 2,098 |
| 1,910 |
| 2,231 |
| 154 |
| — |
| — |
| 6,393 |
|
| Commodity sales | — |
| — |
| — |
| — |
| 6,575 |
| — |
| 6,575 |
|
Other revenue1 | (269 | ) | 25 |
| 2 |
| 3 |
| — |
| (3 | ) | (242 | ) |
| Intersegment revenue | 80 |
| 2 |
| 4 |
| — |
| 57 |
| (143 | ) | — |
|
| Total revenue | 1,909 |
| 1,937 |
| 2,237 |
| 157 |
| 6,632 |
| (146 | ) | 12,726 |
|
| |
1 | Includes mark-to-market gains/(losses) from our hedging program. |
We disaggregate revenue into categories which represent our principal performance obligations within each business segment because thesesegment. 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 March 31, 2023 | 3,186 | | 232 | | 2,328 | |
| Balance as at December 31, 2022 | 3,183 | | 230 | | 2,241 | |
|
| | | | | | |
| | Receivables | Contract Assets | Contract Liabilities |
| (millions of Canadian dollars) | | | |
Balance at adoption date
| 2,475 |
| 290 |
| 992 |
|
Balance at reporting date
| 2,533 |
| 290 |
| 1,008 |
|
Contract receivables represent the amount of receivables derived from contracts with customers.
Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or have partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to 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 revenue. Revenue recognized during the current periodthree months ended March 31, 2023 included in contract liabilities at the beginning of the period is $95was $36 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three months ended March 31, 2018,2023 were $96 million during the period.$124 million.
Performance Obligations
|
| |
Business Unit | Nature of Performance Obligation |
Transportation services - pipelines
| •
Transportation and storage of crude oil, natural gas and natural gas liquids (NGL) |
Gas Transmission and Midstream | •
Sale of crude oil, natural gas and NGLs |
•
Transportation, storage, gathering, compression and treating of natural gas |
Gas Distribution | •
Supply and delivery of natural gas |
•
Transportation of natural gas |
|
Green Power and transmission
| •
Generation and transmission of electricity |
•
Delivery of electricity from renewable energy generation facilities |
There was no material revenue recognized in the current periodthree months ended March 31, 2023 from performance obligations satisfied in previous periods.
Payment Terms
Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution customers are received on a continuous basis based on established billing cycles.
Certain contracts in the United States offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs is recorded as a contract liability. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives.
Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is $63.8$60.0 billion, of which $5.7$6.0 billion and $5.9$6.7 billion isare expected to be recognized during the remaining nine months ending December 31, 20182023 and the year ending December 31, 2019,2024, respectively.
The revenues excluded from the amounts above, based on optional exemptions available under ASCAccounting 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. Those revenuescustomers and are not included inexcluded from the amounts for revenue 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.
SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE
Long-Term Transportation AgreementsVariable Consideration
For long-term transportation agreements, significant judgments pertainDuring the three months ended March 31, 2023, 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, over whichif any. Due to the uncertainty of adjustment to tolling pursuant to a Canada Energy Regulator (CER) decision, interim toll revenue recognized during the three months ended March 31, 2023 is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed.
considered variable consideration.
Estimates of Variable Consideration
Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes sold or transported and actual tolls and prices are determined.
Recognition and Measurement of RevenueRevenues
| | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | | Consolidated |
| Three months ended March 31, 2023 |
| (millions of Canadian dollars) | | | | | | |
| Revenue from products transferred at a point in time | — | | — | | 30 | | — | | | 30 | |
Revenue from products and services transferred over time1 | 3,006 | | 1,479 | | 2,632 | | 66 | | | 7,183 | |
| Total revenue from contracts with customers | 3,006 | | 1,479 | | 2,662 | | 66 | | | 7,213 | |
|
| | | | | | | | | | | | |
| | Liquids Pipelines |
| Gas Transmission and Midstream |
| Gas Distribution |
| Green Power and Transmission |
| Energy Services |
| Consolidated |
|
Three months ended
March 31, 2018 |
| (millions of Canadian dollars) | |
| | |
| |
| |
| |
Revenue from products transferred at a point in time1 | — |
| 693 |
| 25 |
| — |
| — |
| 718 |
|
Revenue from products and services transferred over time2 | 2,098 |
| 1,217 |
| 2,206 |
| 154 |
| — |
| 5,675 |
|
| Total revenue from contracts with customers | 2,098 |
| 1,910 |
| 2,231 |
| 154 |
| — |
| 6,393 |
|
| | | | | | | | | | | | | | | | | | |
| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | | Consolidated |
| Three months ended March 31, 2022 |
| (millions of Canadian dollars) | | | | | | |
| Revenue from products transferred at a point in time | — | | — | | 16 | | — | | | 16 | |
Revenue from products and services transferred over time1 | 2,736 | | 1,293 | | 2,380 | | 62 | | | 6,471 | |
| Total revenue from contracts with customers | 2,736 | | 1,293 | | 2,396 | | 62 | | | 6,487 | |
| |
1
| Revenue from sales of crude oil, natural gas and NGLs. |
| |
2
| 1 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales. |
Performance Obligations Satisfied at a Point in Time
Revenue from commodity sales where the commodity is not immediately consumed prior to use is recognized at the point in time when the contractually specified volume of the commodity has been delivered, as control over the commodity transfers to the customer upon delivery.
Performance Obligations Satisfied Over Time
For arrangements involving the transportation and sale of petroleum products and natural gas where thepipeline transportation, services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period.
Determination of Transaction Prices
Prices for gas processing and transportation services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation.
Prices for commodities sold are determined by reference to market price indices plus or minus a negotiated differential and in certain cases a marketing fee.
Prices forstorage, natural gas soldgathering, compression and distribution services provided by regulatedtreating, natural gas distribution, operations are prescribed by regulation.natural gas storage services and electricity sales.
Effective December 31, 2017, we changed our segment-level profit measure to Earnings before interest, income taxes and depreciation and amortization from the previous measure of Earnings before interest and income taxes. We also renamed the Gas Pipelines and Processing segment to Gas Transmission and Midstream. The presentation of the prior year table has been revised in order to align with the current presentation.
17
|
| | | | | | | | | | | | | | |
| | Liquids Pipelines |
| Gas Transmission and Midstream |
| Gas Distribution |
| Green Power and Transmission |
| Energy Services |
| Eliminations and Other |
| Consolidated |
|
Three months ended
March 31, 2018 |
| (millions of Canadian dollars) | |
| | |
| |
| |
| |
| |
|
| Revenues | 1,909 |
| 1,937 |
| 2,237 |
| 157 |
| 6,632 |
| (146 | ) | 12,726 |
|
| Commodity and gas distribution costs | (4 | ) | (620 | ) | (1,388 | ) | — |
| (6,455 | ) | 146 |
| (8,321 | ) |
| Operating and administrative | (747 | ) | (507 | ) | (248 | ) | (30 | ) | (12 | ) | (97 | ) | (1,641 | ) |
| Asset impairment | (144 | ) | (913 | ) | — |
| — |
| — |
| (5 | ) | (1,062 | ) |
| Income/(loss) from equity investments | 131 |
| 208 |
| 17 |
| (25 | ) | 4 |
| — |
| 335 |
|
| Other income/(expense) | 11 |
| 21 |
| 18 |
| 7 |
| — |
| (177 | ) | (120 | ) |
Earnings/(loss) before interest, income taxes, and depreciation and amortization
| 1,156 |
| 126 |
| 636 |
| 109 |
| 169 |
| (279 | ) | 1,917 |
|
| Depreciation and amortization | | | | | | | (824 | ) |
| Interest expense | |
| |
| |
| |
| |
| |
| (656 | ) |
| Income tax recovery | |
| |
| |
| |
| |
| |
| 73 |
|
| Earnings | | |
| |
| |
| |
| |
| 510 |
|
Capital expenditures1 | 615 |
| 825 |
| 183 |
| 14 |
| — |
| 6 |
| 1,643 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Three months ended
March 31, 2023 | 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 | 3,165 | | 1,491 | | 2,625 | | 144 | | 4,801 | | (151) | | 12,075 | |
| Commodity and gas distribution costs | — | | — | | (1,612) | | (4) | | (4,782) | | 168 | | (6,230) | |
| Operating and administrative | (1,123) | | (549) | | (309) | | (53) | | (18) | | 15 | | (2,037) | |
| | | | | | | |
| | | | | | | |
| Income/(loss) from equity investments | 248 | | 238 | | — | | 35 | | — | | (4) | | 517 | |
| | | | | | | |
| | | | | | | |
| Other income/(expense) | 73 | | 25 | | 12 | | 14 | | — | | (22) | | 102 | |
| Earnings before interest, income taxes and depreciation and amortization | 2,363 | | 1,205 | | 716 | | 136 | | 1 | | 6 | | 4,427 | |
| Depreciation and amortization | | | | | | | (1,146) | |
| Interest expense | | | | | | | (905) | |
| Income tax expense | | | | | | | (510) | |
| Earnings | | | | | | | 1,866 | |
Capital expenditures1 | 280 | | 527 | | 264 | | 45 | | — | | 25 | | 1,141 | |
|
| | | | | | | | | | | | | | |
| | Liquids Pipelines |
| Gas Transmission and Midstream |
| Gas Distribution |
| Green Power and Transmission |
| Energy Services |
| Eliminations and Other |
| Consolidated |
|
Three months ended
March 31, 2017 |
| (millions of Canadian dollars) | |
| | |
| |
| |
| |
| |
|
| Revenues | 2,155 |
| 1,235 |
| 1,584 |
| 137 |
| 6,133 |
| (98 | ) | 11,146 |
|
| Commodity and gas distribution costs | (3 | ) | (647 | ) | (1,046 | ) | 1 |
| (5,968 | ) | 98 |
| (7,565 | ) |
| Operating and administrative | (760 | ) | (254 | ) | (189 | ) | (40 | ) | (12 | ) | (296 | ) | (1,551 | ) |
| Income from equity investments | 86 |
| 110 |
| 36 |
| 2 |
| 2 |
| — |
| 236 |
|
| Other income/(expense) | 2 |
| 31 |
| 2 |
| 1 |
| 1 |
| (2 | ) | 35 |
|
Earnings/(loss) before interest, income taxes, and depreciation and amortization
| 1,480 |
| 475 |
| 387 |
| 101 |
| 156 |
| (298 | ) | 2,301 |
|
| Depreciation and amortization | | | | | | | (672 | ) |
| Interest expense | |
| |
| |
| |
| |
| |
| (486 | ) |
| Income tax expense | |
| |
| |
| |
| |
| |
| (198 | ) |
| Earnings | |
| |
| |
| |
| |
| |
| 945 |
|
Capital expenditures1 | 654 |
| 655 |
| 183 |
| 114 |
| — |
| 59 |
| 1,665 |
|
| |
1
| Includes allowance for equity funds used during construction. |
TOTAL ASSETS | | | | | | | | | | | | | | | | | | | | | | | |
Three months ended
March 31, 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 | 3,055 | | 1,300 | | 2,411 | | 156 | | 8,337 | | (162) | | 15,097 | |
| Commodity and gas distribution costs | (11) | | — | | (1,468) | | (4) | | (8,427) | | 163 | | (9,747) | |
| Operating and administrative | (947) | | (530) | | (299) | | (48) | | (14) | | (37) | | (1,875) | |
| | | | | | | |
| | | | | | | |
| Income from equity investments | 215 | | 221 | | — | | 55 | | — | | — | | 491 | |
| | | | | | | |
| Other income | 17 | | 23 | | 21 | | 3 | | 3 | | 391 | | 458 | |
| Earnings/(loss) before interest, income taxes and depreciation and amortization | 2,329 | | 1,014 | | 665 | | 162 | | (101) | | 355 | | 4,424 | |
| Depreciation and amortization | | | | | | | (1,055) | |
| Interest expense | | | | | | | (719) | |
| Income tax expense | | | | | | | (593) | |
| Earnings | | | | | | | 2,057 | |
Capital expenditures1 | 545 | | 229 | | 266 | | 6 | | — | | 12 | | 1,058 | |
1Includes allowance for equity funds used during construction.
|
| | | | |
| | March 31, 2018 |
| December 31, 2017 |
|
| (millions of Canadian dollars) | |
| |
|
| Liquids Pipelines | 64,842 |
| 63,881 |
|
| Gas Transmission and Midstream | 61,880 |
| 60,745 |
|
| Gas Distribution | 25,784 |
| 25,956 |
|
| Green Power and Transmission | 6,466 |
| 6,289 |
|
| Energy Services | 1,628 |
| 2,514 |
|
| Eliminations and Other | 2,894 |
| 2,708 |
|
| | 163,494 |
| 162,093 |
|
4. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE
| |
5. | EARNINGS PER COMMON SHARE
|
BASIC
Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of 13 million for the three months ended March 31, 2018 and 2017, resulting from our reciprocal investment in Noverco Inc.
DILUTED
The treasury stock method is used to determine the dilutive impact of stock options.options and RSUs. 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
March 31, |
| | | | | 2023 | 2022 |
| (number of shares in millions) | | | | | |
| Weighted average shares outstanding | | | | 2,025 | | 2,026 | |
| Effect of dilutive options and RSUs | | | | 3 | | 3 | |
| Diluted weighted average shares outstanding | | | | 2,028 | | 2,029 | |
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (number of common shares in millions) | |
| |
|
| Weighted average shares outstanding | 1,685 |
| 1,177 |
|
| Effect of dilutive options | 4 |
| 10 |
|
| Diluted weighted average shares outstanding | 1,689 |
| 1,187 |
|
For the three months ended March 31, 20182023 and 2017, 29,882,1422022, 16.7 million and 13,545,193,12.9 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $49.80$55.62 and $57.71,$56.09, respectively, were excluded from the diluted earnings per common share calculation.
On May 2, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2023 to shareholders of record on May 15, 2023.
| | | | | |
| Dividend per share |
Common Shares1 | $0.88750 | |
| Preference Shares, Series A | $0.34375 | |
| Preference Shares, Series B | $0.32513 | |
Preference Shares, Series D2 | $0.33825 | |
| Preference Shares, Series F | $0.29306 | |
| Preference Shares, Series H | $0.27350 | |
| Preference Shares, Series L | US$0.36612 | |
| Preference Shares, Series N | $0.31788 | |
| Preference Shares, Series P | $0.27369 | |
| Preference Shares, Series R | $0.25456 | |
| Preference Shares, Series 1 | US$0.37182 | |
| 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 193 | $0.38825 | |
| |
6. | ASSETS HELD FOR SALE
|
Midcoast Operating, L.P.
On May 9, 2018 our indirect subsidiary, Enbridge (U.S.) Inc. entered into a definitive agreement to sell Midcoast Operating, L.P. and its subsidiaries (Sales Agreement), which conducts our United States natural gas and NGL gathering, processing, transportation and marketing businesses, to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for a cash purchase price of US$1.1 billion, subject to customary closing adjustments. The transaction is expected to close in the third quarter of 2018, subject to receipt of customary regulatory approvals and satisfaction of other customary closing conditions.
These assets, excluding our equity method investment in the Texas Express NGL pipeline system, were classified as held for sale and were measured at the lower of their carrying value or fair value less costs to sell as at December 31, 2017. As a result of entering into the Sales Agreement, the fair value of the assets held for sale as at March 31, 2018 were revised based on the sale price. Accordingly, we recorded a loss of $913 million ($701 million after-tax attributable to us). This loss has been included within Asset impairment on the Consolidated Statements of Earnings for the three months ended March 31, 2018.
Line 10 Crude Oil Pipeline
At March 31, 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P., own the Canadian and United States portion of Line 10, respectively, and the related assets are included in our Liquids Pipeline segment.
We expect to close the sale of Line 10 within one year, subject to regulatory approval and certain closing conditions. As such, we classified Line 10 assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $144 million ($85 million after-tax attributable to us) included within Asset impairment on the Consolidated Statements of Earnings for the three months ended March 31, 2018.
The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position:
|
| | | | |
| | March 31, 2018 |
| December 31, 2017 |
|
| (millions of Canadian dollars) | |
| |
| Accounts receivable and other (current assets held for sale) | 305 |
| 424 |
|
| Deferred amounts and other assets (long-term assets held for sale) | 422 |
| 1,190 |
|
| Accounts payable and other (current liabilities held for sale) | (233 | ) | (315 | ) |
| Other long-term liabilities (long-term liabilities held for sale) | (37 | ) | (34 | ) |
| Net assets held for sale | 457 |
| 1,265 |
|
1The quarterly dividend per common share was increased 3.2% to $0.8875 from $0.86, effective March 1, 2023.
2The quarterly dividend per share paid on Preference Shares, Series D was increased to $0.33825 from $0.27875 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.
3The quarterly dividend per share paid on Preference Shares, Series 19 was increased to $0.38825 from $0.30625 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.
5. DEBT
CREDIT FACILITIES
The following table provides details of our committed credit facilities as at March 31, 2018:2023:
| | | | | | | | | | | | | | |
| Maturity1 | Total
Facilities | Draws2 | Available |
| (millions of Canadian dollars) | | | | |
| Enbridge Inc. | 2023-2027 | 9,623 | | 7,053 | | 2,570 | |
| Enbridge (U.S.) Inc. | 2024-2027 | 8,594 | | 1,702 | | 6,892 | |
| Enbridge Pipelines Inc. | 2024 | 2,000 | | 876 | | 1,124 | |
| Enbridge Gas Inc. | 2024 | 2,500 | | 1,440 | | 1,060 | |
| Total committed credit facilities | | 22,717 | | 11,071 | | 11,646 | |
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. |
| | | | | | | |
| | | March 31, 2018 |
| | Maturity | Total Facilities |
| Draws1 |
| Available |
|
| (millions of Canadian dollars) | | | | |
Enbridge Inc.2 | 2019-2022 | 6,644 |
| 2,616 |
| 4,028 |
|
| Enbridge (U.S.) Inc. | 2019 | 2,469 |
| 1,142 |
| 1,327 |
|
Enbridge Energy Partners, L.P.3 | 2019-2022 | 3,385 |
| 1,660 |
| 1,725 |
|
| Enbridge Gas Distribution Inc. (EGD) | 2019 | 1,017 |
| 884 |
| 133 |
|
| Enbridge Income Fund | 2020 | 1,500 |
| 566 |
| 934 |
|
| Enbridge Pipelines Inc. | 2019 | 3,000 |
| 1,730 |
| 1,270 |
|
Spectra Energy Partners, LP4 | 2022 | 3,223 |
| 2,135 |
| 1,088 |
|
| Union Gas Limited (Union Gas) | 2021 | 700 |
| 130 |
| 570 |
|
| Total committed credit facilities | | 21,938 |
| 10,863 |
| 11,075 |
|
| |
1 | Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
|
| |
2 | Includes $135 million, $161 million (US$125 million) and$150 million of commitments that expire in 2018, 2018 and 2020, respectively.
|
| |
3 | Includes $226 million (US$175 million) and $239 million (US$185 million) of commitments that expire in 2018 and 2020, respectively. |
| |
4 | Includes $434 million (US$336 million) of commitments that expire in 2021. |
During the first quarter of 2018,In March 2023, Enbridge terminated a US$650 millionGas Inc. (Enbridge Gas) increased its 364-day extendible credit facility which was setfrom $2.0 billion to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilizedUS$950 million credit facility, which was set to mature in 2019.$2.5 billion.
During the first quarter of 2018, Westcoast Energy Inc. terminated an unutilized $400 million credit facility with a syndicate of banks. The facility was set to mature in 2021.
In addition to the committed credit facilities noted above, we have $790 millionmaintain $1.3 billion of uncommitted demand letter of credit facilities, of which $511$720 million werewas unutilized as at March 31, 2018.2023. As at December 31, 2017,2022, we had $792 million$1.3 billion of uncommitted demand letter of credit facilities, of which $518$689 million werewas unutilized.
Our credit facilities carry a weighted average standby fee of 0.2%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 setscheduled to mature from 20192023 to 2022.2027.
As at March 31, 20182023 and December 31, 2017,2022, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $9,832 million$9.0 billion and $10,055 million,$10.5 billion, respectively, arewere 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 first quarter of 2018,three months ended March 31, 2023, we completed the following long-term debt issuances:
issuances totaling US$3.0 billion: | | | | | | | | | | | | | | |
| Company | Issue Date | | | Principal Amount |
| (millions of Canadian dollars, unless otherwise stated) | |
| Enbridge Inc. | | | |
| March 2023 | 5.70% | sustainability-linked senior notes due March 20331 | US$2,300 |
| March 2023 | 5.97% | senior notes due March 20262 | US$700 |
| | | | |
| | | | |
Company | Issue Date | | | Principal Amount |
(millions of dollars) | | |
Enbridge Inc. | | | |
| March 2018 | Fixed-to-floating rate notes due 20781
| US$850 |
Spectra Energy Partners, LP2
| | | |
| January 2018 | 3.50% senior notes due 2028 | US$400 |
| January 2018 | 4.15% senior notes due 2048 | US$400 |
| |
1 | Notes mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.25%. Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 364 basis points from years 10 to 30, and a margin of 439 basis points from years 30 to 60.
|
| |
2 | Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of Spectra Energy Partners, LP (SEP). |
LONG-TERM DEBT REPAYMENTS
During the first quarter of 2018, we completed the following long-term debt repayments:
|
| | | | |
| | | |
Company | Retirement/Repayment Date | | | Principal Amount |
| Cash Consideration |
(millions of Canadian dollars unless otherwise stated) | | | | |
Enbridge Southern Lights LP
| | | | |
| January 2018 | 4.01% medium-term notes due June 2040 | 9 |
| |
Spectra Energy Capital, LLC1
| | | | |
Repurchase via Tender Offer | | | | |
| March 2018 | 6.75% senior unsecured notes due 2032 | US$64 | US$80 |
| March 2018 | 7.50% senior unsecured notes due 2038 | US$43 | US$59 |
Redemption | | | |
| March 2018 | 5.65% senior unsecured notes due 2020 | US$163 | US$172 |
| March 2018 | 3.30% senior unsecured notes due 2023 | US$498 | US$508 |
| |
1 | The loss on debt extinguishment of $37 million (US$29 million), net of the fair value adjustment recorded upon completion of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction), was reported within Interest expense in the Consolidated Statements of Earnings.
| | | |
1The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on September 8, 2031, the interest rate will be set to equal 5.70% plus a margin of 50 basis points.
2We have the option to call the notes at par after one year from issuance. Refer to Note 7 - Risk Management and Financial Instruments.
LONG-TERM DEBT REPAYMENTS
During the three months ended March 31, 2023, we completed the following long-term debt repayments totaling US$513 million and $275 million:
| | | | | | | | | | | | | | |
| Company | Repayment Date | | | Principal Amount |
| (millions of Canadian dollars, unless otherwise stated) | |
| Enbridge Inc. | | | |
| January 2023 | 3.94% | medium-term notes | $275 |
| February 2023 | Floating rate notes1 | US$500 |
| | | | |
| |
| | | | |
| | | |
| | | | |
| |
| | | | |
| | | |
| | | | |
| |
| | | | |
| Tri Global Energy, LLC |
| January 2023 | 10.00 | % | senior notes | US$4 |
| January 2023 | 14.00 | % | senior notes | US$9 |
1The notes carried an interest rate set to equal the Secured Overnight Financing Rate plus a margin of 40 basis points.
On April 15, 2023 call date, we redeemed at par all of the outstanding US$600 million five-year callable, 6.38% fixed-to-floating rate subordinated notes that carried an original maturity date of April 2078.
SUBORDINATED TERM NOTES
As at March 31, 2023 and December 31, 2022, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $10.3 billion.
FAIR VALUE ADJUSTMENT
As at March 31, 2023 and December 31, 2022, the net fair value adjustments to total debt assumed in a historical acquisition were $588 million and $608 million, respectively.
During the three months ended March 31, 2023 and 2022, amortization of the fair value adjustment recorded as a reduction to Interest expense in the Consolidated Statements of Earnings was $11 million.
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 wereare to default on payment or violate certain covenants. As at March 31, 2018,2023, we were in compliance with all debt covenants.covenant provisions.
21
6. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
| |
8. | COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME |
Changes in Accumulated other comprehensive incomeincome/(loss) (AOCI) attributable to our common shareholders for the three months ended March 31, 20182023 and 20172022 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, 2023 | 121 | | (35) | | (1,137) | | 4,348 | | 5 | | 218 | | 3,520 | |
| Other comprehensive income/(loss) retained in AOCI | (90) | | 7 | | 15 | | (57) | | — | | — | | (125) | |
| Other comprehensive loss/(income) reclassified to earnings | | | | | | | |
Interest rate contracts1 | 8 | | — | | — | | — | | — | | — | | 8 | |
| | | | | | | |
| | | | | | | |
Other contracts2 | 1 | | — | | — | | — | | — | | — | | 1 | |
Amortization of pension and OPEB actuarial gain3 | — | | — | | — | | — | | — | | (5) | | (5) | |
| | | | | | | |
| (81) | | 7 | | 15 | | (57) | | — | | (5) | | (121) | |
| Tax impact | | | | | | | |
| Income tax on amounts retained in AOCI | 28 | | — | | — | | — | | — | | — | | 28 | |
| Income tax on amounts reclassified to earnings | (2) | | — | | — | | — | | — | | 1 | | (1) | |
| 26 | | — | | — | | — | | — | | 1 | | 27 | |
| | | | | | | |
| Balance as at March 31, 2023 | 66 | | (28) | | (1,122) | | 4,291 | | 5 | | 214 | | 3,426 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | 384 | | (1) | | 133 | | (691) | | — | | — | | (175) | |
| Other comprehensive loss/(income) reclassified to earnings | | | | | | | |
Interest rate contracts1 | 76 | | — | | — | | — | | — | | — | | 76 | |
Foreign exchange contracts4 | (4) | | — | | — | | — | | — | | — | | (4) | |
Other contracts2 | 2 | | — | | — | | — | | — | | — | | 2 | |
| | | | | | | |
Amortization of pension and OPEB actuarial gain3 | — | | — | | — | | — | | — | | (3) | | (3) | |
| | | | | | | |
| 458 | | (1) | | 133 | | (691) | | — | | (3) | | (104) | |
| Tax impact | | | | | | | |
| Income tax on amounts retained in AOCI | (92) | | — | | — | | — | | — | | — | | (92) | |
| Income tax on amounts reclassified to earnings | (17) | | — | | — | | — | | — | | 1 | | (16) | |
| (109) | | — | | — | | — | | — | | 1 | | (108) | |
| | | | | | | |
| Balance as at March 31, 2022 | (548) | | (1) | | (33) | | (635) | | (5) | | (86) | | (1,308) | |
1Reported within Interest expense in the Consolidated Statements of Earnings.
2Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
3These components are included in the computation of net periodic benefit credit and are reported within Other income in the Consolidated Statements of Earnings.
4Reported within Transportation and other services revenues and Other income in the Consolidated Statements of Earnings.
|
| | | | | | | | | | | | |
| | Cash Flow Hedges |
| Net Investment Hedges |
| Cumulative Translation Adjustment |
| Equity Investees |
| Pension and OPEB Adjustment |
| Total |
|
| (millions of Canadian dollars) | | | | | | |
| Balance at January 1, 2018 | (644 | ) | (139 | ) | 77 |
| 10 |
| (277 | ) | (973 | ) |
| Other comprehensive income/(loss) retained in AOCI | 70 |
| (213 | ) | 1,425 |
| 2 |
| — |
| 1,284 |
|
| Other comprehensive (income)/loss reclassified to earnings | | | | | |
|
|
Interest rate contracts1 | 28 |
| — |
| — |
| — |
| — |
| 28 |
|
Commodity contracts2 | (1 | ) | — |
| — |
| — |
| — |
| (1 | ) |
Foreign exchange contracts3 | 4 |
| — |
| — |
| — |
| — |
| 4 |
|
Other contracts4 | 9 |
| — |
| — |
| — |
| — |
| 9 |
|
Amortization of pension and OPEB actuarial loss and prior service costs5 | — |
| — |
| — |
| — |
| (38 | ) | (38 | ) |
| | 110 |
| (213 | ) | 1,425 |
| 2 |
| (38 | ) | 1,286 |
|
| Tax impact | |
| |
| |
| |
| |
| |
|
| Income tax on amounts retained in AOCI | (9 | ) | 29 |
| — |
| 8 |
| — |
| 28 |
|
| Income tax on amounts reclassified to earnings | (11 | ) | — |
| — |
| — |
| (1 | ) | (12 | ) |
| | (20 | ) | 29 |
| — |
| 8 |
| (1 | ) | 16 |
|
| Balance at March 31, 2018 | (554 | ) | (323 | ) | 1,502 |
| 20 |
| (316 | ) | 329 |
|
|
| | | | | | | | | | | | |
| | Cash Flow Hedges |
| Net Investment Hedges |
| Cumulative Translation Adjustment |
| Equity Investees |
| Pension and OPEB Adjustment |
| Total |
|
| (millions of Canadian dollars) | | | | | | |
| Balance at January 1, 2017 | (746 | ) | (629 | ) | 2,700 |
| 37 |
| (304 | ) | 1,058 |
|
| Other comprehensive income/(loss) retained in AOCI | (1 | ) | 50 |
| 293 |
| 5 |
| — |
| 347 |
|
| Other comprehensive (income)/loss reclassified to earnings | | | | | |
|
|
Interest rate contracts1 | 31 |
| — |
| — |
| — |
| — |
| 31 |
|
Commodity contracts2 | (2 | ) | — |
| — |
| — |
| — |
| (2 | ) |
Other contracts4 | 9 |
| — |
| — |
| — |
| — |
| 9 |
|
Amortization of pension and OPEB actuarial loss and prior service costs5
| — |
| — |
| — |
| — |
| 6 |
| 6 |
|
| | 37 |
| 50 |
| 293 |
| 5 |
| 6 |
| 391 |
|
| Tax impact | | | | | | |
| Income tax on amounts retained in AOCI | (1 | ) | (1 | ) | — |
| 1 |
| — |
| (1 | ) |
| Income tax on amounts reclassified to earnings | (8 | ) | — |
| — |
| — |
| (2 | ) | (10 | ) |
| | (9 | ) | (1 | ) | — |
| 1 |
| (2 | ) | (11 | ) |
| Balance at March 31, 2017 | (718 | ) | (580 | ) | 2,993 |
| 43 |
| (300 | ) | 1,438 |
|
| |
1 | Reported within Interest expense in the Consolidated Statements of Earnings. |
| |
2 | Reported within Commodity costs in the Consolidated Statements of Earnings. |
| |
3 | Reported within Other income/(expense) in the Consolidated Statements of Earnings. |
| |
4 | Reported within Operating and administrative expense in the Consolidated Statements of Earnings. |
| |
5 | These components are included in the computation of net periodic benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings. |
9. NONCONTROLLING INTERESTS
As at December 31, 2017, we collectively owned a 75% ownership interest in SEP, together with 100% of SEP's incentive distribution rights (IDRs). On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our IDRs and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs have been eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 million of SEP common units, representing 83% of SEP's outstanding common units. As a result of this restructuring, we recorded a decrease in Noncontrolling interests of $1.5 billion and increases in Additional paid-in capital and Deferred income taxes of $1.1 billion and $333 million, respectively, for the three months ended March 31, 2018.
10. 7. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
MARKET RISK
Our earnings, cash flows and other comprehensive incomeincome/(loss) (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risk)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 areis used to hedge anticipated foreign
currency denominated revenues and expenses and to manage variability in cash flows. We hedge
certain net investments in United States dollar denominated(US) dollar-denominated investments and subsidiaries using foreign
currency derivatives and United States dollar denominatedUS dollar-denominated debt.
The foreign exchange risks inherent within the Competitive Toll Settlement framework are not expected to be present in the negotiated settlement. Accordingly, our foreign exchange hedging program related to the Canadian Mainline will no longer be required, and the related derivatives were terminated in the first quarter of 2023 for a realized loss of $638 million.
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. Pay fixed-receive floating interest rate swaps are
used to hedge against the effect of future interest rate movements. We have implemented a program to
significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of
floating to fixed interest rate swaps with an average swap rate of 2.6%.
As a result of the Merger Transaction, 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 to hedge against future changes to the fair value of fixed rate debt. We have assumed a program
within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via
execution of fixed to floating interest rate swaps with an average swap rate of 2.1%.
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 assumed a program within some of our subsidiaries
to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via
execution of floating to fixed interest rate swaps with an average swap rate of 3.4%.
We also 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 the execution of floating-to-fixed interest rate swaps. These hedges have an average fixed rate of 4.1%.
On March 8, 2023, we issued US$700 million three-year fixed rate notes which includes the right for us to call at par after the first year. A corresponding fix-to-floating cancellable swap was also executed which gives the swap counterparty a similar right to cancel the swap after the first year. This swap has a fixed rate of 6.0%. This instrument is our only pay floating-receive fixed interest rate swap outstanding as at March 31, 2023.
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 the execution of floating-to-fixed interest rate swaps with an average swap rate of 2.5%.
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 NGL.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.
Emission Allowance Price Risk
Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission
allowances that our gas distribution business is required to purchase for itself and most of its customers
to meet greenhouse gas compliance obligations under the Ontario Cap and Trade framework. Similar to the gas supply procurement framework, the Ontario Energy Board's (OEB) framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure
to our own common share price through the issuance of various forms of stock-based compensation,
which affect earnings through the revaluation of 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.RSUs. We use a combination of qualifying and non-qualifying derivative instruments to manage equity
price risk.
TOTAL DERIVATIVE INSTRUMENTS
The following table summarizes the Consolidated Statements of Financial Position location and carrying
value of our 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
reduces 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 thesethe specific circumstances.circumstances described above. All amounts are presented gross in the Consolidated
Statements of Financial Position.
| | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2023 | Derivative
Instruments
Used as
Cash Flow
Hedges | | Derivative
Instruments
Used as
Fair Value
Hedges | Non-
Qualifying
Derivative
Instruments | Total Gross
Derivative
Instruments
as Presented | | Amounts
Available
for Offset | Total Net
Derivative
Instruments |
| (millions of Canadian dollars) | | | | | | | | |
| Other current assets | | | | | | | | |
| Foreign exchange contracts | — | | | 68 | | 54 | | 122 | | | (13) | | 109 | |
| Interest rate contracts | 194 | | | — | | 21 | | 215 | | | (11) | | 204 | |
| Commodity contracts | — | | | — | | 193 | | 193 | | | (118) | | 75 | |
| Other contracts | — | | | — | | 2 | | 2 | | | — | | 2 | |
| 194 | | | 68 | | 270 | | 532 | | | (142) | | 390 | |
| Deferred amounts and other assets | | | | | | | | |
| Foreign exchange contracts | — | | | 83 | | 131 | | 214 | | | (108) | | 106 | |
| Interest rate contracts | 154 | | | — | | 44 | | 198 | | | (43) | | 155 | |
| Commodity contracts | — | | | — | | 67 | | 67 | | | (30) | | 37 | |
| | | | | | | | |
| 154 | | | 83 | | 242 | | 479 | | | (181) | | 298 | |
| Other current liabilities | | | | | | | | |
| Foreign exchange contracts | — | | | (42) | | (89) | | (131) | | | 13 | | (118) | |
| Interest rate contracts | (19) | | | — | | (1) | | (20) | | | 11 | | (9) | |
| Commodity contracts | (30) | | | — | | (218) | | (248) | | | 118 | | (130) | |
| | | | | | | | |
| (49) | | | (42) | | (308) | | (399) | | | 142 | | (257) | |
| Other long-term liabilities | | | | | | | | |
| Foreign exchange contracts | — | | | — | | (980) | | (980) | | | 108 | | (872) | |
| Interest rate contracts | (4) | | | — | | (45) | | (49) | | | 43 | | (6) | |
| Commodity contracts | (21) | | | — | | (123) | | (144) | | | 30 | | (114) | |
| | | | | | | | |
| (25) | | | — | | (1,148) | | (1,173) | | | 181 | | (992) | |
| Total net derivative asset/(liability) | | | | | | | | |
| Foreign exchange contracts | — | | | 109 | | (884) | | (775) | | | — | | (775) | |
| Interest rate contracts | 325 | | | — | | 19 | | 344 | | | — | | 344 | |
| Commodity contracts | (51) | | | — | | (81) | | (132) | | | — | | (132) | |
| Other contracts | — | | | — | | 2 | | 2 | | | — | | 2 | |
| 274 | | | 109 | | (944) | | (561) | | | — | | (561) | |
|
| | | | | | | | | | | | | | |
| March 31, 2018 | Derivative Instruments Used as Cash Flow Hedges |
| Derivative Instruments Used as Net Investment 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 | — |
| 3 |
| — |
| 131 |
| 134 |
| (70 | ) | 64 |
|
| Interest rate contracts | 27 |
| — |
| — |
| — |
| 27 |
| (5 | ) | 22 |
|
| Commodity contracts | — |
| — |
| — |
| 100 |
| 100 |
| (34 | ) | 66 |
|
| | 27 |
| 3 |
| — |
| 231 |
| 261 |
| (109 | ) | 152 |
|
| Deferred amounts and other assets | | | | | | | |
| Foreign exchange contracts | 18 |
| — |
| — |
| 92 |
| 110 |
| (58 | ) | 52 |
|
| Interest rate contracts | 15 |
| — |
| — |
| — |
| 15 |
| — |
| 15 |
|
| Commodity contracts | 19 |
| — |
| — |
| 3 |
| 22 |
| (19 | ) | 3 |
|
| Other contracts | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | 52 |
| — |
| — |
| 95 |
| 147 |
| (77 | ) | 70 |
|
| Accounts payable and other | | | | | | | |
| Foreign exchange contracts | (5 | ) | (23 | ) | — |
| (327 | ) | (355 | ) | 70 |
| (285 | ) |
| Interest rate contracts | (112 | ) | — |
| (9 | ) | (185 | ) | (306 | ) | 5 |
| (301 | ) |
| Commodity contracts | (2 | ) | — |
| — |
| (244 | ) | (246 | ) | 34 |
| (212 | ) |
| Other contracts | (2 | ) | — |
| — |
| (8 | ) | (10 | ) | — |
| (10 | ) |
| | (121 | ) | (23 | ) | (9 | ) | (764 | ) | (917 | ) | 109 |
| (808 | ) |
| Other long-term liabilities | | | | | | | |
| Foreign exchange contracts | — |
| (10 | ) | — |
| (1,650 | ) | (1,660 | ) | 58 |
| (1,602 | ) |
| Interest rate contracts | (20 | ) | — |
| (2 | ) | — |
| (22 | ) | — |
| (22 | ) |
| Commodity contracts | — |
| — |
| — |
| (160 | ) | (160 | ) | 19 |
| (141 | ) |
| Other contracts | (5 | ) | — |
| — |
| (3 | ) | (8 | ) | — |
| (8 | ) |
| | (25 | ) | (10 | ) | (2 | ) | (1,813 | ) | (1,850 | ) | 77 |
| (1,773 | ) |
| Total net derivative asset/(liability) | | | | | | | |
| Foreign exchange contracts | 13 |
| (30 | ) | — |
| (1,754 | ) | (1,771 | ) | — |
| (1,771 | ) |
| Interest rate contracts | (90 | ) | — |
| (11 | ) | (185 | ) | (286 | ) | — |
| (286 | ) |
| Commodity contracts | 17 |
| — |
| — |
| (301 | ) | (284 | ) | — |
| (284 | ) |
| Other contracts | (7 | ) | — |
| — |
| (11 | ) | (18 | ) | — |
| (18 | ) |
| | (67 | ) | (30 | ) | (11 | ) | (2,251 | ) | (2,359 | ) | — |
| (2,359 | ) |
| | | December 31, 2017 | Derivative Instruments Used as Cash Flow Hedges |
| Derivative Instruments Used as Net Investment 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 |
| |
| December 31, 2022 | | December 31, 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) | | (millions of Canadian dollars) | | | |
| Accounts receivable and other | | |
| Other current assets | | Other current assets | | | |
| Foreign exchange contracts | 1 |
| 4 |
| — |
| 138 |
| 143 |
| (83 | ) | 60 |
| Foreign exchange contracts | — | | | — | | 46 | | 46 | | (41) | | 5 | |
| Interest rate contracts | 6 |
| — |
| 2 |
| — |
| 8 |
| (3 | ) | 5 |
| Interest rate contracts | 649 | | | — | | 11 | | 660 | | — | | 660 | |
| Commodity contracts | 2 |
| — |
| — |
| 143 |
| 145 |
| (64 | ) | 81 |
| Commodity contracts | — | | | — | | 302 | | 302 | | (182) | | 120 | |
| Other contracts | | Other contracts | — | | | — | | 7 | | 7 | | — | | 7 | |
| | 9 |
| 4 |
| 2 |
| 281 |
| 296 |
| (150 | ) | 146 |
| | 649 | | | — | | 366 | | 1,015 | | (223) | | 792 | |
| Deferred amounts and other assets | | 2 |
| | Deferred amounts and other assets | | | |
| Foreign exchange contracts | 1 |
| 1 |
| — |
| 143 |
| 145 |
| (125 | ) | 20 |
| Foreign exchange contracts | — | | | 156 | | 153 | | 309 | | (138) | | 171 | |
| Interest rate contracts | 7 |
| — |
| 6 |
| — |
| 13 |
| (2 | ) | 11 |
| Interest rate contracts | 254 | | | — | | — | | 254 | | — | | 254 | |
| Commodity contracts | 17 |
| — |
| — |
| 6 |
| 23 |
| (19 | ) | 4 |
| Commodity contracts | — | | | — | | 61 | | 61 | | (25) | | 36 | |
| Other contracts | | Other contracts | 1 | | | — | | 2 | | 3 | | — | | 3 | |
| | 25 |
| 1 |
| 6 |
| 149 |
| 181 |
| (146 | ) | 35 |
| | 255 | | | 156 | | 216 | | 627 | | (163) | | 464 | |
| Accounts payable and other | | |
| Other current liabilities | | Other current liabilities | | | |
| Foreign exchange contracts | (5 | ) | (42 | ) | — |
| (312 | ) | (359 | ) | 83 |
| (276 | ) | Foreign exchange contracts | — | | | (42) | | (524) | | (566) | | 41 | | (525) | |
| Interest rate contracts | (140 | ) | — |
| (6 | ) | (183 | ) | (329 | ) | 3 |
| (326 | ) | |
| | Commodity contracts | — |
| — |
| — |
| (439 | ) | (439 | ) | 64 |
| (375 | ) | Commodity contracts | (48) | | | — | | (284) | | (332) | | 182 | | (150) | |
| Other contracts | (1 | ) | — |
| — |
| (2 | ) | (3 | ) | — |
| (3 | ) | |
| | | (146 | ) | (42 | ) | (6 | ) | (936 | ) | (1,130 | ) | 150 |
| (980 | ) | | (48) | | | (42) | | (808) | | (898) | | 223 | | (675) | |
| Other long-term liabilities | | Other long-term liabilities | | | |
| Foreign exchange contracts | (4 | ) | (9 | ) | — |
| (1,299 | ) | (1,312 | ) | 125 |
| (1,187 | ) | Foreign exchange contracts | — | | | — | | (1,116) | | (1,116) | | 138 | | (978) | |
| Interest rate contracts | (38 | ) | — |
| (2 | ) | — |
| (40 | ) | 2 |
| (38 | ) | Interest rate contracts | (3) | | | — | | (1) | | (4) | | — | | (4) | |
| Commodity contracts | — |
| — |
| — |
| (186 | ) | (186 | ) | 19 |
| (167 | ) | Commodity contracts | (37) | | | — | | (133) | | (170) | | 25 | | (145) | |
| Other contracts | (1 | ) | — |
| — |
| — |
| (1 | ) | — |
| (1 | ) | |
| | | (43 | ) | (9 | ) | (2 | ) | (1,485 | ) | (1,539 | ) | 146 |
| (1,393 | ) | | (40) | | | — | | (1,250) | | (1,290) | | 163 | | (1,127) | |
| Total net derivative asset/(liability) | | -2 |
| | Total net derivative asset/(liability) | | | |
| Foreign exchange contracts | (7 | ) | (46 | ) | — |
| (1,330 | ) | (1,383 | ) | — |
| (1,383 | ) | Foreign exchange contracts | — | | | 114 | | (1,441) | | (1,327) | | — | | (1,327) | |
| Interest rate contracts | (165 | ) | — |
| — |
| (183 | ) | (348 | ) | — |
| (348 | ) | Interest rate contracts | 900 | | | — | | 10 | | 910 | | — | | 910 | |
| Commodity contracts | 19 |
| — |
| — |
| (476 | ) | (457 | ) | — |
| (457 | ) | Commodity contracts | (85) | | | — | | (54) | | (139) | | — | | (139) | |
| Other contracts | (2 | ) | — |
| — |
| (2 | ) | (4 | ) | — |
| (4 | ) | Other contracts | 1 | | | — | | 9 | | 10 | | — | | 10 | |
| | (155 | ) | (46 | ) | — |
| (1,991 | ) | (2,192 | ) | — |
| (2,192 | ) | | 816 | | | 114 | | (1,476) | | (546) | | — | | (546) | |
The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.instruments:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2023 | 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total | |
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) | 832 | | 1,000 | | 500 | | — | | — | | — | | 2,332 | | |
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) | 4,566 | | 4,708 | | 4,763 | | 4,157 | | 2,969 | | 1,728 | | 22,891 | | |
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) | 21 | | 30 | | 30 | | 28 | | 32 | | — | | 141 | | |
| | | | | | | | |
Foreign exchange contracts - Euro forwards - sell (millions of Euro) | 69 | | 91 | | 86 | | 85 | | 81 | | 262 | | 674 | | |
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) | 7,821 | | 1,929 | | 80 | | 26 | | 25 | | 39 | | 9,920 | | |
Interest rate contracts - short-term debt receive fixed rate (millions of Canadian dollars) | 711 | | 947 | | 947 | | 179 | | — | | — | | 2,784 | | |
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars) | 4,153 | | 1,494 | | 588 | | — | | — | | — | | 6,235 | | |
Equity contracts (millions of Canadian dollars) | — | | 32 | | 12 | | — | | — | | — | | 44 | | |
Commodity contracts - natural gas (billions of cubic feet) | 34 | | 25 | | 23 | | 8 | | 3 | | — | | 93 | | |
Commodity contracts - crude oil (millions of barrels) | 11 | | — | | — | | — | | — | | — | | 11 | | |
| | | | | | | | |
Commodity contracts - power (megawatt per hour) (MW/H) | 19 | | (31) | | (46) | | — | | — | | — | | (17) | | 1 |
|
| | | | | | | | | | | | |
| March 31, 2018 | 2018 |
| 2019 |
| 2020 |
| 2021 |
| 2022 |
| Thereafter1 |
|
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) | 544 |
| 2 |
| 1 |
| — |
| — |
| — |
|
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) | 3,215 |
| 3,247 |
| 3,258 |
| 1,689 |
| 1,676 |
| 3,489 |
|
Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP) | — |
| — |
| — |
| — |
| — |
| — |
|
Foreign exchange contracts - GBP forwards - sell (millions of GBP) | — |
| 89 |
| 25 |
| 27 |
| 28 |
| 149 |
|
Foreign exchange contracts - Euro forwards - purchase (millions of Euro) | 264 |
| 375 |
| — |
| — |
| — |
| — |
|
Foreign exchange contracts - Euro forwards - sell (millions of Euro) | — |
| — |
| 35 |
| 169 |
| 169 |
| 889 |
|
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) | — |
| 32,662 |
| — |
| — |
| 20,000 |
| — |
|
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) | 3,749 |
| 2,100 |
| 527 |
| 109 |
| 93 |
| 203 |
|
Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) | 728 |
| 580 |
| 553 |
| 188 |
| 102 |
| — |
|
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars) | 2,242 |
| 800 |
| 447 |
| — |
| — |
| — |
|
Equity contracts (millions of Canadian dollars) | 40 |
| 37 |
| 8 |
| — |
| — |
| — |
|
Commodity contracts - natural gas (billions of cubic feet) | (16 | ) | (57 | ) | (23 | ) | (2 | ) | 14 |
| 2 |
|
Commodity contracts - crude oil (millions of barrels) | 1 |
| 2 |
| — |
| — |
| — |
| — |
|
Commodity contracts - NGL (millions of barrels) | (10 | ) | (1 | ) | — |
| — |
| — |
| — |
|
Commodity contracts - power (megawatt per hour) (MW/H)) | 60 |
| 64 |
| 66 |
| (3 | ) | (43 | ) | (43 | ) |
1 As at March 31, 2018, thereafter includesTotal is an average net purchase/(sell)(sale) of power of (43) MW/H for 2023 through 2025.
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 Other income or Interest expense in the Consolidated Statements of Earnings. The offsetting loss or gain on the hedged item attributable to the hedged risk is included in Other income in the Consolidated Statements of Earnings. Any excluded components are included in the Consolidated Statements of Comprehensive Income.
| | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | 2023 | 2022 |
| (millions of Canadian dollars) | | | | | |
| Unrealized gain/(loss) on derivative | | | | (11) | | 76 | |
| Unrealized gain/(loss) on hedged item | | | | 11 | | (87) | |
| Realized loss on derivative | | | | (11) | | (75) | |
| Realized gain on hedged item | | | | — | | 85 | |
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
The following table presents the effect of cash flow hedges and net investmentfair value hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes:
| | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | 2023 | 2022 |
| (millions of Canadian dollars) | | | | | |
| Amount of unrealized gain/(loss) recognized in OCI | | | | | |
| Cash flow hedges | | | | | |
| Foreign exchange contracts | | | | — | | 2 | |
| Interest rate contracts | | | | (105) | | 377 | |
| Commodity contracts | | | | 34 | | 4 | |
| Other contracts | | | | (2) | | 3 | |
| Fair value hedges | | | | | |
| Foreign exchange contracts | | | | 7 | | (1) | |
| | | | | |
| | | | | |
| | | | (66) | | 385 | |
| Amount of loss reclassified from AOCI to earnings | | | |
Foreign exchange contracts1 | | | | — | | 13 | |
Interest rate contracts2 | | | | 8 | | 76 | |
| | | | | |
Other contracts3 | | | | 1 | | 2 | |
| | | | | 9 | | 91 | |
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | | |
| Amount of unrealized gain/(loss) recognized in OCI | | |
| Cash flow hedges | | |
| Foreign exchange contracts | 21 |
| (2 | ) |
| Interest rate contracts | 100 |
| (14 | ) |
| Commodity contracts | (2 | ) | 21 |
|
| Other contracts | (14 | ) | (9 | ) |
| Net investment hedges | | |
| Foreign exchange contracts | 16 |
| 8 |
|
| | 121 |
| 4 |
|
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion) | | |
Foreign exchange contracts1 | (1 | ) | 1 |
|
Interest rate contracts2 | 41 |
| 48 |
|
Commodity contracts3 | (1 | ) | (2 | ) |
Other contracts4 | 9 |
| 9 |
|
| | 48 |
| 56 |
|
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) | | |
Interest rate contracts2 | (1 | ) | 2 |
|
| | (1 | ) | 2 |
|
| |
1 | Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings. |
| |
2 | Reported within Interest expense in the Consolidated Statements of Earnings. |
| |
3 | Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. |
| |
4 | Reported within Operating and administrative expense in the Consolidated Statements of Earnings. |
1Reported within Transportation and other services revenues and Other income 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 lossgain of $22$20 million offrom AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 33 months as at March 31, 2018.2023.
Fair Value Derivatives
For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings. During the three months ended March 31, 2018 and 2017, we recognized an unrealized loss of $8 million and $2 million, respectively, on the derivative and an unrealized gain of $8 million and $2 million, respectively, on the hedged item in earnings. During the three months ended March 31, 2018 and 2017, we recognized a realized loss of $3 million and nil, respectively, on the derivative and a realized gain of $3 million and nil, respectively, on the hedged item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness.
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
March 31, |
| | | | 2023 | 2022 |
| (millions of Canadian dollars) | | | | | |
Foreign exchange contracts1 | | | | 556 | | 433 | |
Interest rate contracts2 | | | | 10 | | — | |
Commodity contracts3 | | | | (39) | | (68) | |
Other contracts4 | | | | (7) | | 4 | |
| Total unrealized derivative fair value gain/(loss), net | | | | 520 | | 369 | |
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | | |
Foreign exchange contracts1 | (424 | ) | 273 |
|
Interest rate contracts2 | (2 | ) | (18 | ) |
Commodity contracts3 | 175 |
| 163 |
|
Other contracts4 | (9 | ) | — |
|
| Total unrealized derivative fair value gain/(loss), net | (260 | ) | 418 |
|
| |
1 | For the respective three months ended periods, reported within Transportation and other services revenues (2018 - $297 million loss; 2017 - $159 million gain) and Other income/(expense) (2018 - $127 million loss; 2017 - $114 million gain) in the Consolidated Statements of Earnings. |
| |
2 | Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings. |
| |
3 | For the respective three months ended periods, reported within Transportation and other services revenues (2018 - $1 million loss; 2017 - $22 million loss), Commodity sales (2018 - $82 million gain; 2017 - $187 million gain), Commodity costs (2018 - $84 million gain; 2017 - $5 million gain) and Operating and administrative expense (2018 - $10 million gain; 2017 - $7 million loss) in the Consolidated Statements of Earnings. |
| |
4 | Reported within Operating and administrative expense in the Consolidated Statements of Earnings. |
2Reported as an increase within Interest expense in the Consolidated Statements of Earnings.
3For the respective three months ended periods, reported within Transportation and other services revenues (2023 - $6 million gain; 2022 - $16 million loss), Commodity sales (2023 - $69 million gain; 2022 - $16 million loss), Commodity costs (2023 - $75 million loss; 2022 - $37 million loss) and Operating and administrative expense (2023 - $39 million loss; 2022 - $1 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 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. We also maintain currentOur shelf prospectuses with securities
regulators which enables, subject to market conditions,enable ready access to either the Canadian or United
StatesUS public capital markets.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 arewere in compliance
with all the terms and conditions of our committed credit facility agreements and term debt indentures as
at March 31, 2018.2023. 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 bythrough the 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:
| | | | | | | | |
| March 31,
2023 | December 31,
2022 |
| (millions of Canadian dollars) | | |
| Canadian financial institutions | 471 | | 644 | |
| US financial institutions | 115 | | 277 | |
| European financial institutions | 178 | | 334 | |
| Asian financial institutions | 97 | | 224 | |
Other1 | 88 | | 105 | |
| 949 | | 1,584 | |
|
| | | | |
| | March 31,
2018 |
| December 31,
2017 |
|
| (millions of Canadian dollars) | | |
| Canadian financial institutions | 49 |
| 82 |
|
| United States financial institutions | 29 |
| 19 |
|
| European financial institutions | 143 |
| 145 |
|
| Asian financial institutions | 15 |
| 2 |
|
Other1 | 72 |
| 137 |
|
| | 308 |
| 385 |
|
| |
1 | Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. |
As at March 31, 2018,2023, we provideddid not provide any letters of credit totaling nil 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 March 31, 20182023 and December 31, 2017.2022.
Gross derivative balances have been presented without the effects of collateral posted. Derivative assets
are adjusted for non-performance risk of our counterparties using their credit default swap spread rates
and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the
valuation.
Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, the assessment of credit ratings and netting arrangements. Within EGD and UnionEnbridge Gas, credit risk is mitigated by the utilities'utility's large and diversified customer base and the ability to recover an estimate for doubtful accountsexpected 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 classifyutilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and provide for receivables older than 30 days as past due.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
derivatives and other financial instruments. We also disclose the fair value of other financial instruments not measured at fair value. The
fair value of financial instruments reflects our best estimates of market value based on generally accepted
valuation techniques or models and is supported by observable market prices and rates. When such
values are not available, we use discounted cash flow analysis from applicable yield curves based on
observable market inputs to estimate fair value.
FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our derivativefinancial 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 derivativesfinancial 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 derivativefinancial 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.
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 derivativefinancial instrument valuations determined using directly or indirectly observable inputs other than
quoted prices included within Level 1. DerivativesFinancial 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 derivative.financial instrument. Derivatives valued using
Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange
forward and cross currencycross-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 to maturity preferred share investmentby our captive insurance subsidiaries, and restricted long-term
debt investments in Canadian government bonds held in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the
yield of certain Government of Canada bonds. 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 derivatives’derivatives' fair value. Generally, Level 3
derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing
information is not available or have no binding broker quote to support Level 2 classification. We have
developed methodologies, benchmarked against industry standards, to determine fair value for these
derivatives based on the extrapolation of observable future prices and rates. Derivatives valued using Level 3
inputs primarily include long-dated derivative power, contracts and NGL and natural gas contracts, basis
swaps, commodity swaps, and power and energy swaps, as well as options.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:
| | | March 31, 2018 | Level 1 |
| Level 2 |
| Level 3 |
| Total Gross Derivative Instruments |
| |
| March 31, 2023 | | March 31, 2023 | Level 1 | Level 2 | Level 3 | Total Gross
Derivative
Instruments |
| (millions of Canadian dollars) | |
| |
| |
| |
| (millions of Canadian dollars) | |
| Financial assets | |
| |
| |
| |
| Financial assets | |
| Current derivative assets | |
| |
| |
| |
| Current derivative assets | |
| Foreign exchange contracts | — |
| 134 |
| — |
| 134 |
| Foreign exchange contracts | — | | 122 | | — | | 122 | |
| Interest rate contracts | — |
| 27 |
| — |
| 27 |
| Interest rate contracts | — | | 215 | | — | | 215 | |
| Commodity contracts | — |
| 18 |
| 82 |
| 100 |
| Commodity contracts | 46 | | 63 | | 84 | | 193 | |
| Other contracts | | Other contracts | — | | 2 | | — | | 2 | |
| | — |
| 179 |
| 82 |
| 261 |
| | 46 | | 402 | | 84 | | 532 | |
| Long-term derivative assets | |
| |
| |
| |
| Long-term derivative assets | |
| Foreign exchange contracts | — |
| 110 |
| — |
| 110 |
| Foreign exchange contracts | — | | 214 | | — | | 214 | |
| Interest rate contracts | — |
| 15 |
| — |
| 15 |
| Interest rate contracts | — | | 198 | | — | | 198 | |
| Commodity contracts | — |
| 1 |
| 21 |
| 22 |
| Commodity contracts | — | | 17 | | 50 | | 67 | |
| Other contracts | — |
| — |
| — |
| — |
| |
| | | — |
| 126 |
| 21 |
| 147 |
| | — | | 429 | | 50 | | 479 | |
| Financial liabilities | |
| |
| |
| |
| Financial liabilities | |
| Current derivative liabilities | |
| |
| |
| |
| Current derivative liabilities | |
| Foreign exchange contracts | — |
| (355 | ) | — |
| (355 | ) | Foreign exchange contracts | — | | (131) | | — | | (131) | |
| Interest rate contracts | — |
| (306 | ) | — |
| (306 | ) | Interest rate contracts | — | | (20) | | — | | (20) | |
| Commodity contracts | (6 | ) | (88 | ) | (152 | ) | (246 | ) | Commodity contracts | (36) | | (48) | | (164) | | (248) | |
| Other contracts | — |
| (10 | ) | — |
| (10 | ) | |
| | | (6 | ) | (759 | ) | (152 | ) | (917 | ) | | (36) | | (199) | | (164) | | (399) | |
| Long-term derivative liabilities | |
| |
| |
| |
| Long-term derivative liabilities | |
| Foreign exchange contracts | — |
| (1,660 | ) | — |
| (1,660 | ) | Foreign exchange contracts | — | | (980) | | — | | (980) | |
| Interest rate contracts | — |
| (22 | ) | — |
| (22 | ) | Interest rate contracts | — | | (49) | | — | | (49) | |
| Commodity contracts | — |
| (4 | ) | (156 | ) | (160 | ) | Commodity contracts | — | | (26) | | (118) | | (144) | |
| Other contracts | — |
| (8 | ) | — |
| (8 | ) | |
| | — |
| (1,694 | ) | (156 | ) | (1,850 | ) | |
| Total net financial liabilities | |
| |
| |
| |
| |
| | | | — | | (1,055) | | (118) | | (1,173) | |
| Total net financial asset/(liability) | | Total net financial asset/(liability) | |
| Foreign exchange contracts | — |
| (1,771 | ) | — |
| (1,771 | ) | Foreign exchange contracts | — | | (775) | | — | | (775) | |
| Interest rate contracts | — |
| (286 | ) | — |
| (286 | ) | Interest rate contracts | — | | 344 | | — | | 344 | |
| Commodity contracts | (6 | ) | (73 | ) | (205 | ) | (284 | ) | Commodity contracts | 10 | | 6 | | (148) | | (132) | |
| Other contracts | — |
| (18 | ) | — |
| (18 | ) | Other contracts | — | | 2 | | — | | 2 | |
| | (6 | ) | (2,148 | ) | (205 | ) | (2,359 | ) | | 10 | | (423) | | (148) | | (561) | |
| | | December 31, 2017 | Level 1 |
| Level 2 |
| Level 3 |
| Total Gross Derivative Instruments |
| |
| December 31, 2022 | | December 31, 2022 | Level 1 | Level 2 | Level 3 | Total Gross
Derivative
Instruments |
| (millions of Canadian dollars) | |
| |
| |
| |
| (millions of Canadian dollars) | |
| Financial assets | |
| |
| |
| |
| Financial assets | |
| Current derivative assets | |
| |
| |
| |
| Current derivative assets | |
| Foreign exchange contracts | — |
| 143 |
| — |
| 143 |
| Foreign exchange contracts | — | | 46 | | — | | 46 | |
| Interest rate contracts | — |
| 8 |
| — |
| 8 |
| Interest rate contracts | — | | 660 | | — | | 660 | |
| Commodity contracts | 1 |
| 30 |
| 114 |
| 145 |
| Commodity contracts | 65 | | 90 | | 147 | | 302 | |
| Other contracts | | Other contracts | — | | 7 | | — | | 7 | |
| | 1 |
| 181 |
| 114 |
| 296 |
| | 65 | | 803 | | 147 | | 1,015 | |
| Long-term derivative assets | |
| |
| |
| |
| Long-term derivative assets | |
| Foreign exchange contracts | — |
| 145 |
| — |
| 145 |
| Foreign exchange contracts | — | | 309 | | — | | 309 | |
| Interest rate contracts | — |
| 13 |
| — |
| 13 |
| Interest rate contracts | — | | 254 | | — | | 254 | |
| Commodity contracts | — |
| 2 |
| 21 |
| 23 |
| Commodity contracts | — | | 17 | | 44 | | 61 | |
| Other contracts | | Other contracts | — | | 3 | | — | | 3 | |
| | — |
| 160 |
| 21 |
| 181 |
| | — | | 583 | | 44 | | 627 | |
| Financial liabilities | |
| |
| |
| |
| Financial liabilities | |
| Current derivative liabilities | |
| |
| |
| |
| Current derivative liabilities | |
| Foreign exchange contracts | | Foreign exchange contracts | — | | (566) | | — | | (566) | |
| | Commodity contracts | | Commodity contracts | (60) | | (77) | | (195) | | (332) | |
| | | | (60) | | (643) | | (195) | | (898) | |
| Long-term derivative liabilities | | Long-term derivative liabilities | |
| Foreign exchange contracts | | Foreign exchange contracts | — | | (1,116) | | — | | (1,116) | |
| Interest rate contracts | | Interest rate contracts | — | | (4) | | — | | (4) | |
| Commodity contracts | | Commodity contracts | — | | (38) | | (132) | | (170) | |
| | | | — | | (1,158) | | (132) | | (1,290) | |
| Total net financial asset/(liability) | | Total net financial asset/(liability) | |
| Foreign exchange contracts | — |
| (359 | ) | — |
| (359 | ) | Foreign exchange contracts | — | | (1,327) | | — | | (1,327) | |
| Interest rate contracts | — |
| (329 | ) | — |
| (329 | ) | Interest rate contracts | — | | 910 | | — | | 910 | |
| Commodity contracts | (13 | ) | (87 | ) | (339 | ) | (439 | ) | Commodity contracts | 5 | | (8) | | (136) | | (139) | |
| Other contracts | — |
| (3 | ) | — |
| (3 | ) | Other contracts | — | | 10 | | — | | 10 | |
| | (13 | ) | (778 | ) | (339 | ) | (1,130 | ) | | 5 | | (415) | | (136) | | (546) | |
| Long-term derivative liabilities | |
| |
| |
| |
| |
| Foreign exchange contracts | — |
| (1,312 | ) | — |
| (1,312 | ) | |
| Interest rate contracts | — |
| (40 | ) | — |
| (40 | ) | |
| Commodity contracts | — |
| (3 | ) | (183 | ) | (186 | ) | |
| Other contracts | — |
| (1 | ) | — |
| (1 | ) | |
| | — |
| (1,356 | ) | (183 | ) | (1,539 | ) | |
| Total net financial liabilities | |
| |
| |
| |
| |
| Foreign exchange contracts | — |
| (1,383 | ) | — |
| (1,383 | ) | |
| Interest rate contracts | — |
| (348 | ) | — |
| (348 | ) | |
| Commodity contracts | (12 | ) | (58 | ) | (387 | ) | (457 | ) | |
| Other contracts | — |
| (4 | ) | — |
| (4 | ) | |
| | (12 | ) | (1,793 | ) | (387 | ) | (2,192 | ) | |
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
| | | | | | | | | | | | | | | | | | | | |
| March 31, 2023 | 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 | (34) | | Forward gas price | 2.30 | | 10.29 | | 4.60 | | $/mmbtu2 |
| Crude | (12) | | Forward crude price | 72.61 | | 104.87 | | 92.25 | | $/barrel |
| | | | | | |
| Power | (92) | | Forward power price | 25.07 | | 214.37 | | 70.68 | | $/MW/H |
Commodity contracts - physical1 | | | | | | |
| Natural gas | (34) | | Forward gas price | 0.60 | | 8.14 | | 3.51 | | $/mmbtu2 |
| Crude | (9) | | Forward crude price | 74.97 | | 116.60 | | 91.05 | | $/barrel |
| | | | | | |
| Power | 33 | | Forward power price | 13.30 | | 107.36 | | 55.46 | | $/MW/H |
| (148) | | | | | | |
1Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2One million British thermal units (mmbtu).
|
| | | | | | | | | | |
| March 31, 2018 | Fair Value |
| Unobservable Input | Minimum Price/Volatility |
| Maximum Price/Volatility |
| Weighted Average Price |
| Unit of Measurement |
| (fair value in millions of Canadian dollars) | | | | | | |
Commodity contracts - financial1 | | | | | | |
| Natural gas | 9 |
| Forward gas price | 2.49 |
| 4.25 |
| 3.20 |
| $/mmbtu3 |
| Crude | (4 | ) | Forward crude price | 48.92 |
| 63.73 |
| 53.07 |
| $/barrel |
| NGL | (4 | ) | Forward NGL price | 0.34 |
| 1.83 |
| 1.29 |
| $/gallon |
| Power | (100 | ) | Forward power price | 14.30 |
| 76.27 |
| 52.00 |
| $/MW/H |
Commodity contracts - physical1 | | | | | | |
| Natural gas | (81 | ) | Forward gas price | 0.78 |
| 4.91 |
| 2.57 |
| $/mmbtu3 |
| Crude | (29 | ) | Forward crude price | 38.01 |
| 91.27 |
| 75.29 |
| $/barrel |
| NGL | 5 |
| Forward NGL price | 0.34 |
| 1.88 |
| 0.86 |
| $/gallon |
Commodity options2 | | | | | | |
| Crude | (1 | ) | Option volatility | 22 | % | 24 | % | 23 | % | |
| NGL | — |
| Option volatility | — | % | — | % | — | % | |
| Power | — |
| Option volatility | 23 | % | 26 | % | 24 | % | |
| | (205 | ) | | | | | |
| |
1 | Financial and physical forward commodity contracts are valued using a market approach valuation technique. |
| |
2 | Commodity options contracts are valued using an option model valuation technique. |
| |
3 | One million British thermal units (mmbtu). |
If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on
the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair
value measurement of Level 3 derivative instruments include forward commodity prices and, for option
contracts, price volatility.prices. Changes in forward commodity prices could result in significantly different fair
values for our Level 3 derivatives. Changes in price volatility would change the value of the option
contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the
estimate of price volatility.
Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:
| | | | | | | | |
| Three months ended
March 31, |
| | 2023 | 2022 |
| (millions of Canadian dollars) | | |
| Level 3 net derivative liability at beginning of period | (136) | | (108) | |
| Total gain/(loss) | | |
Included in earnings1 | (44) | | (52) | |
| Included in OCI | 33 | | 4 | |
| Settlements | (1) | | (24) | |
| Level 3 net derivative liability at end of period | (148) | | (180) | |
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | |
| |
|
| Level 3 net derivative liability at beginning of period | (387 | ) | (295 | ) |
| Total gain/(loss) | |
| |
|
Included in earnings1 | 31 |
| 83 |
|
| Included in OCI | (3 | ) | 19 |
|
| Settlements | 154 |
| 70 |
|
| Level 3 net derivative liability at end of period | (205 | ) | (123 | ) |
| |
1 | Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. |
1Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
Our policy is to recognize transfers as at the last day of the reporting period.
There were no transfers between levelsinto or out of Level 3 as at March 31, 20182023 or 2017.December 31, 2022.
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.
34
During the three months ended March 31, 2023 and 2022, we recognized unrealized foreign exchange gains of $59 million and $133 million, respectively, on the translation of US dollar-denominated debt, in OCI. No unrealized gains or losses on the change in fair value of our outstanding foreign exchange forward contracts were recognized in OCI during the three months ended March 31, 2023 and 2022. No realized gains or losses associated with the settlement of foreign exchange forward contracts were recognized in OCI during the three months ended March 31, 2023 and 2022. During the three months ended March 31, 2023 and 2022, we recognized a realized loss of $44 million and nil, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.
FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS
Our otherCertain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FMVA)(FVMA) investments and are recorded at cost less impairment. The carrying value of FMVA other long-termFVMA investments totaled $100$209 million and $99$102 million as at March 31, 20182023 and December 31, 2017,2022, respectively.
As at March 31, 2023, we had investments with a fair value of $646 million included in Restricted long-term investments in the Consolidated Statements of Financial Position (December 31, 2022 - $593 million). These securities are classified as available-for-sale and represent restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements.
We have Restrictedhad restricted long-term investments held in trust totaling $280 million and $267$249 million as at March 31, 20182023, which are classified as Level 1 in the fair value hierarchy (December 31, 2022 - $236 million). We also had restricted long-term investments held in trust totaling $397 million (cost basis - $451 million) and $357 million (cost basis - $437 million) as at March 31, 2023 and December 31, 2017,2022, respectively, which are recognized atclassified as Level 2 in the fair value.value hierarchy. There were unrealized holding gains of $34 million on these investments for the three months ended March 31, 2023 (2022 - losses of $60 million).
We have awholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments.As at March 31, 2023, the fair value of investments in equity funds and debt securities held to maturity preferred share investment carried at its amortized cost of $382by our captive insurance subsidiaries was $351 million and $371$309 million, respectively (December 31, 2022 - $335 million and $298 million, respectively). Our investments in debt securities had a cost basis of $303 million as at March 31, 20182023 (December 31, 2022 - $295 million). These investments in equity funds and December 31, 2017, respectively. These preferred sharesdebt securities are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.50%. Asrecognized at March 31, 2018fair value, classified as Level 1 and December 31, 2017,Level 2 in the fair value hierarchy, respectively, and are recorded in Other current assets and Long-term investments in the Consolidated Statements of this preferred share investment approximates its face valueFinancial Position. There were unrealized holding gains of $580 million.$15 million and losses of $8 million for the three months ended March 31, 2023 and 2022, respectively.
As at March 31, 20182023 and December 31, 2017,2022, our long-term debt had a carrying value of $65.6$79.5 billion and $64.0$79.3 billion, respectively, before debt issuance costs and a fair value of $68.0$74.9 billion and $67.4$73.5 billion, respectively. We also have noncurrentnon-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at March 31, 20182023 and December 31, 2017,2022, the noncurrentnon-current notes receivable hashad a carrying value of $92$691 million and $89$752 million, respectively, and awhich also approximates their fair value of $92 million and $89 million, respectively.value.
The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, Restrictedrestricted long-term investments, and long-term debt and non-current notes receivable described above approximate their costcarrying value due to the short period to maturity.
NET INVESTMENT HEDGES
We have designated a portion of our United States dollar denominated debt, as well as a portfolio of
foreign exchange forward contracts, as a hedge of our net investment in United States dollar
denominated investments and subsidiaries.
During the three months ended March 31, 2018 and 2017, we recognized an unrealized foreign exchange
loss of $194 million on the translation of United States dollar denominated debt and a gain of $20 million, respectively, and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of $15 million and $9 million, respectively, in OCI. During the three months ended March 31, 2018 and 2017, we recognized a realized loss of $23 million and gain of $1 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts and recognized a realized loss of $11 million and gain of $20 million, respectively, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the three months ended March 31, 2018 and 2017.
11. 8. INCOME TAXES
The effective income tax rates for the three months ended March 31, 20182023 and 20172022 were (16.7)%21.5% and 17.3%22.4%, respectively.
The period-over-period decrease in the effective income tax rate is primarily due to higher investment tax credits available on certain capital projects in the US, and the effects of rate-regulated accounting for income taxes and other permanent items relative to the decrease in earnings for the three months ended March 31, 2018 as well as the impact of the United States federal corporate income tax rate reduction enacted in 2017.earnings.
On December 22, 2017, the United States enacted the TCJA and we made reasonable estimates for the measurement and accounting of certain effects of the TCJA in our consolidated financial statements for the year ended December 31, 2017. We recorded a nil provision in the first quarter of 2018, based on
9. OTHER INCOME
| | | | | | | | |
| Three months ended March 31, |
| 2023 | 2022 |
| (millions of Canadian dollars) | | |
| Gain/(loss) on dispositions | 3 | | (2) | |
| Realized foreign currency gain | 145 | | 2 | |
| Unrealized foreign currency gain/(loss) | (188) | | 367 | |
| Net defined pension and OPEB credit | 33 | | 58 | |
| Other | 109 | | 33 | |
| | 102 | | 458 | |
35
existing guidance and legislation, for the remaining effects of the TCJA including the Global Intangible Low Taxed Income tax and the Base Erosion and Anti-abuse tax.
12. PENSION AND OTHER POSTRETIREMENT BENEFITS
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | | |
| Service cost | 65 |
| 54 |
|
| Interest cost | 45 |
| 32 |
|
| Expected return on plan assets | (82 | ) | (51 | ) |
| Amortization of prior service costs | (1 | ) | — |
|
| Amortization of actuarial loss | 7 |
| 9 |
|
| Net periodic benefit costs | 34 |
| 44 |
|
13. CONTINGENCIES
LITIGATION
We and our subsidiaries are involved insubject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups.permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our interim consolidated financial position or results of operations.
TAX MATTERS
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.
INSURANCE
We maintain a comprehensive insurance program for us, our operating subsidiaries and certain equity investments. This program includes insurance coverage in types and amounts and is subject to certain deductibles, terms, exclusions and conditions that are generally consistent with coverage considered customary for our industry, however insurance does not cover all events in all circumstances. We self-insure a significant portion of expected losses relating to certain insurance property and casualty risk exposures in the US and Canada through our wholly-owned captive insurance subsidiaries.
36
In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among entities on an equitable basis based on an insurance allocation agreement we have entered into with us and other subsidiaries. Insurance estimates include certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices and the selection of estimated loss among estimates derived using different methods.
11. SUBSEQUENT EVENT
14. SUBSEQUENT EVENTS
On April 12, 2018, we completed an offering of $750 million of fixed-to-floating rate subordinated
notes that mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry
a fixed interest rate of 6.625%. After the initial 10 years, the interest rate will be set to equal the Canadian Dollar Offered Rate plus a margin of 432 basis points from years 10 to 30, and a margin of 507 basis points from years 30 to 60.
On April 12, 2018, we completed an offering of US$600 million of fixed-to-floating rate subordinated
notes that mature in 60 years and are callable on or after year5. For the initial 5 years, the notes carry a fixed interest rate of 6.375%. After the initial 5 years, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years5 to 10, a margin of 384 basis points from years 10 to 25, and a margin of 459 basis points from years 25 to 60.
TRES PALACIOS HOLDINGS LLC
On April 30, 2018, Sabal Trail Transmission, LLC (Sabal Trail), a joint venture in which SEP owns a 50% interest, issued US$500 million in aggregate principal amount of 4.246% senior notes due in 2028,
US$600 million in aggregate principal amount of 4.682% due in 2038 and US$400 million in aggregate principle amount of 4.832% due in 2048. Sabal Trail distributed net proceeds from the offering to the partners as a partial reimbursement of construction and development costs incurred by the partners. The net contribution made to SEP was approximately US$750 million to be used to pay down indebtedness.
On May 9, 20183, 2023, we entered into agreements with the Canadian Pension Plan Investment Board to sell a 49% interest in all of our Canadian renewable energy generation assets, 49% of two large United States renewable assets and 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion, both concurrently under construction in Germany (collectively, the Assets). Initial proceeds from the transaction are $1.75 billion. In addition, our partner will fund their pro-rata share of the remaining capital on the Hohe See Offshore wind project. We will maintain a 51% interest in the Assets and continue to manage, operate and provide administrative services for the Assets. The transaction is subject to closing adjustments and conditions customary in transactions of this nature. Closing is expected to occur during the third quarter of 2018 subject to the receipt of all necessary regulatory approvals and consents.
On May 9, 2018 our indirect subsidiary, Enbridge (U.S.) Inc. entered into a definitive agreement to sell Midcoast Operating, L.P. and its subsidiaries (Sales Agreement), which conducts our United States natural gas and NGL gathering, processing, transportation and marketing businesses, to AL Midcoastacquired Tres Palacios Holdings LLC (an affiliate(Tres Palacios) for US$335 million of ArcLight Capital Partners, LLC) for a cash, purchase price of US$1.1 billion, subject to customary closing adjustments. The transactionTres Palacios is expected to closea natural gas storage facility located in the third quarter of 2018, subject to receipt of customary regulatory approvalsUS Gulf Coast and satisfaction of other customary closing conditions.
its infrastructure serves Texas gas-fired power generation and liquefied natural gas exports, as well as Mexico pipeline exports.
37
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 in conjunction with the auditedour consolidated financial statements and the accompanying footnotesnotes included in Part II. Item 8. Financial Statements and Supplementary Data of our Annual Reportannual report on Form 10-K for the year ended December 31, 2017,2022.
We continue to qualify as fileda 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
MAINLINE TOLLING AGREEMENT
Enbridge Inc. (Enbridge) has reached an agreement in principle on February 16, 2018.
UNITED STATES TAX REFORM UPDATE
On December 22, 2017,a negotiated settlement (the settlement) with shippers for tolls on its Mainline pipeline system. The settlement covers both the United States enacted the Tax CutsCanadian and Jobs Act (TCJA). As disclosed in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 16, 2018, we made certain estimates for the measurement and accounting of certain effectsUS portions of the TCJAMainline and would see the Mainline continuing to operate as a common carrier system available to all shippers on a monthly nomination basis. The settlement is subject to regulatory and other approvals and the term is seven and a half years through the end of 2028, with new interim tolls to take effect on July 1, 2023.
The settlement will include:
•an International Joint Toll (IJT), for heavy crude oil movements from Hardisty to Chicago, comprised of a Canadian Mainline Toll of $1.65 per barrel plus a Lakehead System Toll of US$2.57 per barrel, plus the year endedapplicable Line 3 Replacement surcharge;
•toll escalation for operation, administration, and as at December 31, 2017. As wepower costs tied to US consumer price and power indices;
•tolls will continue to gather, preparebe distance and analyzecommodity adjusted, and will utilize a dual currency IJT; and
•a financial performance collar providing incentives for Enbridge to optimize throughput and cost, but also providing downside protection in the necessary information in reasonable detailevent of extreme supply or demand disruptions or unforeseen operating cost exposure. This performance collar is intended to completeensure the accounting forMainline will earn 11% to 14.5% returns, on a deemed 50% equity capitalization, which is similar to the impactreturns earned on average during the previous tolling agreement.
Approximately 70% of Mainline deliveries are tolled under this settlement, while approximately 30% of deliveries are tolled on a full path basis to markets downstream of the TCJA, we continue to refine our estimates. DuringMainline. The other continuing feature is that the first quarter of 2018 we refined our calculation ofMainline toll will flex up or down US$0.035 per barrel for 50,000 barrel per day changes in throughput.
The expected financial outcome from this settlement is in line with previously reported financial results after taking into consideration the regulatory liability associated with the TCJA. This resulted in a reduction of the US$860 million overall regulatory liability at Spectra Energy Partners, LP (SEP) by US$25 million.previously recognized provision, inflationary cost adjustments and increased volumes.
We have also recorded a nil provision in the first quarter of 2018, based on existing guidance and
legislation, for the Global Intangible Low Taxed Income tax and the Base Erosion and Anti-abuse
tax.
SEP INCENTIVE DISTRIBUTION RIGHTS
On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our incentive distribution rights (IDRs) and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, allsettlement, Enbridge will be settling its previously filed Lakehead cost of service application, currently before the IDRs have been eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 million of SEP common units, representing approximately 83% of SEP's outstanding common units.
REVISED FERC POLICY ON TREATMENT OF INCOME TAXES
On March 15, 2018, theUS' Federal Energy Regulatory Commission (FERC) revised.
ACQUISITIONS
Tres Palacios Holdings LLC
On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for US$335 million of cash, subject to customary closing adjustments. Tres Palacios is a long standing policy announcing that it would no longer permit entities organized as Master Limited Partnerships (MLPs) to recover an income tax allowance for interstate pipeline assets with cost-of-service rates. The announcement of the Revised Policy Statement was accompanied by: (i) a Notice of Proposed Rulemaking proposing interstate natural gas pipelines file a one-time report to quantifystorage facility located in the impact of the federal income tax rate reductionUS Gulf Coast and the impact of the revised Policy Statement on each pipeline;its infrastructure serves Texas gas-fired power generation and (ii) a Notice of Inquiry seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation.
We hold United States liquids andliquefied natural gas pipelines through a number of different ownership structures, including MLPs. Spectra Energy Partners (SEP) and Enbridge Energy Partners (EEP) have responded to the FERC announcement regarding tax allowance, both directly and through industry associations, objecting to the change in FERC policy and requesting a re-hearing. On April 27, 2018, the FERC issued a tolling order for the purpose of affording it additional time for consideration of matters raised on rehearing. These FERC announcements have adversely affected MLPs generally, including
SEP and EEP. Both the direct consequences of the change in FERC policyexports, as well as the adverse market effect may negatively impact the longer-term availabilityMexico pipeline exports. Tres Palacios is comprised of capital to SEPthree natural gas storage salt caverns with a total FERC-certificated working gas capacity of approximately 35 billion cubic feet (Bcf) and EEP at attractive terms.also owns an integrated 62-mile natural gas header pipeline system, with eleven inter- and intrastate natural gas pipeline connections.
While there will likely be varying impacts to each of the sponsored vehicles, on a consolidated basis, we do not expect a material impact to our results of operations or cash flows over the 2018 to 2020 horizon. Under the International Joint Toll mechanism on the Mainline System, reductions in the EEP tariff would create an offsetting revenue increase on the Canadian Mainline system owned by the Fund Group. In addition, while many uncertainties remain in regard to the implementation of the recent FERC actions, if implemented as announced, we estimate the unmitigated impact to revenue from SEP would not be material to us. We continue to evaluate a variety of options to mitigate the negative impact of the FERC policy change on both EEP and SEP.
ASSET MONETIZATION
On May 9, 2018 we entered into agreements with the Canadian Pension Plan Investment Board to sell a49% interest in all of our Canadian renewable energy generation assets, 49% of two large United States renewable assets and 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion, both concurrently under construction in Germany, (collectively, the Assets). Initial proceeds from the transaction are $1.75 billion. In addition, our partner will fund their pro-rata share of the remaining capital on the Hohe See Offshore wind project. We will maintain a 51% interest in the Assets and continue to manage, operate and provide administrative services for the Assets. The transaction is subject to closing adjustments and conditions customary in transactions of this nature. Closing is expected to occur during the third quarter of 2018 subject to the receipt of all necessary regulatory approvals and consents.
Aitken Creek Gas Storage
On May 9, 2018 our indirect subsidiary,1, 2023, we announced that Enbridge (U.S.) Inc.has entered into a definitive agreement to sell Midcoast Operating, L.P.acquire a 93.8% interest in Aitken Creek Gas Storage Facility and its subsidiaries, which conducts our United Statesa 100% interest in Aitken Creek North Gas Storage Facility (collectively, Aitken Creek) for $400 million of cash plus payment for derivative contracts and gas inventory, subject to other customary closing adjustments. Aitken Creek is a natural gas and naturalstorage facility located in British Columbia, Canada with a working gas liquids gathering, processing, transportation and marketing businesses, to AL Midcoast Holdings, LLC (an affiliatecapacity of ArcLight Capital Partners, LLC) for a cash purchase price of US$1.1 billion, subject to customary closing adjustments.approximately 77 Bcf. The transaction is expected to close later in the third quarter of 2018,2023, subject to receipt of customary regulatory approvals and satisfaction of other customary closing conditions.
FORWARD-LOOKING INFORMATIONGAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS
Forward-looking information, or forward-looking statements, have been included in this quarterly report
Texas Eastern Transmission
The Stipulation and Agreement for Texas Eastern Transmission, LP’s (Texas Eastern) consolidated 2021 rate cases was approved by the FERC on MD&ANovember 30, 2022, and became effective on January 1, 2023. Texas Eastern received FERC approval on April 3, 2023 to provide information about usimplement the settled rates and our subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriateother settlement provisions.
Maritimes & Northeast Pipeline
The current toll settlement agreement for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows; expected performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution, Green Power and Transmission, and Energy Services businesses; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions; estimated future dividends; recovery of the costs of the Canadian portion of Maritimes & Northeast (M&N) Pipeline expires in December 2023. Settlement negotiations with M&N Pipeline shippers are planned throughout 2023 with the Line 3 Replacement Program (Canadian L3R Program);objective of reaching a toll settlement which would be effective January 1, 2024. It is expected future actionsthat a settlement agreement will be filed in the fourth quarter of regulators;2023 with the Canada Energy Regulator (CER) for review and approval. A CER decision is expected costs relatedin the first quarter of 2024.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
Incentive Regulation Rate Application
In October 2022, Enbridge Gas Inc. (Enbridge Gas) filed its application with the Ontario Energy Board (OEB) to leak remediationestablish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regardingframework seeks approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term (2025 – 2028). An OEB decision is expected on Phase 1 of 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 2023, the April 1, 2023 QRAM application was filed and approved by the OEB, which included an adjustment to the prior mitigation approved as part of the July 1, 2022 QRAM. The recovery of the outstanding PGVA balance from the extended recovery period approved as part of the July 1, 2022 QRAM will now be completed by March 31, 2024.
As at March 31, 2023, Enbridge Gas' PGVA receivable balance was $287 million.
FINANCING UPDATE
In March 2023, we closed a two-tranche US debt offering consisting ofthree-year senior notes, callable at par after one year at our option, and 10-year sustainability-linked senior notes, for an aggregate principal amount of US$3.0 billion. Each tranche is payable semi-annually in arrears and matures in March 2026 and March 2033, respectively.
In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion.
On April 15, 2023 call date, we redeemed at par all of the outstanding US$600 million five-year callable, 6.38% fixed-to-floating rate subordinated notes that carried an original maturity date of April 2078.
These financing activities, in combination with the financing activities executed in 2022, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects and other operating working capital requirements without requiring access to the capital markets for the next 12 months, should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources.
As at March 31, 2023, after adjusting for the impact of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction) including our combined scale, financial flexibility, growth program, future business prospects and performance; impact of the Canadian L3R Program on existing integrity programs; the sponsored
vehicle strategy; dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of hedging program; and expectations resulting from the successful executionfloating-to-fixed interest rate swap hedges, less than 5% of our 2018-2020 Strategic Plan.
Although we believe these forward-looking statements are reasonable based on thetotal debt is exposed to floating rates. Refer to Part I. Item 1. Financial Statements - Note 7 - Risk Management and Financial Instruments for more information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labor and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of the dividend policy on our future cash flows; credit ratings; capital project funding; expected EBITDA; expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to the impact of the Merger Transaction on us, expected EBITDA, earnings/(loss), earnings/(loss) per share, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes.rate hedging program.
Our forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger Transaction, operating performance, regulatory parameters, dividend policy, project approval and support, renewals of rights-of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this quarterly report on MD&A and in our other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge Inc. assumes no obligation to publicly update or revise any forward-looking statements made in this quarterly report on MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.
RESULTS OF OPERATIONS
| | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | | 2023 | 2022 |
| (millions of Canadian dollars, except per share amounts) | | | | | |
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1 | | | | | |
| Liquids Pipelines | | | | 2,363 | | 2,329 | |
| Gas Transmission and Midstream | | | | 1,205 | | 1,014 | |
| Gas Distribution and Storage | | | | 716 | | 665 | |
| Renewable Power Generation | | | | 136 | | 162 | |
| Energy Services | | | | 1 | | (101) | |
| Eliminations and Other | | | | 6 | | 355 | |
Earnings before interest, income taxes and depreciation and amortization1 | | | | 4,427 | | 4,424 | |
| Depreciation and amortization | | | | (1,146) | | (1,055) | |
| Interest expense | | | | (905) | | (719) | |
| Income tax expense | | | | (510) | | (593) | |
| Earnings attributable to noncontrolling interests | | | | (49) | | (28) | |
| Preference share dividends | | | | (84) | | (102) | |
| Earnings attributable to common shareholders | | | | 1,733 | | 1,927 | |
| Earnings per common share attributable to common shareholders | | | | 0.86 | | 0.95 | |
| Diluted earnings per common share attributable to common shareholders | | | | 0.85 | | 0.95 | |
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.
40
|
| | | | |
| | Three months ended March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars, except per share amounts) | |
| |
|
| Segment earnings/(loss) before interest, income taxes and depreciation and amortization | | |
| Liquids Pipelines | 1,156 |
| 1,480 |
|
| Gas Transmission and Midstream | 126 |
| 475 |
|
| Gas Distribution | 636 |
| 387 |
|
| Green Power and Transmission | 109 |
| 101 |
|
| Energy Services | 169 |
| 156 |
|
| Eliminations and Other | (279 | ) | (298 | ) |
| | | |
| Depreciation and amortization | (824 | ) | (672 | ) |
| Interest expense | (656 | ) | (486 | ) |
| Income tax expense | 73 |
| (198 | ) |
| (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests | 24 |
| (224 | ) |
| Preference share dividends | (89 | ) | (83 | ) |
| Earnings attributable to common shareholders | 445 |
| 638 |
|
| Earnings per common share | 0.26 |
| 0.54 |
|
| Diluted earnings per common share | 0.26 |
| 0.54 |
|
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
Three months ended March 31, 2018,2023, compared with the three months ended March 31, 20172022
Earnings Attributableattributable to Common Shareholders for the period ended March 31, 2018common shareholders were positively impacted by contributions of approximately $364 million from new assets following the completion of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (Merger Transaction).
After taking into consideration the contribution of additional earnings from the Merger Transaction, Earnings Attributable to Common Shareholders was negatively impacted by $893$215 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
•a realized loss of $913$638 million ($701479 million after-tax attributableafter-tax) due to us) on Midcoast Operating, L.P. and its subsidiaries resulting from a revision totermination of foreign exchange hedges, reflecting changes in the fair value ofkey settlement terms under the assets held for sale based on the sale price; refer to Part I. Item 1. Financial Statements - Note 6. Assets Held for SaleCompetitive Toll Settlement (CTS);
partially offset by•a non-cash, net unrealized derivative fair value loss of $277 million ($146 million after-tax attributable to us) in 2018, compared with a gain of $416$532 million ($245399 million after-tax attributableafter-tax) in 2023, compared to us)a net gain of $433 million ($331 million after-tax) in the corresponding 2017 period,2022, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity prices risks;
•a lossnon-cash, net positive equity earnings adjustment of $144$8 million ($856 million after-tax attributableafter-tax) in 2023, compared to us)a net negative adjustment of $63 million ($47 million after-tax) in 2018 related2022 relating to our share of changes in the Line 10 crude oil pipeline (Line 10), which is a componentmark-to-market value of derivative financial instruments of our mainline system, resulting from its classification as an asset held for sale and equity method investee, DCP Midstream, LP (DCP);
•the subsequent measurement at the lowerreceipt of carrying value or fair value less costs to sell;
employee severance, transition and transformation costsa litigation claim settlement of $97$68 million ($9652 million after-tax attributable to us)after-tax) in 2018, compared with $129 million ($78 million after-tax attributable to us) in the corresponding 2017 period, related to the Merger Transaction; partially offset by2023;
•the absence of transaction costsa $44 million ($33 million after-tax) impairment of $152 million ($111 million after-tax attributable to us) recordedlease assets in 2017 related to the Merger Transaction;2022;
•a non-cash, net unrealized gain of $50$8 million after-tax attributable($6 million after-tax) in 2023, compared to usa net loss of $21 million ($16 million after-tax) in 2018, compared with 2022, 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 loss $40net unrealized gain of $13 million ($11 million after-tax) in 2023, reflecting changes in the corresponding 2017 period, resulting from the reallocationmark-to-market value of income betweenequity fund investments held by our interest and thewholly-owned captive insurance subsidiaries.
noncontrolling interests in Enbridge Energy Partners, L.P. (EEP) to resolve capital account deficits as required under EEP’s partnership agreement; and
a gain of $63 million after-tax attributable to us in 2018 resulting from the impact of the TCJA on our United States Green Power and Transmission assets.
As it pertains to theThe non-cash, unrealized derivative fair value gains and losses discussed above we havegenerally arise as a result of our comprehensive long-term economic hedging program to mitigate interest rate, 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 financial 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 $336$21 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:by:
stronger
•higher contributions from our Liquids Pipelines segment due to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and higher volumes from the Flanagan South Pipeline;
•higher contributions from Mainline System and Line 9 in our Liquids Pipelines segment driven by increased crude demand, net of a lower Line 3 Replacement (L3R) surcharge and the recognition of a higher foreign exchange hedgeprovision against the interim Mainline IJT;
•recognition of revenues in our Gas Transmission and Midstream segment attributable to the Texas Eastern rate used to record United Statescase settlement, which we did not begin recognizing until the second half of 2022; and
•the favorable effect of translating US dollar denominated Canadian Mainline revenues,earnings at a higher International Joint Tariff (IJT) Benchmark Toll and higher throughput drivenaverage exchange rate in 2023 compared to the same period in 2022; partially offset by capacity optimization initiatives implemented
•a reduction in 2017;
contributions from new Liquids Pipelines assets placed into service in 2017; and
increased earnings from our Gas DistributionTransmission and Midstream segment primarily due to colder weatherour decreased interest in DCP as a result of a joint venture merger transaction with Phillips 66 that closed in the third quarter in 2022;
•lower commodity prices impacting the DCP and Aux Sable Canada LP, Aux Sable Liquid Products LP and Aux Sable Midstream LLC (collectively, Aux Sable) joint ventures in our Gas Transmission and Midstream segment; and
•higher Interest expense primarily due to higher interest rates and higher distribution charges.average principal.
BUSINESS SEGMENTS
LIQUIDS PIPELINES
| | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | | 2023 | 2022 |
| (millions of Canadian dollars) | | | | | |
| Earnings before interest, income taxes and depreciation and amortization | | | | 2,363 | | 2,329 | |
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | |
| |
|
| Earnings before interest, income taxes and depreciation and amortization | 1,156 |
| 1,480 |
|
Three months ended March 31, 2018,2023, compared with the three months ended March 31, 20172022
Earnings before interest, income taxes and depreciation and amortization (EBITDA) for the period ended March 31, 2018EBITDA was positivelynegatively impacted by $53 million of contributions from new assets following the completion of the Merger Transaction.
After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $626$103 million due to certain unusual, infrequent or other non-operating factors, primarily explained byby:
•a realized loss of $638 million due to termination of foreign exchange hedges, reflecting changes in the following:key settlement terms under the CTS; partially offset by
•a non-cash, net unrealized lossgain of $298$613 million in 20182023, compared with a $164net gain of $122 million gain in 20172022, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and
•the receipt of a losslitigation claim settlement of $144$68 million in 2018 related to Line 10, which is a component of our mainline system, resulting from its classification as an asset held for sale and the subsequent measurement at the lower of carrying value or fair value less costs to sell.
2023.
After taking into consideration the factors above, the remaining $249$137 million increase is primarily explained by the following significant business factors:
•higher contributions from the Gulf Coast and Mid-Continent Systems due primarily to increased earnings resulting from a higher foreign exchange hedge rate used to record United States dollar denominated Canadian Mainline revenuesownership of $1.25the Gray Oak Pipeline and Cactus II Pipeline acquired in 2018 compared with $1.04 in 2017;
increased earnings resulting from a higher IJT Benchmark Tollthe second half of $4.07 in 2018 compared with $4.05 in 2017,2022 and higher toll surcharges forvolumes from the recovery of costs related to certain expansion projects;Flanagan South Pipeline;
increased earnings resulting from •higher Canadian Mainline and Lakehead Pipeline System ex-Gretna average throughput of 2,625 thousands of3.1 million barrels per day (kbpd)(mmbpd) in 20182023 as compared with 2,593 kbpdto 3.0 mmbpd in 20172022, and higher Line 9 deliveries to eastern Canada driven by capacity optimization initiatives implemented in 2017;increased crude demand, net of a lower L3R surcharge and the recognition of a higher provision against the interim Mainline IJT;
•higher contributions from assets placed into service during 2017, including the Wood Buffalo Extension Pipeline, the Athabasca Pipeline Twincertain Bakken pipelines due to higher volumes; and the Norlite Pipeline System and the acquisition of a minority interest in the Bakken Pipeline System;
increased transportation revenues resulting from an increase in the level of committed take-or-pay volumes and higher spot volumes on Flanagan South Pipeline driven by strong demand in the United States Gulf Coast; partially offset by
the net unfavorable•favorable effect of translating United StatesUS dollar EBITDAearnings at a lower Canadian to United States dollarhigher average exchange rate (Average Exchange Rate)in 2023 compared to the same period in 2022; partially offset by
•lower contribution from Seaway Crude Pipeline System due to lower volumes in 2023 and higher expiration of $1.26customer make-up rights in 2018 compared with $1.32 in 2017.the same period of 2022; and
•higher power costs as a result of increased volumes and power prices.
GAS TRANSMISSION AND MIDSTREAM
| | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | | 2023 | 2022 |
| (millions of Canadian dollars) | | | | | |
| Earnings before interest, income taxes and depreciation and amortization | | | | 1,205 | | 1,014 | |
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | | |
| Earnings before interest, income taxes and depreciation and amortization | 126 |
| 475 |
|
Three months ended March 31, 2018,2023, compared with the three months ended March 31, 20172022
EBITDA for the period ended March 31, 2018 was positively impacted by $570 million of contributions from new assets following the completion of the Merger Transaction. When compared to pre-merger results from the prior period, operating results from the new assets include higher earnings primarily from business expansion projects on Algonquin Gas Transmission, Sabal Trail Transmission and Texas Eastern Transmission, LP.
After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $923$60 million due to certain unusual, infrequent or other marketnon-operating factors, primarily explained by the following:
a loss of $913 million on Midcoast Operating, L.P. and its subsidiaries resulting from a revision to the fair value of the assets held for sale based on the sale price; refer to Part I. Item 1. Financial Statements - Note 6. Assets Held for Sale; and
a non-cash, unrealized gainnet positive equity earnings adjustment of $6$8 million in 20182023, compared withto a gainnet negative adjustment of $10$63 million in 2017 reflecting net fair value gains and losses arising from the change2022 relating to our share of changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risk.of our equity method investee, DCP.
After taking into consideration the factors above, theThe remaining $4$131 million increase is primarily explained by the following significant business factors:
operational efficiencies
•recognition of $13 million achieved on our United States Midstreamrevenues attributable to the Texas Eastern rate case settlement, which we did not begin recognizing until the second half of 2022; and Canadian assets;
increased•the favorable effect of translating US dollar earnings of $6 millionat a higher average exchange rate in 2023 compared to the same period in 2022; partially offset by
•a reduction in earnings from our Allianceinvestment in DCP as a result of our decreased interest due to the joint venture due to favorable seasonal firmmerger transaction with Phillips 66 that closed during the third quarter in 2022; and interruptible revenues that resulted from wider basis differentials; partially offset by
decreased margins of $13 million on•lower commodity prices impacting our United States Midstream assets resulting from lower volumes.DCP and Aux Sable joint ventures.
GAS DISTRIBUTION AND STORAGE
| | | | Three months ended
March 31, | | | Three months ended
March 31, |
| | 2018 |
| 2017 |
| | | 2023 | 2022 |
| (millions of Canadian dollars) | | | (millions of Canadian dollars) | | | |
| Earnings before interest, income taxes and depreciation and amortization | 636 |
| 387 |
| Earnings before interest, income taxes and depreciation and amortization | | 716 | | 665 | |
Three months ended March 31, 2018,2023, compared with the three months ended March 31, 20172022
EBITDA for the period ended March 31, 2018 was positively impacted by $180$51 million of contributions from Union Gas Limited (Union Gas) following the completion of the Merger Transaction. When compared to pre-merger results from the prior period, Union Gas' operating results benefited from colder weather and higher revenues primarily due to expansion.
After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $16 million due to certain unusual, infrequent and other business factors, primarily explained by the following:
a non-cash, unrealized gain of $1 million in 2018 compared with a gain of $10 million in 2017 arising from the change in the mark-to-market value of Noverco Inc.'s derivative financial instruments; and
a negative equity earnings adjustment of $9 million at Noverco Inc. in 2018 arising from the United States TCJA.
After taking into consideration the factors above, the remaining $85 million increase is primarily explained by the following significant business factors:
increased earnings of $25 million resulting from colder weather experienced in our franchise service areas; and
•higher distribution charges primarily reflecting growthresulting from increases in rate base.rates and customer base; and
•favorable timing of recognition of storage demand and transportation costs of $63 million, which will be reversed over the remainder of 2023; partially offset by
•weather, when compared with the normal weather forecast embedded in rates, was warmer in 2023 and colder in 2022, resulting in a negative EBITDA impact of approximately $63 million year-over- year. GREEN
RENEWABLE POWER AND TRANSMISSIONGENERATION
| | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | | 2023 | 2022 |
| (millions of Canadian dollars) | | | | | |
| Earnings before interest, income taxes and depreciation and amortization | | | | 136 | | 162 | |
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | |
| |
|
| Earnings before interest, income taxes and depreciation and amortization | 109 |
| 101 |
|
Three months ended March 31, 2018,2023, compared with the three months ended March 31, 20172022
EBITDA decreasedwas negatively impacted by $30$26 million primarily due to certain unusual, infrequent and other factors, primarily explained by the following:
an asset impairment charge of $22 million in 2018 from our equity investment in NRGreen Power Limited Partnership related to the Chickadee Creek waste heat recovery facility in Alberta; and
| |
▪ | a loss of $11 million in 2018 from our equity investment in Rampion Offshore Wind Limited resulting from damaged cables. |
After taking into consideration the factors above, the remaining $38 million increase is primarily explained by the following significant business factors:
strongerweaker wind resources of $13 million at Canadian and United StatesEuropean wind farms;
contributions from the Chapman Ranch Wind Project, which was placed into service in October 2017;
contributions from the Rampion Offshore Wind Project, which is expected to be fully operational in the second quarter of 2018;facilities and
a net gain of $11 million from an arbitration settlement related to our Canadian lower energy pricing at European offshore wind facilities.
ENERGY SERVICES
| | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | | 2023 | 2022 |
| (millions of Canadian dollars) | | | | | |
| Earnings/(loss) before interest, income taxes and depreciation and amortization | | | | 1 | | (101) | |
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | |
| |
|
| Earnings before interest, income taxes and depreciation and amortization | 169 |
| 156 |
|
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 March 31, 2018,2023, compared with the three months ended March 31, 20172022
EBITDA decreasedwas positively impacted by $13$37 million due to certain unusual, infrequent or othernon-operating factors, primarily explained by the following:
a non-cash, net unrealized gain of $147$8 million in 20182023, compared with a gainnet loss of $160$21 million in 20172022, reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions, andas well as to manage the exposure to movements in commodity prices.
After taking into consideration the factor above, the remaining $26$65 million increase is primarily explained by the following significant business factors:by:
increased earnings of $17 million from Energy Services’ natural gas operations due to increased asset positions in core markets, which allowed for optimization of wider differentials in 2018; and
increased earnings of $6 million from Energy Services' Canadian and United States crude operations due•less pronounced market structure backwardation as compared to the wideningsame period of certain location2022;
•expiration of transportation commitments; and quality differentials in 2018, which increased opportunities to generate profitable margins.
•favorable margins realized on facilities where we hold capacity obligations and storage opportunities.
ELIMINATIONS AND OTHER
| | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | 2023 | 2022 |
| (millions of Canadian dollars) | | | | | |
| Earnings before interest, income taxes and depreciation and amortization | | | | 6 | | 355 | |
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | | |
| Loss before interest, income taxes and depreciation and amortization | (279 | ) | (298 | ) |
Eliminations and Other includes operating and administrative costs that are not allocated to business segments, and the impact of foreign exchange hedge settlements alland the activities of which are not allocated to business segments.our wholly-owned captive insurance subsidiaries. Eliminations and Other also includes the impact of new business development activities generaland corporate investments and a portion of the synergies achieved thus far related to the integration of corporate functions due to the Merger Transaction.investments.
Three months ended March 31, 2018,2023, compared with the three months ended March 31, 20172022
Loss before interest, income taxes and depreciation and amortization decreasedEBITDA was negatively impacted by $5$316 million due to certain unusual, infrequent and otheror non-operating factors, primarily explained by the following:by:
the absence of transaction costs in 2018 compared with $149 million of costs recorded in 2017 related to the Merger Transaction;
employee severance, transition and transformation costs of $62 million in 2018 compared with $125 million in 2017; partially offset by
•a non-cash, net unrealized loss of $136$83 million in 20182023, compared with a $72net gain of $309 million gain in 20172022, reflecting net fair value gains and losses arising from the changechanges in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk.risk; partially offset by
•the absence of a $44 million impairment of lease assets in 2022; and
•a net unrealized gain of $13 million in 2023, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries.
After taking into consideration the non-operating factors above, the remaining $14$33 million decrease is primarily explained by the following significant business factors:
alower realized loss of $42 million in 2018 compared with a loss of $72 million in 2017 related to settlements under our foreign exchange risk management program; partially offset bygains on hedge settlements in 2023.
two additional months of eliminations and other costs post-Merger Transaction, net of corporate synergies.
GROWTH PROJECTS –- COMMERCIALLY SECURED PROJECTS
The following table summarizes the status of our significant commercially secured projects, organized by business segment. Expenditures to date reflect total cumulative expenditures incurred from inception of the project to March 31, 2018.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. | Texas Eastern Venice Extension | 100 | % | US$391 million | US$69 million | Pre-construction | 2023 - 2024 |
| 2. | Texas Eastern Modernization | 100 | % | US$394 million | US$13 million | Pre-construction | 2024 - 2025 |
| 3. | T-North Expansion | 100 | % | $1.2 billion | $7 million | Pre-construction | 2026 |
| 4. | Woodfibre LNG3 | 30 | % | US$1.5 billion | US$153 million | Pre-construction | 2027 |
| 5. | T-South Expansion | 100 | % | $3.6 billion | $5 million | Pre-construction | 2028 |
| | | |
| | | | | | |
| RENEWABLE POWER GENERATION | | |
| 6. | Fécamp Offshore Wind4 | 17.9 | % | $692 million | $393 million | Under construction | 2023 |
| (€471 million) | (€269 million) |
| 7. | Calvados Offshore Wind5 | 21.7 | % | $954 million | $260 million | Under construction | 2025 |
| (€645 million) | (€180 million) |
|
| | | | | | |
| | | Enbridge's Ownership Interest | Estimated
Capital Cost1 | Expenditures
to Date2 | Status | Expected
In-Service
Date |
| (Canadian dollars, unless stated otherwise) | | | | |
| LIQUIDS PIPELINES | | | | | |
| 1. | Canadian Line 3 Replacement Program (the Fund Group)3 | 100% | $5.3 billion | $2.5 billion | Under construction | 2H - 2019 |
| 2. | U.S. Line 3 Replacement Program (EEP)4 | 100% | US$2.9 billion | US$0.8 billion | Pre-construction5 | 2H - 2019 |
| 3. | Other - United States6 | 100% | US$0.4 billion | US$0.4 billion | Substantially
complete | 2H - 2019 |
| 4. | Other - Canada | 100% | $0.1 billion | No significant
expenditures to date | Under construction | Q2 - 2018 |
| GAS TRANSMISSION AND MIDSTREAM | | | | |
| 5. | Atlantic Bridge (SEP) | 100% | US$0.5 billion | US$0.4 billion | Under construction | Q4 - 2018 |
| 6. | NEXUS (SEP)
| 50% | US$1.3 billion | US$0.7 billion | Under construction | Q3 - 2018 |
| 7. | Reliability and Maintainability Project | 100% | $0.5 billion | $0.4 billion | Under construction | Q3 - 2018 |
| 8. | Valley Crossing Pipeline | 100% | US$1.6 billion | US$1.4 billion | Under construction | Q4 - 2018 |
| 9. | Spruce Ridge Program | 100% | $0.5 billion | $0.1 billion | Pre-construction | 2H - 2019 |
| 10. | T-South Expansion Program | 100% | $1.0 billion | No significant expenditures to date | Pre-construction | 2H - 2020 |
| 11. | Other - United States7 | 100% | US$1.7 billion | US$0.9 billion | Various stages | 2018 - 2019 |
| 12. | Other - Canada8 | 100% | $0.6 billion | $0.6 billion | Complete | In service |
| GREEN POWER AND TRANSMISSION | | | | |
| 13. | Rampion Offshore Wind Project | 24.9% | $0.8 billion
(£0.37 billion) | $0.6 billion
(£0.3 billion) | Under construction | Q2 - 2018 |
| 14. | Hohe See Offshore Wind Project and Expansion | 50% | $2.1 billion
(€1.34 billion) | $0.8 billion
(€0.6 billion) | Under construction | 2H - 2019 |
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 reflect total cumulative expenditures incurred from inceptionand status of the project up toare determined as at March 31, 2018.2023.
3 The Fund GroupOur equity contribution is comprised of Enbridge Income Fund, Enbridge Commercial Trust, Enbridge Income Partners LP and the subsidiaries and investees of Enbridge Income Partners LP.
4 The United States portion of the Line 3 Replacement Program (U.S. L3R Program) is being funded 99% by Enbridge and 1% by EEP.
5 Construction of the Wisconsin portion of the project is mechanically complete as noted below. The remaining project is in pre-construction status.
6 Estimated in-service date will be adjusted to coincideUS$893 million, with the in-service date ofremainder financed through non-recourse project level debt.
4Our equity contribution is $103 million, with the U.S. L3R Program.remainder financed through non-recourse project level debt.
7 Includes5Our equity contribution is $181 million, with the US$0.2 billion Stampede Offshore oil lateral placed into service in the first quarter of 2018.remainder financed through non-recourse project level debt.
8 Includes the $0.4 billion High Pine and the $0.2 billion Wyndwood pipeline expansion, both placed into service in the first quarter of 2018.
A full description of each of our projects is provided in our Annual Reportannual report on Form 10-K as filed withfor the Securities and Exchange Commission on February 16, 2018. Significantyear ended December 31, 2022. No significant updates that have occurred since the date of filing are discussed below.of our Form 10-K.
48
LIQUIDS PIPELINES
United States Line 3 Replacement Program (EEP) - construction on the Wisconsin portion of the U.S. L3R Program commenced in late June 2017, was mechanically completed in February 2018 and is expected to be commissioned in May 2018. For additional updates on the project, refer to Growth Projects - Regulatory Matters.
GAS TRANSMISSION AND MIDSTREAM
Valley Crossing Pipeline - a natural gas pipeline connecting the Agua Dulce hub in Texas to an offshore tie-in with the Sur de Texas-Tuxpan project, which is being constructed by a third party. The project will help Mexico meet its growing gas fired electric generation needs by providing capacity of up to approximately 2.6 bcf/d. Based on an updated execution plan, the revised cost of the project is US$1.6 billion. This is roughly 12% above prior estimates and reflects scope changes, reroutes and offshore weather delays.
GREEN POWER AND TRANSMISSION
Rampion Offshore Wind Project - the project generated first power in November 2017. All remaining turbines were commissioned in March 2018 and full operating capacity is expected to be reached in the second quarter of 2018.
GROWTH PROJECTS - REGULATORY MATTERS
United States Line 3 Replacement Program (EEP)
EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate of Need and an approval of the pipeline’s route (Route Permit) from the Minnesota Public Utilities Commission (MNPUC). On February 1, 2016, the MNPUC issued a written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental Impact Statement (EIS) before the Certificate of Need and Route Permit processes commence. The DOC issued the final EIS on August 17, 2017. The MNPUC determined the final EIS to be inadequate in four specific areas on December 7, 2017, which the MNPUC directed the DOC to address. As a result, the DOC provided a supplemental EIS on February 12, 2018 and the MNPUC deemed it adequate on March 15, 2018. Progress continues with the parallel Certificate and Route Permit dockets, with public and evidentiary hearings now complete.
On April 23, 2018, an Administrative Law Judge (ALJ) issued Findings of Fact, Conclusions of Law and Recommendation (the ALJ Report) to the MNPUC in connection with EEP's application for a Certificate and Route Permit. The ALJ recommended that the MNPUC grant EEP's application for a Certificate, but only if the MNPUC also selects a route that would require in-trench replacement of the existing Line 3, which is not EEP's preferred route. The ALJ Report is not binding on the MNPUC and the MNPUC is expected to issue a ruling in the Certificate and Route Permit dockets late in the second quarter of 2018. EEP believes that its preferred route remains the best solution for Minnesota and EEP intends to continue its efforts to secure MNPUC approval for its preferred route. On May 9, 2018, EEP filed its exceptions to the ALJ Report with the MNPUC, in which EEP set out its proposed revisions to the ALJ’s summary of the evidentiary record, as well as EEP's points of disagreement with her conclusions and route recommendation.
OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT
The following projects have been announced by us, but have not yet met our criteria to be classified as commercially secured:
LIQUIDS PIPELINES
Gray Oak Pipeline Project - the Gray Oak Pipeline, LLC announced on April 24, 2018, that it has received sufficient binding commitments on an initial open season to proceed with construction of the Gray Oak Pipeline system. The Gray Oak Pipeline will provide crude oil transportation from West Texas to destinations in the Corpus Christi and Sweeny/Freeport markets. The pipeline is expected to be placed in service by the end of 2019. A second open season has been launched to secure additional volume commitments, which if fully subscribed, the pipeline could have an ultimate capacity of approximately one million barrels per day. We have secured an option to acquire an interest in the pipeline.
GAS TRANSMISSION AND MIDSTREAM
Alliance Pipeline Expansion Project -on March 28, 2018, Alliance Pipeline announced an open season for binding bids for additional long-term firm transportation service contracts on the Alliance Pipeline Canada and Alliance Pipeline US systems in support of up to 400 million cubic feet per day (mmcf/d) of expanded services on Alliance Pipeline Canada and up to 430 mmcf/d of expanded services on Alliance Pipeline US. The open season closes on May 30, 2018. The projected in-service date for the potential expansion is the fourth quarter of 2021.
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 $881 million, which are expected to be paid over the next four 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, including utilizationalternatives. Our current financing plan does not include any issuances of our sponsored vehicles.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 March 31, 2018.2023:
| | | | | | | | | | | | | | |
| Maturity1 | Total
Facilities | Draws2 | Available |
| (millions of Canadian dollars) | | | | |
| Enbridge Inc. | 2023-2027 | 9,623 | | 7,053 | | 2,570 | |
| Enbridge (U.S.) Inc. | 2024-2027 | 8,594 | | 1,702 | | 6,892 | |
| Enbridge Pipelines Inc. | 2024 | 2,000 | | 876 | | 1,124 | |
| Enbridge Gas Inc. | 2024 | 2,500 | | 1,440 | | 1,060 | |
| Total committed credit facilities | | 22,717 | | 11,071 | | 11,646 | |
|
| | | | | | | |
| | | March 31, 2018 |
| | Maturity Dates | Total Facilities |
| Draws1 |
| Available |
|
| (millions of Canadian dollars) | | | | |
Enbridge Inc.2 | 2019-2022 | 6,644 |
| 2,616 |
| 4,028 |
|
| Enbridge (U.S.) Inc. | 2019 | 2,469 |
| 1,142 |
| 1,327 |
|
Enbridge Energy Partners, L.P.3 | 2019-2022 | 3,385 |
| 1,660 |
| 1,725 |
|
| Enbridge Gas Distribution Inc. | 2019 | 1,017 |
| 884 |
| 133 |
|
| Enbridge Income Fund | 2020 | 1,500 |
| 566 |
| 934 |
|
| Enbridge Pipelines Inc. | 2019 | 3,000 |
| 1,730 |
| 1,270 |
|
Spectra Energy Partners, LP4 | 2022 | 3,223 |
| 2,135 |
| 1,088 |
|
| Union Gas Limited | 2021 | 700 |
| 130 |
| 570 |
|
| Total committed credit facilities | | 21,938 |
| 10,863 |
| 11,075 |
|
| |
1 | Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
|
| |
2 | Includes $135 million, $161 million (US$125 million) and$150 million of commitments that expire in 2018, 2018 and 2020, respectively.
|
| |
3 | Includes $226 million (US$175 million) and $239 million (US$185 million) of commitments that expire in 2018 and 2020, respectively.
|
| |
4 | Includes $434 million (US$336 million) of commitments that expire in 2021.
|
2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
During the first quarter of 2018,
In March 2023, Enbridge terminated a US$650 millionGas increased its 364-day extendible credit facility which was setfrom $2.0 billion to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilizedUS$950 million credit facility, which was set to mature in 2019. $2.5 billion.
During the first quarter of 2018, Westcoast Energy Inc. terminated an unutilized $400 million credit facility with a syndicate of banks. The facility was set to mature in 2021.
In addition to the committed credit facilities noted above, we have $790 millionmaintain $1.3 billion of uncommitted demand letter of credit facilities, of which $511$720 million werewas unutilized as at March 31, 2018.2023. As at December 31, 2017,2022, we had $792 million$1.3 billion of uncommitted demand letter of credit facilities, of which $518$689 million werewas unutilized.
As at March 31, 2023, our net available liquidity totaled $12.6 billion (December 31, 2022 - $10.0 billion), consisting of $11,685 million as at Marchavailable credit facilities of $11.6 billion (December 31, 2018,2022 - $9.1 billion) and was inclusive of $610 million of unrestricted cash and cash equivalents of $976 million (December 31, 2022 - $861 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 wereare to default on payment or violate certain covenants. As at March 31, 2018,2023, we were in compliance with all debt covenants and expects to continue to comply with such covenants.covenant provisions.
LONG-TERM DEBT ISSUANCES
During the first quarter of 2018,three months ended March 31, 2023, we completed the following long-term debt issuances:
issuances totaling US$3.0 billion: | | | | | | | | | | | | | | |
| Company | Issue Date | | | Principal Amount |
| (millions of Canadian dollars, unless otherwise stated) | |
| Enbridge Inc. | | | |
| March 2023 | 5.70% | sustainability-linked senior notes due March 20331 | US$2,300 |
| March 2023 | 5.97% | senior notes due March 20262 | US$700 |
| | | | |
| | | | |
Company | Issue Date | | | Principal Amount |
(millions of dollars) | | | | |
Enbridge Inc. | | | |
| March 2018 | Fixed-to-floating rate notes due 20781
| US$850 | |
Spectra Energy Partners, LP2
| | | | |
| January 2018 | 3.50% senior notes due 2028 | US$400 |
| January 2018 | 4.15% senior notes due 2048 | US$400 | |
| | | | |
| |
1 | Notes mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.25%. Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 364 basis points from years 10 to 30, and a margin of 439 basis points from years 30 to 60. |
| | |
2 | Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP. |
On April 12,1The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 we completedlevels at an offeringobservation date of $750 million of fixed-to-floating rate subordinated notes that mature in 60 years and are callableDecember 31, 2030. If the target is not met, on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.625%. After the initial 10 years,September 8, 2031, the interest rate will be set to equal the Canadian Dollar Offered Rate5.70% plus a margin of 43250 basis points from years 10points.
2We have the option to 30, and a margin of 507 basis points from years 30 to 60.
On April 12, 2018, we completed an offering of US$600 million of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 5. For the initial 5 years,call the notes carry a fixed interest rate of 6.375%. After the initial 5 years, the interest rate will be set at par after one year from issuance. Refer to equal the three-month LIBOR plus a margin of 359 basis points from years 5 to 10, a margin of 384 basis points from years 10 to 25,Part I. Item 1. Financial Statements - Note 7 - Risk Management and a margin of 459 basis points from years 25 to 60.Financial Instruments.
LONG-TERM DEBT REPAYMENTS
During the first quarter of 2018,three months ended March 31, 2023, we completed the following long-term debt repayments totaling US$513 million and $275 million:
| | | | | | | | | | | | | | |
| Company | Repayment Date | | | Principal Amount |
| (millions of Canadian dollars, unless otherwise stated) | |
| Enbridge Inc. | | | |
| January 2023 | 3.94 | % | medium-term notes | $275 |
| February 2023 | Floating rate notes1 | US$500 |
| | | | |
| |
| | | | |
| | | |
| | | | |
| |
| | | | |
| | | |
| | | | |
| |
| | | | |
| Tri Global Energy, LLC |
| January 2023 | 10.00 | % | senior notes | US$4 |
| January 2023 | 14.00 | % | senior notes | US$9 |
1The notes carried an interest rate set to further simplify our debt financing structure post-merger:equal the Secured Overnight Financing Rate plus a margin of 40 basis points.
|
| | | | | | |
Company | Retirement/Repayment Date | | | Principal Amount |
| Cash Consideration |
(millions of Canadian dollars unless otherwise stated) | | | |
Enbridge Southern Lights LP
| | | | |
| January 2018 | 4.01% medium-term notes due June 2040 | 9 |
| |
Spectra Energy Capital, LLC1
| | | | |
Repurchase via Tender Offer | | | | |
| March 2018 | 6.75% senior unsecured notes due 2032 | US$64 | US$80 |
| March 2018 | 7.50% senior unsecured notes due 2038 | US$43 | US$59 |
Redemption | | | |
| March 2018 | 5.65% senior unsecured notes due 2020 | US$163 | US$172 |
| March 2018 | 3.30% senior unsecured notes due 2023 | US$498 | US$508 |
On the April 15, 2023 call date, we redeemed at par all of the outstanding US$600 million five-year callable, 6.38% fixed-to-floating rate subordinated notes that carried an original maturity date of April 2078. | |
1 | The loss on debt extinguishment of $37 million (US$29 million), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.
|
Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model supporthave 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 help ensure 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 total capital. As at March 31, 2018, our debt capitalization ratio was 48.2%, compared with 48.3% as at December 31, 2017.EBITDA.
There are no material restrictions on our cash. Total restricted cash of $113$75 million, as reported on the Consolidated Statements of Financial Position, primarily includes EGD’s and Union Gas’ receipt of cash from the Government of Ontario to fund its Green Investment Fund program. In addition, our restricted cash includesreinsurance security, cash collateral, future pipeline abandonment costs collected and held in trust, amounts received in respect of specific shipper commitments.commitments and capital projects. Cash and cash equivalents held by EEP, the Fund Group and SEP are generally not readily accessible by us until distributions are declared and paid by these entities, which occurs quarterly for EEP and SEP, and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative uses by us.
Excluding current maturities of long-term debt, we had a negative working capital position as at March 31, 2018. The2023 and December 31, 2022, we had positive and negative working capital positions of $576 million and $2.1 billion, respectively. During the three months ended March 31, 2023, the major contributing factor to the positive working capital position was due to settlement of current liabilities, while during the year ended December 31, 2022, the negative working capital position was the ongoing funding ofdue to current liabilities associated with our growth capital program.
To address this negative working capital position, we 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. As at March 31, 2018 and December 31, 2017, our net available liquidity totaled $11,685 million and $12,959 million, respectively.
SOURCES AND USES OF CASH
|
| | | | |
| | Three months ended
March 31, |
| | 2018 |
| 2017 |
|
| (millions of Canadian dollars) | |
| |
|
| Operating activities | 3,194 |
| 1,776 |
|
| Investing activities | (2,068 | ) | (3,448 | ) |
| Financing activities | (1,009 | ) | 1,313 |
|
| Effect of translation of foreign denominated cash and cash equivalents and restricted cash | 19 |
| (9 | ) |
| Increase/(decrease) in cash and cash equivalents and restricted cash | 136 |
| (368 | ) |
| | | | | | | | | | | |
| | | Three months ended
March 31, |
| | | | | 2023 | 2022 |
| (millions of Canadian dollars) | | | | | |
| Operating activities | | | | 3,866 | | 2,939 | |
| Investing activities | | | | (1,437) | | (1,318) | |
| Financing activities | | | | (2,289) | | (1,483) | |
| Effect of translation of foreign denominated cash and cash equivalents and restricted cash | | | | 4 | | (4) | |
| Net change in cash and cash equivalents and restricted cash | | | | 144 | | 134 | |
Significant sources and uses of cash for the three months ended March 31, 20182023 and March 31, 20172022 are summarized below:
Operating Activities
The growth inTypically, the primary factors impacting cash flow delivered by operationsfrom operating activities period-over-period include changes in the first quarter of 2018 is a reflection of the positive operating factors discussed under Results of Operations. The increase in operating cash flow was driven mainly from the contributions from new assets and distributions from additional long-term investments following the completion of the Merger Transaction.
Changes inour operating assets and liabilities included within operating activities were $622 million and $340 million for the three months ended March 31, 2018 and 2017, respectively. Our operating assets and liabilities fluctuate in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within the Energy Services and Gas Distributionour 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 in Results of Operations.
Investing Activities
The quarter-over-quarter decrease of cashCash used in investing activities was primarily attributablerelates to activity in the first quarter of 2017 that was not present in the first quarter of 2018, related primarilycapital expenditures to the acquisition of an interest in the Bakken Pipeline System of $2.0 billion (US $1.5 billion), partially offset by cash acquired in the Merger Transaction of $0.7 billion and cash received from asset dispositions of $0.3 billion.
We are continuing with the execution ofexecute our growth capital program, which is further described in Growth Projects - Commercially Secured Projects.The timing of project approval,approval, construction and in-service dates impacts the timing of cash requirements.
The increase in cash used in investing activities period-over-period was also due to the acquisition of an additional 10.0% ownership in the Gray Oak Pipeline, partially offset by net receipts of long-term notes receivable from affiliates, in the first quarter of 2023.
Financing Activities
The quarter-over-quarter decreaseCash 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 provided byused in financing activities wasperiod-over-period primarily attributableinclude:
•higher net commercial paper and credit facility repayments in 2023 when compared to the same period in 2022;
•net repayments of maturing term notesshort-term borrowings in 2023 when compared to net issuances during the same period in 2022; and credit facilities. During the three months ended March 31, 2018, we issued hybrid securities, the proceeds of which were used to repay maturing term notes and credit facilities and to finance growth capital programs. Proceeds from the hybrid securities were primarily used to repay credit facilities and to repurchase or redeem Spectra Energy Capital, LLC’s outstanding senior unsecured notes as discussed in Liquidity and Capital Resources - Long-Term Debt Repayments.
Finally, with the exception of dividends paid to Spectra Energy shareholders that were declared prior to the Merger Transaction, our •common share dividend payments increased in the first quarter of 2018,period-over-period primarily due to the increase in theour common share dividend raterate.
The factors above were partially offset by:
•higher long-term debt issuances in 2023 when compared to the second and fourth quarters of 2017,same period in 2022, as well as an increaselower repayments of long-term debt made during the first quarter of 2023; and
•the absence in 2023 of the redemption of Preference Shares, Series 17 and the repurchase and cancellation of 950,024 common shares under our NCIB for approximately $50 million in the numberfirst quarter of common shares2022.
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 asseries 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 common shares issuedthe guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in connectionthe same position with the Merger Transaction.
Dividend Reinvestment and Share Purchase Plan
Participants in our Dividend Reinvestment and Share Purchase Plan (DRIP) receive a 2% discount on the purchase of common shares with reinvested dividends. For the three months ended March 31, 2018 and 2017, total dividends paid were $1,138 million and $548 million, respectively, of which $764 million and $354 million, respectively, were paid in cash and reflected in financing activities. The remaining $374 million and $194 million, respectively, of dividends paid were reinvested pursuantrespect to the DRIPnet assets, income and resulted incash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the issuancePartnerships, Enbridge subsidiaries (including the subsidiaries of common shares rather than a cash payment. In addition to amounts paid in cash and reflected in financing activities for the three months ended March 31, 2017, were $414 million in dividends declared to Spectra Energy shareholders priorPartnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the Merger Transaction that were paid after the Merger Transaction. For the three months ended March 31, 2018subsidiary guarantee agreement and 2017, 32.9%have not otherwise guaranteed any of Enbridge's outstanding series of senior notes.
Consenting SEP notes and 35.4%, respectively, of total dividends paid were reinvested through the DRIP.
Our Board of Directors has declared the following quarterly dividends. All dividends are payable on June 1, 2018, to shareholders of record on May 15, 2018.
EEP notes under Guarantee |
| | | | |
Common SharesSEP Notes1 |
| $0.67100 |
EEP Notes2 |
Preference Shares, Series A4.750% Senior Notes due 2024 |
| $0.34375 |
5.875% Notes due 2025 |
Preference Shares, Series B3.500% Senior Notes due 2025 |
| $0.21340 |
5.950% Notes due 2033 |
Preference Shares, Series C1
3.375% Senior Notes due 2026 |
| $0.22685 |
6.300% Notes due 2034 |
Preference Shares, Series D2
5.950% Senior Notes due 2043 |
| $0.27875 |
7.500% Notes due 2038 |
Preference Shares, Series F4.500% Senior Notes due 2045 |
| $0.25000 |
5.500% Notes due 2040 |
Preference Shares, Series H |
| $0.25000 |
|
Preference Shares, Series J | US$0.30540 |
|
Preference Shares, Series L | US$0.30993 |
|
Preference Shares, Series N |
| $0.25000 |
|
Preference Shares, Series P |
| $0.25000 |
|
Preference Shares, Series R |
| $0.25000 |
|
Preference Shares, Series 1 | US$0.25000 |
|
Preference Shares, Series 3 |
| $0.25000 |
|
Preference Shares, Series 5 | US$0.27500 |
|
Preference Shares, Series 7 |
| $0.27500 |
|
Preference Shares, Series 9 |
| $0.27500 |
|
Preference Shares, Series 11 |
| $0.27500 |
|
Preference Shares, Series 13 |
| $0.27500 |
|
Preference Shares, Series 15 |
| $0.27500 |
|
Preference Shares, Series 17 |
| $0.32188 |
|
Preference Shares, Series 193
|
| $0.30625 |
|
1As at March 31, 2023, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.
2As at March 31, 2023, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.
Enbridge Notes under Guarantees
| | | | | |
USD Denominated1 | The quarterly dividend amountsCAD Denominated2
|
| Floating Rate Senior Notes due 2024 | 3.940% Senior Notes due 2023 |
| 4.000% Senior Notes due 2023 | 3.950% Senior Notes due 2024 |
| 0.550% Senior Notes due 2023 | 2.440% Senior Notes due 2025 |
| 3.500% Senior Notes due 2024 | 3.200% Senior Notes due 2027 |
| 2.150% Senior Notes due 2024 | 5.700% 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 |
| 5.969% Senior Notes due 2026 | 6.100% Sustainability-Linked 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 |
| 5.700% Sustainability-Linked Senior Notes due 2033 | 5.120% Senior Notes due 2040 |
| 4.500% Senior Notes due 2044 | 4.240% Senior Notes due 2042 |
| 5.500% Senior Notes due 2046 | 4.570% Senior Notes due 2044 |
| 4.000% Senior Notes due 2049 | 4.870% Senior Notes due 2044 |
| 3.400% Senior Notes due 2051 | 4.100% Senior Notes due 2051 |
| 6.510% Senior Notes due 2052 |
| 4.560% Senior Notes due 2064 |
1As at March 31, 2023, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$13.5 billion.
2As at March 31, 2023, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $9.9 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
| | | | | |
| Three months ended March 31, | 2023 |
(millions of Series C was increased to $0.22685 from $0.20342 on March 1, 2018, due to reset on a quarterly basis.Canadian dollars) | |
| |
2Operating income | The quarterly dividend amounts of Series D was increased to $0.27875 from $0.25000 on March 1 2018, due to reset of the annual dividend on March 1, 2018, and every five years thereafter.
|
| |
3Earnings | The Series 19 increase from $0.26850499
| |
Earnings attributable to the regular quarterly dividend of $0.30625 will take effect on June 1, 2018.common shareholders | 414 | |
Summarized Combined Statements of Financial Position
| | | | | | | | | | | |
| | March 31,
2023 | | December 31,
2022 | |
| (millions of Canadian dollars) | | | | | |
| Cash and cash equivalents | | 532 | | | 425 | |
| Accounts receivable from affiliates | | 2,053 | | | 2,486 | | |
| Short-term loans receivable from affiliates | | 4,232 | | | 5,232 | | |
| Other current assets | | 706 | | | 969 | | |
| Long-term loans receivable from affiliates | | 45,885 | | | 43,873 | | |
| Other long-term assets | | 3,657 | | | 4,111 | | |
| Accounts payable to affiliates | | 1,943 | | | 1,375 | | |
| Short-term loans payable to affiliates | | 1,261 | | | 1,745 | | |
| Other current liabilities | | 7,354 | | | 8,752 | | |
| Long-term loans payable to affiliates | | 37,943 | | | 37,626 | | |
| Other long-term liabilities | | 48,213 | | | 47,447 | | |
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 PIPELINESMichigan Line 5 Dual Pipelines - Straits of Mackinac Easement
Eddystone Rail Legal Matter
In February 2017, Eddystone Rail Company, LLC (Eddystone Rail)2019, the Michigan Attorney General (AG) filed an action against several defendantsa complaint in the United StatesMichigan 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 forin the EasternWestern District of Pennsylvania. Eddystone Rail allegesMichigan (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 defendants transferred valuable assets from Eddystone Rail’s counterpartysimilar (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 maritime contract, so asrequest to avoid outstanding obligationsfile a remand motion and on December 28, 2021, we responded to Eddystone Rail. Eddystone Rail is seeking payment of compensatoryher 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 motion was fully briefed in March 2022. On August 18, 2022, Judge Neff denied the AG’s motion to remand and punitive damages in excess of US$140 million. On July 19, 2017,on August 30, 2022, the defendants’ motions to dismiss Eddystone Rail’s claims were denied. Defendants have filed Answers and Counterclaims, which together with subsequent amendments, seek damages from Eddystone Rail in excess of US$32 million. EddystoneAG filed a motion to dismisscertify the counterclaimsAugust 18 Order, in order to pursue an appeal on the jurisdictional issue and defendants amended their Answer and Counterclaims on September 21, 2017. On October 12, 2017 Eddystone Rail moved to dismiss the latest version of defendants’ counterclaims.Enbridge opposed that motion. On February 6, 2018,21, 2023, the Court denied without prejudice Eddystone Rail'sgranted the AG’s motion to dismisscertify the defendants' counterclaims. The defendants’ chances of success on their counterclaims cannot be predicted at this time.
GAS TRANSMISSION AND MIDSTREAM
Sabal Trail FERC Certificate Review
Sierra Club and two other non-governmental organizationsAugust 18, 2022 Order. On March 2, 2023, the AG filed aher Petition for Review of Sabal Trail’s FERC certificate on September 20, 2016Permission to Appeal in the D.C.6th Circuit Court of Appeals. Enbridge’s Response was filed on March 13, 2023. We anticipate a response from the 6th Circuit Court of Appeals within the next few months. In the meantime, this case will remain on hold in US District Court. If the Court of Appeals hears the appeal, it will likely take 12-18 months for briefing a decision.
On August 22, 2017,May 21, 2021, the D.C. Circuit issuedDistrict Court dismissed the plaintiff Tribes’ request for an opinion denying oneinjunction enjoining Dakota Access Pipeline (DAPL) from operating until the Army Corps has completed its Environmental Impact Statement (EIS). The right of the petitions,plaintiff Tribes to appeal the denial of the injunction request expired on July 20, 2021. The Army Corps earlier indicated that it did not intend, at that time, to exercise its authority to bar DAPL’s continued operation, notwithstanding the absence of an easement and grantingthat it anticipates completion of the other petitionEIS process.
On July 22, 2021, the Army Corps filed a notice with the District Court advising that the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a notice asserting violations of federal safety regulations resulting from the operation of DAPL. The Army Corps stated that it would consider PHMSA’s notice as part of its ongoing consideration of whether and how the Army Corps will enforce its rights on property crossed by the pipeline and in part, vacating the certificates, and remandingcontext of the caseongoing EIS. The Army Corps also granted the request from the Tribes to FERCextend the draft EIS completion date to supplementSeptember 2022. The Army Corps now expects to complete the environmental impactdraft EIS in the spring of 2023.
statement for the project to estimate the quantity of green-house gases to be released into the environment by the gas-fired generation plants in Florida that will consume the gas transported by Sabal Trail. The court withheld issuance of the mandate requiring vacatur of the certificate until seven days after the disposition of any timely petition for rehearing. On October 6, 2017, Sabal Trail and FERC each filed timely petitions for rehearing. On January 31, 2018, the court denied FERC’s and Sabal Trail’s petitions for rehearing. On February 5, 2018, FERC issued its final supplemental environmental impact statement in compliance with the D.C. Circuit decision. In addition, on February 6, 2018, FERC filed a motion with the court requesting a 45-day stay of the mandate. On March 7, 2018, the Court granted FERC’s 45-day request for stay, and directed that issuance of the mandate be withheld through March 26, 2018. On March 14, 2018 FERC issued its Order on Remand Reinstating Certificate and Abandonment Authorizations which addressed the Court’s ruling in the August 22, 2017 decision, and on March 30, 2018 the Court issued its mandate.
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 by special interest groups.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.
CAPITAL EXPENDITURE COMMITMENTS
We have signed contracts for the purchase of services, pipe and other materials totaling $2,265 million which are expected to be paid over the next five years.
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
ADOPTION OF NEW STANDARDS
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2018-02 to address a specific consequence of theTCJAenacted by the United States federal government on December 22, 2017. The amendments in this accounting update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. The amendments will eliminate the stranded tax effects as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements.
Clarifying Guidance on the Application of Modification Accounting on Stock Compensation
Effective January 1, 2018, we adopted ASU 2017-09 and applied the standard on a prospective basis. The new standard was issued to clarify the scope of modification accounting. Under the new guidance, modification accounting is required for all changes to share based payment awards, unless all of the following conditions are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The adoption of this accounting update is not expected to have a material impact on our consolidated financial statements.
Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans
Effective January 1, 2018, we adopted ASU 2017-07 which was issued primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. Upon adoption of this accounting update, our consolidated statement of earnings presents the current service cost within Operating and administrative expenses and the other components of net benefit cost within Other income/(expense). Previously, all components of net benefit cost were presented within Operating and administrative expenses. In addition, only the service cost component of net benefit cost will be capitalized on a prospective basis. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements.
Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets
Effective January 1, 2018, we adopted ASU 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our consolidated financial statements.
Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows
Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents.
Simplifying Cash Flow Classification
Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements.
Recognition and Measurement of Financial Assets and Liabilities
Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial instruments for disclosure purposes is measured using exit price. The adoption of this accounting update did not have a material impact on our consolidated financial statements.
Revenue from Contracts with Customers
Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the
use of more estimates and judgments than the previous standards of the consolidated financial statements.
In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied obligations.
The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item along with explanations of those effects. For the three months ended March 31, 2018, the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material.
|
| | | | | | |
| | Balance at December 31, 2017 | Adjustments Due to ASC 606 | Balance at January 1, 2018 |
| (millions of Canadian dollars) | | | |
| Assets | | | |
Deferred amounts and other assets1,2 | 6,442 |
| (170 | ) | 6,272 |
|
Property, plant and equipment, net2 | 90,711 |
| 112 |
| 90,823 |
|
| Liabilities and equity | | | |
Accounts payable and other1,2 | 9,478 |
| 62 |
| 9,540 |
|
Other long-term liabilities2 | 7,510 |
| 66 |
| 7,576 |
|
Deferred income taxes1,2 | 9,295 |
| (62 | ) | 9,233 |
|
Redeemable noncontrolling interests1,2 | 4,067 |
| (38 | ) | 4,029 |
|
Deficit1,2 | (2,468 | ) | (86 | ) | (2,554 | ) |
| |
1 | Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract.
|
| |
2 | Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment.
|
FUTURE ACCOUNTING POLICY CHANGES
Improvements to Accounting for Hedging Activities
ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.
Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective
January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.
Recognition of Leases
ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are currently gathering a complete inventory of our lease contracts in order to assess the impact of the new standard on our consolidated financial statements. We will adopt the new standard on January 1, 2019 and we are currently evaluating options with respect to the transition practical expedients offered in connection with this update.
Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our exposure to market risk is described in Part II. Item 7A7A.Quantitative and Qualitative Disclosures About Market Risk of our Annual Reportannual report on Form 10-K for the fiscal year ended December 31, 2017, filed with the SEC on February 16, 2018.2022. We believe our exposure to market risk has not changed materially since then.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported within the time periods specified by the SEC’sSEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as ofat March 31, 2018,2023, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submitssubmit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.
Changes in Internal Control over Financial Reporting
Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended March 31, 20182023 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are involved in various legal and regulatory actions and proceedings which arise in the ordinary course of business. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations. Refer to Part I. Item 2. 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updatesfor discussion of other legal proceedings.
SEC regulations require the disclosure of any proceeding under environmental laws to which a governmental authority is a party unless the registrant reasonably believes it will not result in monetary sanctions over a certain threshold. Given the size of our operations, we have elected to use a threshold of US$1 million for the purposes of determining proceedings requiring disclosure.
ITEM 1A. RISK FACTORS
In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. 1A. Risk Factors in of our Annual Reportannual report on Form 10-K for the year ended December 31, 2017,2022, which could materially affect our financial condition or future results. Other than as set out below, thereThere have been no material modifications to those risk factors.
Our operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.
Many of our operations are regulated. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States have changed significantly in past years and further substantial changes may occur.
On February 8, 2018, the Government of Canada introduced legislation to revise the process for assessing major resource projects. If the legislation is passed in its current form, we believe it would have adverse impacts on pipeline companies, particularly in relation to the regulatory review process for proposed new projects that are “designated projects”, by making overall timelines for the development and execution of these projects longer and significantly increasing uncertainty.
Compliance with legislative changes may impose additional costs on new pipeline projects as well as on existing operations. Failure to comply with applicable regulations could result in a number of consequences which may have an adverse effect on our operations, earnings, financial condition and cash flows.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.ISSUER PURCHASES OF EQUITY SECURITIES
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| Period | Total number of shares purchased | Average price paid per share | Total number of shares purchased as part of publicly announced plans or programs | Maximum number of shares that may yet be purchased under the plans or programs1 |
January 2023 (January 1 - January 31) | — | | N/A | — | | 27,938,163 | |
February 2023 (February 1 - February 28) | — | | N/A | — | | 27,938,163 | |
March 2023 (March 1 - March 31) | — | | N/A | — | | 27,938,163 | |
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1On January 4, 2023, the Toronto Stock Exchange (TSX) approved our NCIB to purchase, for cancellation, up to 27,938,163 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion. Purchases under the NCIB may be made through the facilities of the TSX, the New York Stock Exchange and other designated exchanges and alternative trading systems. Our NCIB commenced on January 6, 2023 and continues until January 5, 2024, when it expires, or such earlier date on which we have either acquired the maximum number of common shares allowable or otherwise decide not to make further repurchases.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
Each exhibit identified below is included as a part of this quarterly report. Exhibits included in this filing are designated by an asterisk (“("*”"); all exhibits not so designated are incorporated by reference to a prior filing as indicated. Exhibits designated with a “+”"+" constitute a management contract or compensatory plan arrangement.
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| Exhibit No. | | Description |
2.1 | + | |
| + | |
3.1 | | |
3.2 | | |
3.3 | | |
4.1 | | |
4.2 | | |
| | Certain instruments defining the rights of holders of long-term debt securities of the Registrant and its subsidiaries are omitted pursuant to Item 601(b)(4)(iii) of Regulation S-K. The Registrant hereby undertakes to furnish to the SEC, upon request, copies of any such instruments. |
10.1*+ | | |
10.2*+ | | |
10.3*+ | | |
31.1* | | |
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101.INS* 101.SCH* | | XBRL Instance Document. |
101.SCH* | | Inline XBRL Taxonomy Extension Schema Document. |
| 101.CAL* | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. |
| 101.DEF* | | Inline XBRL Taxonomy Extension Definition Linkbase Document. |
| 101.LAB* | | Inline XBRL Taxonomy Extension Label Linkbase Document. |
| 101.PRE* | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. |
| 104 | | Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101) |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | | | | | | |
| | ENBRIDGE INC. |
| | (Registrant) |
| | | |
| Date: | May 5, 2023 | ENBRIDGE INC.By: | /s/ Gregory L. Ebel |
| | (Registrant) |
| | |
Date: | May 10, 2018 | By: | /s/ Al Monaco |
| | Al MonacoGregory L. Ebel
President, and Chief Executive Officer and Director (Principal Executive Officer) |
| | | |
| Date: | May 10, 20185, 2023 | By: | /s/ John K. WhelenVern D. Yu |
| | | John K. Whelen
Vern D. Yu Executive Vice President, and Corporate Development, Chief Financial Officer
and President, New Energy Technologies (Principal Financial Officer) |
