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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM | 10-Q

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

For the quarterly period ended March 31, 2021
OR

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

For the transition period from to
Commission file number 1-10934

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

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

200, 425 - 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
(Address of Principal Executive Offices) (Zip Code)
(403) 231-3900
(Registrant’s Telephone Number, Including Area Code)
_______________________________
Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Trading Symbol(s) |  | Name of each exchange on which registered
Common Shares |  | ENB |  | New York Stock Exchange
6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078 |  | ENBA |  | New York Stock Exchange

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. Yes x No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | x |  | Accelerated filer | ☐
Non-accelerated filer | ☐ |  | Smaller reporting company | ☐
Emerging growth company | ☐ |  |  |

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x
The registrant had 2,025,576,385 common shares outstanding as at April 30, 2021.

1

|  | Page
| PART I |
Item 1. | Financial Statements | 6
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 33
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 51
Item 4. | Controls and Procedures | 51
| PART II |
Item 1. | Legal Proceedings | 52
Item 1A. | Risk Factors | 52
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 52
Item 3. | Defaults Upon Senior Securities | 52
Item 4. | Mine Safety Disclosures | 52
Item 5. | Other Information | 52
Item 6. | Exhibits | 53
| Signatures | 54

2

GLOSSARY

AOCI | Accumulated other comprehensive income/(loss)
Army Corps | United States Army Corps of Engineers
ASU | Accounting Standards Update
CPP Investments | Canada Pension Plan Investment Board
DAPL | Dakota Access Pipeline
DCP Midstream | DCP Midstream, LLC
EBITDA | Earnings before interest, income taxes and depreciation and amortization
EEP | Enbridge Energy Partners, L.P.
EIS | Environmental Impact Statement
EMF | Éolien Maritime France SAS
Enbridge | Enbridge Inc.
Exchange Act | United States Securities Exchange Act of 1934, as amended
LNG | Liquified natural gas
NGL | Natural gas liquids
SEC | US Securities and Exchange Commission
SEP | Spectra Energy Partners, LP
the Straits | Straits of Mackinac
OCI | Other comprehensive income/(loss)
OPEB | Other postretirement benefit obligations
Texas Eastern | Texas Eastern Transmission, LP

3

CONVENTIONS
The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge.
Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to “dollars”, “$” or “C$” are to Canadian dollars and all references to “US$” are to United States (US) dollars. All amounts are provided on a before tax basis, unless otherwise stated.
FORWARD-LOOKING INFORMATION
Forward-looking information, or forward-looking statements, have been included in this quarterly report on Form 10-Q to provide information about us and our subsidiaries and affiliates, including management’s assessment of our and our subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: our corporate vision and strategy, including strategic priorities and enablers; the COVID-19 pandemic and the duration and impact thereof; energy intensity and emissions reduction targets and related environment, social and governance matters; diversity and inclusion goals; expected supply of, demand for and prices of crude oil, natural gas, natural gas liquids (NGL), liquified natural gas (LNG) and renewable energy; energy transition; anticipated utilization of our existing assets; expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected future cash flows and distributable cash flow; dividend growth and payout policy; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected strategic priorities and performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation and Energy Services businesses; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction and for maintenance; expected capital expenditures, investment capacity and capital allocation priorities; 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 and the timing thereof; expected benefits of transactions, including the realization of efficiencies, synergies and cost savings; expected future actions of regulators and courts; toll and rate cases discussions and filings, including Mainline System contracting; anticipated competition; US Line 3 Replacement Program (US L3R Program), including anticipated in-service dates and capital costs; and Line 5 dual pipelines and related litigation and other matters.
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 COVID-19 pandemic and the duration and impact thereof; the expected supply of and demand for crude oil, natural gas, NGL and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; anticipated utilization of assets; 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 timing and closing of acquisitions and dispositions; the realization of anticipated benefits and synergies of transactions; governmental legislation; litigation; estimated future dividends and impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; hedging program; expected EBITDA; expected earnings/(loss); expected future cash flows; and expected distributable cash flow. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL 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 and the COVID-19 pandemic 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 expected EBITDA, expected
4

earnings/(loss), expected future cash flows, expected distributable cash flow or estimated future dividends. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather, customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes; and the COVID-19 pandemic and the duration and impact thereof.
Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities, operating performance, legislative and regulatory parameters; litigation, including with respect to the Dakota Access Pipeline (DAPL) and the Line 5 dual pipelines; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; our dividend policy; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; public opinion; changes in tax laws and tax rates; exchange rates; interest rates; commodity prices; political decisions; the supply of, demand for and prices of commodities; and the COVID-19 pandemic, including but not limited to those risks and uncertainties discussed in this quarterly report on Form 10-Q and in our other filings with Canadian and US securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statement made in this quarterly report on Form 10-Q or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.
5

PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |  |
Operating revenues |  |  |  |  |
Commodity sales | 6,429 |  | 7,389 |  |  |  |
Transportation and other services | 4,218 |  | 3,208 |  |  |  |
Gas distribution sales | 1,540 |  | 1,416 |  |  |  |
Total operating revenues (Note 3) | 12,187 |  | 12,013 |  |  |  |
Operating expenses |  |  |  |  |
Commodity costs | 6,198 |  | 7,163 |  |  |  |
Gas distribution costs | 950 |  | 855 |  |  |  |
Operating and administrative | 1,559 |  | 1,600 |  |  |  |
Depreciation and amortization | 932 |  | 882 |  |  |  |
Total operating expenses | 9,639 |  | 10,500 |  |  |  |
Operating income | 2,548 |  | 1,513 |  |  |  |
Income from equity investments | 395 |  | 163 |  |  |  |
Impairment of equity investments (Note 8) | — |  | (1,736) |  |  |  |
Other income/(expense) |  |  |  |  |
Net foreign currency gain/(loss) | 152 |  | (956) |  |  |  |
Other | 59 |  | (191) |  |  |  |
Interest expense | (657) |  | (706) |  |  |  |
Earnings/(loss) before income taxes | 2,497 |  | (1,913) |  |  |  |
Income tax (expense)/recovery (Note 10) | (483) |  | 549 |  |  |  |
Earnings/(loss) | 2,014 |  | (1,364) |  |  |  |
(Earnings)/loss attributable to noncontrolling interests | (22) |  | 31 |  |  |  |
Earnings/(loss) attributable to controlling interests | 1,992 |  | (1,333) |  |  |  |
Preference share dividends | (92) |  | (96) |  |  |  |
Earnings/(loss) attributable to common shareholders | 1,900 |  | (1,429) |  |  |  |
Earnings/(loss) per common share attributable to common shareholders (Note 5) | 0.94 |  | (0.71) |  |  |  |
Diluted earnings/(loss) per common share attributable to common shareholders (Note 5) | 0.94 |  | (0.71) |  |  |  |

The accompanying notes are an integral part of these interim consolidated financial statements.
6

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

|  |  | Three months ended March 31,
|  |  |  | 2021 | 2020
(unaudited; millions of Canadian dollars) |  |  |  |  |
Earnings/(loss) |  |  |  | 2,014 |  | (1,364) |
Other comprehensive income/(loss), net of tax |  |  |  |  |
Change in unrealized gain/(loss) on cash flow hedges |  |  |  | 370 |  | (513) |
Change in unrealized gain/(loss) on net investment hedges |  |  |  | 93 |  | (715) |
Other comprehensive loss from equity investees |  |  |  | (22) |  | (10) |
Excluded components of fair value hedges |  |  |  | (1) |  | 3 |
Reclassification to earnings of loss on cash flow hedges |  |  |  | 52 |  | 32 |
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts |  |  |  | 5 |  | 3 |
Foreign currency translation adjustments |  |  |  | (796) |  | 5,637 |
Other comprehensive (loss)/income, net of tax |  |  |  | (299) |  | 4,437 |
Comprehensive income |  |  |  | 1,715 |  | 3,073 |
Comprehensive loss/(income) attributable to noncontrolling interests |  |  |  | 3 |  | (145) |
Comprehensive income attributable to controlling interests |  |  |  | 1,718 |  | 2,928 |
Preference share dividends |  |  |  | (92) |  | (96) |
Comprehensive income attributable to common shareholders |  |  |  | 1,626 |  | 2,832 |

The accompanying notes are an integral part of these interim consolidated financial statements.
7

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

|  | Three months ended March 31,
|  |  | 2021 | 2020
(unaudited; millions of Canadian dollars, except per share amounts) |  |  |  |
Preference shares |  |  |  |
Balance at beginning and end of period |  |  | 7,747 |  | 7,747 |
Common shares |  |  |  |
Balance at beginning of period |  |  | 64,768 |  | 64,746 |
Shares issued on exercise of stock options |  |  | 4 |  | 14 |
Balance at end of period |  |  | 64,772 |  | 64,760 |
Additional paid-in capital |  |  |  |
Balance at beginning of period |  |  | 277 |  | 187 |
Stock-based compensation |  |  | 11 |  | 14 |
Options exercised |  |  | (3) |  | (16) |
Change in reciprocal interest |  |  | 39 |  | 12 |
Other |  |  | — |  | 5 |
Balance at end of period |  |  | 324 |  | 202 |
Deficit |  |  |  |
Balance at beginning of period |  |  | (9,995) |  | (6,314) |
Earnings/(loss) attributable to controlling interests |  |  | 1,992 |  | (1,333) |
Preference share dividends |  |  | (92) |  | (96) |
Dividends paid to reciprocal shareholder |  |  | 3 |  | 5 |
Modified retrospective adoption of ASU 2016-13 Financial Instruments - Credit Losses |  |  | — |  | (66) |
Other |  |  | (1) |  | (4) |
Balance at end of period |  |  | (8,093) |  | (7,808) |
Accumulated other comprehensive (loss)/income (Note 7) |  |  |  |
Balance at beginning of period |  |  | (1,401) |  | (272) |
Other comprehensive (loss)/income attributable to common shareholders, net of tax |  |  | (274) |  | 4,261 |
Balance at end of period |  |  | (1,675) |  | 3,989 |
Reciprocal shareholding |  |  |  |
Balance at beginning of period |  |  | (29) |  | (51) |
Change in reciprocal interest |  |  | 12 |  | 4 |
Balance at end of period |  |  | (17) |  | (47) |
Total Enbridge Inc. shareholders’ equity |  |  | 63,058 |  | 68,843 |
Noncontrolling interests |  |  |  |
Balance at beginning of period |  |  | 2,996 |  | 3,364 |
Earnings/(loss) attributable to noncontrolling interests |  |  | 22 |  | (31) |
Other comprehensive (loss)/income attributable to noncontrolling interests, net of tax |  |  |  |
Change in unrealized loss on cash flow hedges |  |  | (3) |  | (2) |
Foreign currency translation adjustments |  |  | (22) |  | 178 |
Contributions |  |  | 3 |  | 15 |
Distributions |  |  | (66) |  | (76) |
Balance at end of period |  |  | 2,930 |  | 3,448 |
Total equity |  |  | 65,988 |  | 72,291 |
Dividends paid per common share |  |  | 0.835 |  | 0.810 |

The accompanying notes are an integral part of these interim consolidated financial statements.
8

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

| Three months ended March 31,
| 2021 | 2020
(unaudited; millions of Canadian dollars) |  |
Operating activities |  |
Earnings/(loss) | 2,014 |  | (1,364) |
Adjustments to reconcile earnings/(loss) to net cash provided by operating activities: |  |
Depreciation and amortization | 932 |  | 882 |
Deferred income tax expense/(recovery) | 369 |  | (713) |
Changes in unrealized (gain)/loss on derivative instruments, net (Note 9) | (315) |  | 1,556 |
Income from equity investments | (395) |  | (163) |
Distributions from equity investments | 388 |  | 428 |
Impairment of equity investments (Note 8) | — |  | 1,736 |
Gain on disposition | (41) |  | — |
Other | 30 |  | 253 |
Changes in operating assets and liabilities | (418) |  | 194 |
Net cash provided by operating activities | 2,564 |  | 2,809 |
Investing activities |  |
Capital expenditures | (2,059) |  | (1,147) |
Long-term investments and restricted long-term investments | (61) |  | (87) |
Distributions from equity investments in excess of cumulative earnings | 61 |  | 77 |
Additions to intangible assets | (65) |  | (69) |
Proceeds from disposition | 122 |  | — |
Affiliate loans, net | 44 |  | (44) |
Net cash used in investing activities | (1,958) |  | (1,270) |
Financing activities |  |
Net change in short-term borrowings | (27) |  | (63) |
Net change in commercial paper and credit facility draws | 1,727 |  | 1,159 |
Debenture and term note issues, net of issue costs | 629 |  | 990 |
Debenture and term note repayments | (912) |  | (1,657) |
Contributions from noncontrolling interests | 3 |  | 15 |
Distributions to noncontrolling interests | (66) |  | (76) |
Common shares issued | — |  | 1 |
Preference share dividends | (92) |  | (96) |
Common share dividends | (1,691) |  | (1,641) |
Redemption of preferred shares held by subsidiary | (115) |  | — |
Other | (21) |  | (18) |
Net cash used in financing activities | (565) |  | (1,386) |
Effect of translation of foreign denominated cash and cash equivalents and restricted cash | (7) |  | 11 |
Net increase in cash and cash equivalents and restricted cash | 34 |  | 164 |
Cash and cash equivalents and restricted cash at beginning of period | 490 |  | 676 |
Cash and cash equivalents and restricted cash at end of period | 524 |  | 840 |

The accompanying notes are an integral part of these interim consolidated financial statements.
9

ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

| March 31, 2021 | December 31, 2020
(unaudited; millions of Canadian dollars; number of shares in millions) |  |
Assets |  |
Current assets |  |
Cash and cash equivalents | 465 |  | 452 |
Restricted cash | 59 |  | 38 |
Accounts receivable and other | 6,227 |  | 5,258 |
Accounts receivable from affiliates | 30 |  | 66 |
Inventory | 853 |  | 1,536 |
| 7,634 |  | 7,350 |
Property, plant and equipment, net | 95,141 |  | 94,571 |
Long-term investments | 13,627 |  | 13,818 |
Restricted long-term investments | 529 |  | 553 |
Deferred amounts and other assets | 8,542 |  | 8,446 |
Intangible assets, net | 2,219 |  | 2,080 |
Goodwill | 32,365 |  | 32,688 |
Deferred income taxes | 638 |  | 770 |
Total assets | 160,695 |  | 160,276 |
Liabilities and equity |  |
Current liabilities |  |
Short-term borrowings | 1,094 |  | 1,121 |
Accounts payable and other | 7,211 |  | 9,228 |
Accounts payable to affiliates | 18 |  | 22 |
Interest payable | 589 |  | 651 |
Current portion of long-term debt | 4,014 |  | 2,957 |
| 12,926 |  | 13,979 |
Long-term debt | 62,688 |  | 62,819 |
Other long-term liabilities | 8,360 |  | 8,783 |
Deferred income taxes | 10,733 |  | 10,332 |
| 94,707 |  | 95,913 |
Contingencies (Note 12) |  |
Equity |  |
Share capital |  |
Preference shares | 7,747 |  | 7,747 |
Common shares (2,026 outstanding at March 31, 2021 and December 31, 2020) | 64,772 |  | 64,768 |
Additional paid-in capital | 324 |  | 277 |
Deficit | (8,093) |  | (9,995) |
Accumulated other comprehensive loss (Note 7) | (1,675) |  | (1,401) |
Reciprocal shareholding | (17) |  | (29) |
Total Enbridge Inc. shareholders’ equity | 63,058 |  | 61,367 |
Noncontrolling interests | 2,930 |  | 2,996 |
| 65,988 |  | 64,363 |
Total liabilities and equity | 160,695 |  | 160,276 |

The accompanying notes are an integral part of these interim consolidated financial statements.
10

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. BASIS OF PRESENTATION
The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2020. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2020, except for the adoption of new standards (Note 2). Amounts are stated in Canadian dollars unless otherwise noted.
Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as the supply of and demand for crude oil and natural gas, and may not be indicative of annual results.
2. CHANGES IN ACCOUNTING POLICIES
ADOPTION OF NEW ACCOUNTING STANDARDS
Reference Rate Reform
For eligible hedging relationships existing as at January 1, 2021 and prospectively, we have applied the optional expedient in Accounting Standards Update (ASU) 2020-04 whereby the modification of the hedging instrument does not result in an automatic hedging relationship de-designation. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Clarifying Interaction between Equity Securities, Equity Method Investments and Derivatives
Effective January 1, 2021, we adopted ASU 2020-01 on a prospective basis. The new standard was issued in January 2020 and clarifies that observable transactions should be considered for the purpose of applying the measurement alternative in accordance with Accounting Standards Codification (ASC) 321 Investments - Equity Securities immediately before the application or upon discontinuance of the equity method of accounting. Furthermore, the ASU clarifies that forward contracts or purchased options on equity securities are not out of scope of ASC 815 Derivatives and Hedging guidance only because, upon the contracts’ exercise, the equity securities could be accounted for under the equity method of accounting or fair value option. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Accounting for Income Taxes
Effective January 1, 2021, we adopted ASU 2019-12 on a prospective basis. The new standard was issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting update removes certain exceptions to the general principles in ASC 740 Income Taxes as well as provides simplification by clarifying and amending existing guidance. The adoption of this ASU did not have a material impact on our consolidated financial statements.
11

FUTURE ACCOUNTING POLICY CHANGES
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity
ASU 2020-06 was issued in August 2020 to simplify accounting for certain financial instruments. The ASU eliminates the current models that require separation of beneficial conversion and cash conversion features from convertible instruments and simplifies the derivative scope exception guidance pertaining to equity classification of contracts in an entity’s own equity. The ASU also introduces additional disclosures for convertible debt and freestanding instruments that are indexed to and settled in an entity’s own equity. The ASU amends the diluted earnings per share guidance, including the requirement to use if-converted method for all convertible instruments and an update for instruments that can be settled in either cash or shares. ASU 2020-06 is effective January 1, 2022 and should be applied on a full or modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.
3. 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, 2021
(millions of Canadian dollars) |  |  |  |  |  |  |
Transportation revenues | 2,329 |  | 1,121 |  | 216 |  | — |  | — |  | — |  | 3,666 |
Storage and other revenues | 26 |  | 74 |  | 58 |  | — |  | — |  | — |  | 158 |
Gas gathering and processing revenues | — |  | 7 |  | — |  | — |  | — |  | — |  | 7 |
Gas distribution revenue | — |  | — |  | 1,534 |  | — |  | — |  | — |  | 1,534 |
Electricity and transmission revenues | — |  | — |  | — |  | 76 |  | — |  | — |  | 76 |
Total revenue from contracts with customers | 2,355 |  | 1,202 |  | 1,808 |  | 76 |  | — |  | — |  | 5,441 |
Commodity sales | — |  | — |  | — |  | — |  | 6,429 |  | — |  | 6,429 |
Other revenues 1,2 | 212 |  | 12 |  | 6 |  | 91 |  | — |  | (4) |  | 317 |
Intersegment revenues | 132 |  | — |  | 9 |  | — |  | 4 |  | (145) |  | — |
Total revenues | 2,699 |  | 1,214 |  | 1,823 |  | 167 |  | 6,433 |  | (149) |  | 12,187 |

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| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated
Three months ended March 31, 2020
(millions of Canadian dollars) |  |  |  |  |  |  |
Transportation revenues | 2,440 |  | 1,255 |  | 215 |  | — |  | — |  | — |  | 3,910 |
Storage and other revenues | 26 |  | 79 |  | 47 |  | — |  | — |  | — |  | 152 |
Gas gathering and processing revenues | — |  | 7 |  | — |  | — |  | — |  | — |  | 7 |
Gas distribution revenues | — |  | — |  | 1,417 |  | — |  | — |  | — |  | 1,417 |
Electricity and transmission revenues | — |  | — |  | — |  | 50 |  | — |  | — |  | 50 |
Total revenue from contracts with customers | 2,466 |  | 1,341 |  | 1,679 |  | 50 |  | — |  | — |  | 5,536 |
Commodity sales | — |  | — |  | — |  | — |  | 7,389 |  | — |  | 7,389 |
Other revenues 1,2 | (1,017) |  | 16 |  | (1) |  | 103 |  | (7) |  | (6) |  | (912) |
Intersegment revenues | 85 |  | — |  | 4 |  | — |  | 16 |  | (105) |  | — |
Total revenues | 1,534 |  | 1,357 |  | 1,682 |  | 153 |  | 7,398 |  | (111) |  | 12,013 |

1 Includes mark-to-market gains/(losses) from our hedging program for the three months ended March 31, 2021 and 2020 of $130 million gain and $1,106 million loss, respectively.
2 Includes revenues from lease contracts for the three months ended March 31, 2021 and 2020 of $159 million and $158 million, respectively.
We disaggregate revenues into categories which represent our principal performance obligations within each business segment. These revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.
Contract Balances

| Contract Receivables | Contract Assets | Contract Liabilities
(millions of Canadian dollars) |  |  |
Balance as at March 31, 2021 | 2,120 |  | 214 |  | 1,724 |
Balance as at December 31, 2020 | 2,042 |  | 226 |  | 1,815 |

Contract receivables represent the amount of receivables derived from contracts with customers.
Contract assets represent the amount of revenues which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at which our right to payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to receive the consideration becomes unconditional.
Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenues. Revenue recognized during the three months ended March 31, 2021 included in contract liabilities at the beginning of the period was $145 million. Increases in contract liabilities from cash received, net of amounts recognized as revenues during the three months ended March 31, 2021 were $69 million.
Performance Obligations
There were no material revenues recognized in the three months ended March 31, 2021 from performance obligations satisfied in previous periods.
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Revenues to be Recognized from Unfulfilled Performance Obligations
Total revenues from performance obligations expected to be fulfilled in future periods is $57.4 billion, of which $5.0 billion and $5.7 billion is expected to be recognized during the nine months ending December 31, 2021 and the year ending December 31, 2022, respectively.
The revenues excluded from the amounts above based on optional exemptions available under ASC 606, as explained below, represent a significant portion of our overall revenues and revenue from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for revenues to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenue from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.
Recognition and Measurement of Revenues

| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation |  | Consolidated
Three months ended March 31, 2021
(millions of Canadian dollars) |  |  |  |  |  |
Revenues from products transferred at a point in time | — |  | — |  | 17 |  | — |  |  | 17 |
Revenues from products and services transferred over time 1 | 2,355 |  | 1,202 |  | 1,791 |  | 76 |  |  | 5,424 |
Total revenue from contracts with customers | 2,355 |  | 1,202 |  | 1,808 |  | 76 |  |  | 5,441 |

| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation |  | Consolidated
Three months ended March 31, 2020
(millions of Canadian dollars) |  |  |  |  |  |
Revenues from products transferred at a point in time | — |  | — |  | 15 |  | — |  |  | 15 |
Revenues from products and services transferred over time 1 | 2,466 |  | 1,341 |  | 1,664 |  | 50 |  |  | 5,521 |
Total revenue from contracts with customers | 2,466 |  | 1,341 |  | 1,679 |  | 50 |  |  | 5,536 |

1 Includes revenues 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.
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4. SEGMENTED INFORMATION

| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated
Three months ended March 31, 2021
(millions of Canadian dollars) |  |  |  |  |  |  |
Revenues | 2,699 |  | 1,214 |  | 1,823 |  | 167 |  | 6,433 |  | (149) |  | 12,187 |
Commodity and gas distribution costs | (3) |  | — |  | (958) |  | — |  | (6,353) |  | 166 |  | (7,148) |
Operating and administrative | (819) |  | (434) |  | (272) |  | (43) |  | (14) |  | 23 |  | (1,559) |
Income from equity investments | 154 |  | 182 |  | 22 |  | 37 |  | — |  | — |  | 395 |
Other income/(expense) | 8 |  | 11 |  | 19 |  | (5) |  | (2) |  | 180 |  | 211 |
Earnings before interest, income taxes, and depreciation and amortization | 2,039 |  | 973 |  | 634 |  | 156 |  | 64 |  | 220 |  | 4,086 |
Depreciation and amortization |  |  |  |  |  |  | (932) |
Interest expense |  |  |  |  |  |  | (657) |
Income tax expense |  |  |  |  |  |  | (483) |
Earnings |  |  |  |  |  |  | 2,014 |
Capital expenditures 1 | 1,195 |  | 482 |  | 219 |  | 5 |  | — |  | 12 |  | 1,913 |

| Liquids Pipelines | Gas Transmission and Midstream | Gas Distribution and Storage | Renewable Power Generation | Energy Services | Eliminations and Other | Consolidated
Three months ended March 31, 2020
(millions of Canadian dollars) |  |  |  |  |  |  |
Revenues | 1,534 |  | 1,357 |  | 1,682 |  | 153 |  | 7,398 |  | (111) |  | 12,013 |
Commodity and gas distribution costs | (7) |  | — |  | (872) |  | — |  | (7,243) |  | 104 |  | (8,018) |
Operating and administrative | (865) |  | (507) |  | (249) |  | (50) |  | (28) |  | 99 |  | (1,600) |
Income/(loss) from equity investments | 197 |  | (75) |  | 23 |  | 16 |  | 2 |  | — |  | 163 |
Impairment of equity investments | — |  | (1,736) |  | — |  | — |  | — |  | — |  | (1,736) |
Other income/(expense) | (9) |  | (93) |  | 20 |  | 1 |  | (8) |  | (1,058) |  | (1,147) |
Earnings/(loss) before interest, income taxes, and depreciation and amortization | 850 |  | (1,054) |  | 604 |  | 120 |  | 121 |  | (966) |  | (325) |
Depreciation and amortization |  |  |  |  |  |  | (882) |
Interest expense |  |  |  |  |  |  | (706) |
Income tax recovery |  |  |  |  |  |  | 549 |
Loss |  |  |  |  |  |  | (1,364) |
Capital expenditures 1 | 500 |  | 391 |  | 222 |  | 23 |  | — |  | 22 |  | 1,158 |

1 Includes allowance for equity funds used during construction.
5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE
BASIC
Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of approximately 3 million and 6 million for the three months ended March 31, 2021 and 2020, respectively, resulting from our reciprocal investment in Noverco Inc.
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DILUTED
The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options 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, |  |
| 2021 | 2020 |  |  |
(number of shares in millions) |  |  |  |  |
Weighted average shares outstanding | 2,022 |  | 2,019 |  |  |  |
Effect of dilutive options | 1 |  | 2 |  |  |  |
Diluted weighted average shares outstanding | 2,023 |  | 2,021 |  |  |  |

For the three months ended March 31, 2021 and 2020, 27.6 million and 16.7 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $51.42 and $56.26, respectively, were excluded from the diluted earnings per common share calculation.
DIVIDENDS PER SHARE
On May 4, 2021, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2021 to shareholders of record on May 14, 2021.

| Dividend per share
Common Shares 1 | $0.83500 |
Preference Shares, Series A | $0.34375 |
Preference Shares, Series B | $0.21340 |
Preference Shares, Series C 2 | $0.15501 |
Preference Shares, Series D | $0.27875 |
Preference Shares, Series F | $0.29306 |
Preference Shares, Series H | $0.27350 |
Preference Shares, Series J | US$0.30540 |
Preference Shares, Series L | US$0.30993 |
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 17 | $0.32188 |
Preference Shares, Series 19 | $0.30625 |

1 The quarterly dividend per common share was increased 3% to $0.835 from $0.81, effective March 1, 2021.
2 The quarterly dividend per share paid on Series C was increased to $0.15501 from $0.15349 on March 1, 2021, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.
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6. DEBT
CREDIT FACILITIES
The following table provides details of our committed credit facilities as at March 31, 2021:

| Maturity 1 | Total Facilities | Draws 2 | Available
(millions of Canadian dollars) |  |  |  |
Enbridge Inc. | 2022-2024 | 9,159 |  | 7,390 |  | 1,769 |
Enbridge (U.S.) Inc. | 2022-2024 | 6,913 |  | 3,351 |  | 3,562 |
Enbridge Pipelines Inc. | 2022 | 3,000 |  | 1,358 |  | 1,642 |
Enbridge Gas Inc. | 2022 | 2,000 |  | 1,094 |  | 906 |
Total committed credit facilities |  | 21,072 |  | 13,193 |  | 7,879 |

1 Maturity date is inclusive of the one-year term out option for certain credit facilities.
2 Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
On February 10, 2021, Enbridge Inc. entered into a three year, revolving, extendible, sustainability linked credit facility for $1.0 billion with a syndicate of lenders and concurrently terminated our one year, revolving, syndicated credit facility for $3.0 billion.
On February 25, 2021, two term loans with an aggregate total of US$500 million were repaid with proceeds from a floating rate notes issuance.
In addition to the committed credit facilities noted above, we maintain $845 million of uncommitted demand credit facilities, of which $595 million was unutilized as at March 31, 2021. As at December 31, 2020, we had $849 million of uncommitted demand credit facilities, of which $533 million was unutilized.
Our credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2022 to 2024.
As at March 31, 2021 and December 31, 2020, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $10.6 billion and $9.9 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.
LONG-TERM DEBT ISSUANCE
During the three months ended March 31, 2021, we completed the following long-term debt issuance totaling US$500 million:

Company | Issue Date |  |  | Principal Amount
(millions of Canadian dollars unless otherwise stated) |  |
Enbridge Inc. |  |  |
| February 2021 | Floating rate notes due February 2023 1 | US$500

1 Notes mature in two years and carry an interest rate set to equal Secured Overnight Financing Rate (SOFR) plus a margin of 40 basis points.
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LONG-TERM DEBT REPAYMENTS
During the three months ended March 31, 2021, we completed the following long-term debt repayments totaling $600 million and US$250 million:

Company | Repayment Date |  |  | Principal Amount |
(millions of Canadian dollars unless otherwise stated) |  |  |
Enbridge Inc. |  |  |
| February 2021 | 4.26% medium-term notes |  | $200 |
| March 2021 | 3.16% medium-term notes | $400 |
Spectra Energy Partners, LP |  |  |
| March 2021 | 4.60% senior notes |  | US$250 |

SUBORDINATED TERM NOTES
As at March 31, 2021 and December 31, 2020, our fixed-to-floating and fixed-to-fixed subordinated term notes had a principal value of $7.7 billion and $7.8 billion, respectively.
FAIR VALUE ADJUSTMENT
As at March 31, 2021 and December 31, 2020, the net fair value adjustments for total debt assumed in the acquisition of Spectra Energy Corp were $726 million and $750 million, respectively. During the three months ended March 31, 2021 and 2020, the amortization of the fair value adjustment, recorded as a reduction to Interest expense in the Consolidated Statements of Earnings, was $12 million and $15 million, respectively.
DEBT COVENANTS
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2021, we were in compliance with all debt covenants.
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7. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
Changes in Accumulated Other Comprehensive Income (AOCI) attributable to our common shareholders for the three months ended March 31, 2021 and 2020 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, 2021 | (1,326) |  | 5 |  | (215) |  | 568 |  | 66 |  | (499) |  | (1,401) |
Other comprehensive income/(loss) retained in AOCI | 493 |  | (1) |  | 105 |  | (774) |  | (26) |  | — |  | (203) |
Other comprehensive (income)/loss reclassified to earnings |  |  |  |  |  |  |
Interest rate contracts 1 | 63 |  | — |  | — |  | — |  | — |  | — |  | 63 |
Commodity contracts 2 | 1 |  | — |  | — |  | — |  | — |  | — |  | 1 |
Foreign exchange contracts 3 | 1 |  | — |  | — |  | — |  | — |  | — |  | 1 |
Amortization of pension and OPEB actuarial loss and prior service costs 4 | — |  | — |  | — |  | — |  | — |  | 7 |  | 7 |
Other | 17 |  | — |  | — |  | (20) |  | 3 |  | — |  | — |
| 575 |  | (1) |  | 105 |  | (794) |  | (23) |  | 7 |  | (131) |
Tax impact |  |  |  |  |  |  |
Income tax on amounts retained in AOCI | (120) |  | — |  | (12) |  | — |  | 4 |  | — |  | (128) |
Income tax on amounts reclassified to earnings | (13) |  | — |  | — |  | — |  | — |  | (2) |  | (15) |
| (133) |  | — |  | (12) |  | — |  | 4 |  | (2) |  | (143) |
Balance as at March 31, 2021 | (884) |  | 4 |  | (122) |  | (226) |  | 47 |  | (494) |  | (1,675) |

| 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, 2020 | (1,073) |  | — |  | (317) |  | 1,396 |  | 67 |  | (345) |  | (272) |
Other comprehensive income/(loss) retained in AOCI | (693) |  | 3 |  | (715) |  | 5,459 |  | (7) |  | — |  | 4,047 |
Other comprehensive loss reclassified to earnings |  |  |  |  |  |  |
Interest rate contracts 1 | 43 |  | — |  | — |  | — |  | — |  | — |  | 43 |
Foreign exchange contracts 3 | 1 |  | — |  | — |  | — |  | — |  | — |  | 1 |
Amortization of pension and OPEB actuarial loss and prior service costs 4 | — |  | — |  | — |  | — |  | — |  | 4 |  | 4 |
| (649) |  | 3 |  | (715) |  | 5,459 |  | (7) |  | 4 |  | 4,095 |
Tax impact |  |  |  |  |  |  |
Income tax on amounts retained in AOCI | 182 |  | — |  | — |  | — |  | (3) |  | — |  | 179 |
Income tax on amounts reclassified to earnings | (12) |  | — |  | — |  | — |  | — |  | (1) |  | (13) |
| 170 |  | — |  | — |  | — |  | (3) |  | (1) |  | 166 |
Balance as at March 31, 2020 | (1,552) |  | 3 |  | (1,032) |  | 6,855 |  | 57 |  | (342) |  | 3,989 |

1 Reported within Interest expense in the Consolidated Statements of Earnings.
2 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and
administrative expense in the Consolidated Statements of Earnings.
3 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
4 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.
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8. IMPAIRMENT OF EQUITY INVESTMENTS
DCP Midstream, LLC
DCP Midstream, LLC (DCP Midstream), a 50% owned equity method investment of Enbridge, holds an equity interest in DCP Midstream, LP. A decline in the market price of DCP Midstream, LP’s publicly traded units during the first quarter of 2020 resulted in an other than temporary impairment loss on our investment in DCP Midstream of $1.7 billion for the three months ended March 31, 2020. In addition, we incurred losses of $324 million through our equity earnings pick up in relation to asset and goodwill impairment losses recorded by DCP Midstream, LP during the three months ended March 31, 2020. The carrying value of our investment in DCP Midstream as at March 31, 2021 and December 31, 2020 was $328 million and $331 million, respectively.
Our investment in DCP Midstream forms part of our Gas Transmission and Midstream segment. The impairment losses were recorded within Impairment of equity investments in the Consolidated Statements of Earnings.
9. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
MARKET RISK
Our earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risks). Formal risk management policies, processes and systems have been designed to mitigate these risks.
The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.
Foreign Exchange Risk
We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying cash flow, fair value and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge certain net investments in US dollar denominated investments and subsidiaries using foreign currency derivatives and US dollar denominated debt.
Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a 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 3.0%.
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We are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps. As at March 31, 2021, we do not have any pay floating-receive fixed interest rate swaps outstanding.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program 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 2.4%.
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. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.
COVID-19 PANDEMIC RISK
The spread of the COVID-19 pandemic has caused significant volatility in Canada, the US and international markets. While we have taken proactive measures to deliver energy safely and reliably during this pandemic, given the ongoing dynamic nature of the circumstances surrounding COVID-19, including ongoing uncertainty as to the duration of the pandemic and corresponding public health measures, the impact of this pandemic on our business remains uncertain.
TOTAL DERIVATIVE INSTRUMENTS
We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances.
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The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.

March 31, 2021 | Derivative Instruments Used as Cash Flow Hedges |  | Derivative Instruments Used as Fair Value Hedges | Non- Qualifying Derivative Instruments | Total Gross Derivative Instruments as Presented |  | Amounts Available for Offset | Total Net Derivative Instruments
(millions of Canadian dollars) |  |  |  |  |  |  |  |
Accounts receivable and other |  |  |  |  |  |  |  |
Foreign exchange contracts | — |  |  | — |  | 242 |  | 242 |  |  | (36) |  | 206 |
Commodity contracts | — |  |  | — |  | 158 |  | 158 |  |  | (93) |  | 65 |
Other contracts | 1 |  |  | — |  | 1 |  | 2 |  |  | — |  | 2 |
| 1 |  |  | — |  | 401 |  | 402 |  |  | (129) |  | 273 |
Deferred amounts and other assets |  |  |  |  |  |  |  |
Foreign exchange contracts | — |  |  | — |  | 465 |  | 465 |  |  | (211) |  | 254 |
Interest rate contracts | 247 |  |  | — |  | — |  | 247 |  |  | (26) |  | 221 |
Commodity contracts | — |  |  | — |  | 47 |  | 47 |  |  | (14) |  | 33 |
Other contracts | 1 |  |  | — |  | 1 |  | 2 |  |  | — |  | 2 |
| 248 |  |  | — |  | 513 |  | 761 |  |  | (251) |  | 510 |
Accounts payable and other |  |  |  |  |  |  |  |
Foreign exchange contracts | (10) |  |  | (120) |  | (119) |  | (249) |  |  | 36 |  | (213) |
Interest rate contracts | (240) |  |  | — |  | — |  | (240) |  |  | — |  | (240) |
Commodity contracts | (4) |  |  | — |  | (221) |  | (225) |  |  | 93 |  | (132) |
| (254) |  |  | (120) |  | (340) |  | (714) |  |  | 129 |  | (585) |
Other long-term liabilities |  |  |  |  |  |  |  |
Foreign exchange contracts | — |  |  | — |  | (543) |  | (543) |  |  | 211 |  | (332) |
Interest rate contracts | (79) |  |  | — |  | (23) |  | (102) |  |  | 26 |  | (76) |
Commodity contracts | (4) |  |  | — |  | (66) |  | (70) |  |  | 14 |  | (56) |
| (83) |  |  | — |  | (632) |  | (715) |  |  | 251 |  | (464) |
Total net derivative assets/(liabilities) |  |  |  |  |  |  |  |
Foreign exchange contracts | (10) |  |  | (120) |  | 45 |  | (85) |  |  | — |  | (85) |
Interest rate contracts | (72) |  |  | — |  | (23) |  | (95) |  |  | — |  | (95) |
Commodity contracts | (8) |  |  | — |  | (82) |  | (90) |  |  | — |  | (90) |
Other contracts | 2 |  |  | — |  | 2 |  | 4 |  |  | — |  | 4 |
| (88) |  |  | (120) |  | (58) |  | (266) |  |  | — |  | (266) |

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December 31, 2020 | Derivative Instruments Used as Cash Flow Hedges |  | Derivative Instruments Used as Fair Value Hedges | Non- Qualifying Derivative Instruments | Total Gross Derivative Instruments as Presented |  | Amounts Available for Offset | Total Net Derivative Instruments
(millions of Canadian dollars) |  |  |  |  |  |  |  |
Accounts receivable and other |  |  |  |  |  |  |  |
Foreign exchange contracts | — |  |  | — |  | 180 |  | 180 |  |  | (28) |  | 152 |
Commodity contracts | — |  |  | — |  | 143 |  | 143 |  |  | (81) |  | 62 |
| — |  |  | — |  | 323 |  | 323 |  |  | (109) |  | 214 |
Deferred amounts and other assets |  |  |  |  |  |  |  |
Foreign exchange contracts | 14 |  |  | — |  | 452 |  | 466 |  |  | (218) |  | 248 |
Interest rate contracts | 56 |  |  | — |  | — |  | 56 |  |  | (25) |  | 31 |
Commodity contracts | — |  |  | — |  | 39 |  | 39 |  |  | (9) |  | 30 |
| 70 |  |  | — |  | 491 |  | 561 |  |  | (252) |  | 309 |
Accounts payable and other |  |  |  |  |  |  |  |
Foreign exchange contracts | (5) |  |  | (29) |  | (151) |  | (185) |  |  | 28 |  | (157) |
Interest rate contracts | (423) |  |  | — |  | (2) |  | (425) |  |  | — |  | (425) |
Commodity contracts | (2) |  |  | — |  | (278) |  | (280) |  |  | 81 |  | (199) |
Other contracts | (1) |  |  | — |  | (3) |  | (4) |  |  | — |  | (4) |
| (431) |  |  | (29) |  | (434) |  | (894) |  |  | 109 |  | (785) |
Other long-term liabilities |  |  |  |  |  |  |  |
Foreign exchange contracts | — |  |  | (87) |  | (673) |  | (760) |  |  | 218 |  | (542) |
Interest rate contracts | (218) |  |  | — |  | (23) |  | (241) |  |  | 25 |  | (216) |
Commodity contracts | (1) |  |  | — |  | (57) |  | (58) |  |  | 9 |  | (49) |
| (219) |  |  | (87) |  | (753) |  | (1,059) |  |  | 252 |  | (807) |
Total net derivative assets/(liabilities) |  |  |  |  |  |  |  |
Foreign exchange contracts | 9 |  |  | (116) |  | (192) |  | (299) |  |  | — |  | (299) |
Interest rate contracts | (585) |  |  | — |  | (25) |  | (610) |  |  | — |  | (610) |
Commodity contracts | (3) |  |  | — |  | (153) |  | (156) |  |  | — |  | (156) |
Other contracts | (1) |  |  | — |  | (3) |  | (4) |  |  | — |  | (4) |
| (580) |  |  | (116) |  | (373) |  | (1,069) |  |  | — |  | (1,069) |

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

March 31, 2021 | 2021 | 2022 | 2023 | 2024 | 2025 | Thereafter | Total |  |  |
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) | 1,237 |  | 1,750 |  | — |  | — |  | — |  | — |  | 2,987 |  |  |  |
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) | 4,331 |  | 5,853 |  | 3,784 |  | 1,856 |  | 648 |  | — |  | 16,472 |  |  |  |
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) | 75 |  | 28 |  | 29 |  | 30 |  | 30 |  | 60 |  | 252 |  |  |  |
Foreign exchange contracts - Euro forwards - sell (millions of Euro) | 85 |  | 94 |  | 92 |  | 91 |  | 86 |  | 428 |  | 876 |  |  |  |
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) | — |  | 72,500 |  | — |  | — |  | — |  | — |  | 72,500 |  |  |  |
Interest rate contracts - short-term debt pay fixed rate (millions of Canadian dollars) | 2,960 |  | 394 |  | 47 |  | 35 |  | 30 |  | 90 |  | 3,556 |  |  |  |
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars) | 2,060 |  | 1,980 |  | 1,328 |  | — |  | — |  | — |  | 5,368 |  |  |  |
Equity contracts (millions of Canadian dollars) | 39 |  | 7 |  | 11 |  | — |  | — |  | — |  | 57 |  |  |  |
Commodity contracts - natural gas (billions of cubic feet)2 | 133 |  | 38 |  | 14 |  | 4 |  | 11 |  | — |  | 200 |  |  |  |
Commodity contracts - crude oil (millions of barrels)2 | 8 |  | — |  | — |  | — |  | — |  | — |  | 8 |  |  |  |
Commodity contracts - power (megawatt per hour) (MW/H) | (14) |  | (43) |  | (43) |  | (43) |  | (43) |  | — |  | (39) |  | 1 |  |

1 Total is an average net purchase/(sale) of power.
2 Total is a net purchase/(sale) of underlying commodity.
Fair Value Derivatives
For foreign exchange 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 Net foreign currency gain/(loss) in the Consolidated Statements of Earnings. Any excluded components are included in the Consolidated Statements of Comprehensive Income.

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars) |  |  |  |  |
Unrealized gain/(loss) on derivative | (3) |  | 218 |  |  |  |
Unrealized loss on hedged item | (4) |  | (203) |  |  |  |
Realized loss on derivative | (39) |  | (12) |  |  |  |
Realized gain on hedged item | 45 |  | — |  |  |  |

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The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
The following table presents the effect of cash flow hedges, fair value hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes:

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars) |  |  |  |  |
Amount of unrealized gain/(loss) recognized in OCI |  |  |  |  |
Cash flow hedges |  |  |  |  |
Foreign exchange contracts | (20) |  | 19 |  |  |  |
Interest rate contracts | 497 |  | (715) |  |  |  |
Commodity contracts | (8) |  | 9 |  |  |  |
Other contracts | 3 |  | (7) |  |  |  |
Fair value hedges |  |  |  |  |
Foreign exchange contracts | (1) |  | 3 |  |  |  |
Net investment hedges |  |  |  |  |
Foreign exchange contracts | — |  | (7) |  |  |  |
| 471 |  | (698) |  |  |  |
Amount of loss reclassified from AOCI to earnings |  |  |  |  |
Foreign exchange contracts 1 | 1 |  | 1 |  |  |  |
Interest rate contracts 2 | 63 |  | 43 |  |  |  |
Commodity contracts | 1 |  | — |  |  |  |
Other contracts 3 | — |  | — |  |  |  |
| 65 |  | 44 |  |  |  |

1 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
2 Reported within Interest expense in the Consolidated Statements of Earnings.
3 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
We estimate that a loss of $113 million of AOCI related to unrealized cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 33 months as at March 31, 2021.
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Non-Qualifying Derivatives
The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives:

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars) |  |  |  |  |
Foreign exchange contracts 1 | 236 |  | (2,003) |  |  |  |
Interest rate contracts 2 | 2 |  | (18) |  |  |  |
Commodity contracts 3 | 72 |  | 473 |  |  |  |
Other contracts 4 | 5 |  | (8) |  |  |  |
Total unrealized derivative fair value gain/(loss), net | 315 |  | (1,556) |  |  |  |

1 For the respective three months ended periods, reported within Transportation and other services revenues (2021 - $154 million gain; 2020 - $1,061 million loss) and Net foreign currency gain/(loss) (2021 - $82 million gain; 2020 - $942 million loss) 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 (2021 - $3 million loss; 2020 - $34 million gain), Commodity sales (2021 - $171 million gain; 2020 - $1,493 million gain), Commodity costs (2021 - $100 million loss; 2020 - $1,045 million loss) and Operating and administrative expense (2021 - $4 million gain; 2020 - $9 million loss) in the Consolidated Statements of Earnings.
4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available 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 current shelf prospectuses with securities regulators which enables ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at March 31, 2021. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.
CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.
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We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:

| March 31, 2021 | December 31, 2020
(millions of Canadian dollars) |  |
Canadian financial institutions | 617 |  | 481 |
US financial institutions | 188 |  | 99 |
European financial institutions | — |  | 28 |
Asian financial institutions | 235 |  | 167 |
Other 1 | 118 |  | 97 |
| 1,158 |  | 872 |

1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at March 31, 2021, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association agreements. We held no cash collateral on derivative asset exposures as at March 31, 2021 and December 31, 2020.
Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates, and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation.
Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Enbridge Gas Inc. (Enbridge Gas), credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers, and in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.
FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivative 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 derivative 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 derivatives 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 derivative 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.
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Level 2
Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives 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. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.
We have also categorized the fair value of our held to maturity preferred share investment and long-term debt 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.
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’ fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power, NGL and natural gas contracts, basis swaps, commodity swaps, and power and energy swaps. 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) 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.
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We have categorized our derivative assets and liabilities measured at fair value as follows:

March 31, 2021 | Level 1 | Level 2 | Level 3 | Total Gross Derivative Instruments
(millions of Canadian dollars) |  |  |  |
Financial assets |  |  |  |
Current derivative assets |  |  |  |
Foreign exchange contracts | — |  | 242 |  | — |  | 242 |
Commodity contracts | 55 |  | 37 |  | 66 |  | 158 |
Other contracts | — |  | 2 |  | — |  | 2 |
| 55 |  | 281 |  | 66 |  | 402 |
Long-term derivative assets |  |  |  |
Foreign exchange contracts | — |  | 465 |  | — |  | 465 |
Interest rate contracts | — |  | 247 |  | — |  | 247 |
Commodity contracts | 8 |  | 27 |  | 12 |  | 47 |
Other contracts | — |  | 2 |  | — |  | 2 |
| 8 |  | 741 |  | 12 |  | 761 |
Financial liabilities |  |  |  |
Current derivative liabilities |  |  |  |
Foreign exchange contracts | — |  | (249) |  | — |  | (249) |
Interest rate contracts | — |  | (240) |  | — |  | (240) |
Commodity contracts | (55) |  | (25) |  | (145) |  | (225) |
| (55) |  | (514) |  | (145) |  | (714) |
Long-term derivative liabilities |  |  |  |
Foreign exchange contracts | — |  | (543) |  | — |  | (543) |
Interest rate contracts | — |  | (102) |  | — |  | (102) |
Commodity contracts | (11) |  | (7) |  | (52) |  | (70) |
| (11) |  | (652) |  | (52) |  | (715) |
Total net financial assets/(liabilities) |  |  |  |
Foreign exchange contracts | — |  | (85) |  | — |  | (85) |
Interest rate contracts | — |  | (95) |  | — |  | (95) |
Commodity contracts | (3) |  | 32 |  | (119) |  | (90) |
Other contracts | — |  | 4 |  | — |  | 4 |
| (3) |  | (144) |  | (119) |  | (266) |

29

December 31, 2020 | Level 1 | Level 2 | Level 3 | Total Gross Derivative Instruments
(millions of Canadian dollars) |  |  |  |
Financial assets |  |  |  |
Current derivative assets |  |  |  |
Foreign exchange contracts | — |  | 180 |  | — |  | 180 |
Commodity contracts | 43 |  | 33 |  | 67 |  | 143 |
| 43 |  | 213 |  | 67 |  | 323 |
Long-term derivative assets |  |  |  |
Foreign exchange contracts | — |  | 466 |  | — |  | 466 |
Interest rate contracts | — |  | 56 |  | — |  | 56 |
Commodity contracts | 1 |  | 24 |  | 14 |  | 39 |
| 1 |  | 546 |  | 14 |  | 561 |
Financial liabilities |  |  |  |
Current derivative liabilities |  |  |  |
Foreign exchange contracts | — |  | (185) |  | — |  | (185) |
Interest rate contracts | — |  | (425) |  | — |  | (425) |
Commodity contracts | (39) |  | (18) |  | (223) |  | (280) |
Other contracts | — |  | (4) |  | — |  | (4) |
| (39) |  | (632) |  | (223) |  | (894) |
Long-term derivative liabilities |  |  |  |
Foreign exchange contracts | — |  | (760) |  | — |  | (760) |
Interest rate contracts | — |  | (241) |  | — |  | (241) |
Commodity contracts | (1) |  | (8) |  | (49) |  | (58) |
| (1) |  | (1,009) |  | (49) |  | (1,059) |
Total net financial assets/(liabilities) |  |  |  |
Foreign exchange contracts | — |  | (299) |  | — |  | (299) |
Interest rate contracts | — |  | (610) |  | — |  | (610) |
Commodity contracts | 4 |  | 31 |  | (191) |  | (156) |
Other contracts | — |  | (4) |  | — |  | (4) |
| 4 |  | (882) |  | (191) |  | (1,069) |

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

March 31, 2021 | Fair Value | Unobservable Input | Minimum Price | Maximum Price | Weighted Average Price | Unit of Measurement
(fair value in millions of Canadian dollars) |  |  |  |  |  |
Commodity contracts - financial 1 |  |  |  |  |  |
Natural gas | (6) |  | Forward gas price | 2.70 |  | 4.11 |  | 3.21 |  | $/mmbtu 2
Crude | 2 |  | Forward crude price | 51.88 |  | 74.36 |  | 62.08 |  | $/barrel
Power | (47) |  | Forward power price | 19.15 |  | 76.00 |  | 60.25 |  | $/MW/H
Commodity contracts - physical 1 |  |  |  |  |  |
Natural gas | 11 |  | Forward gas price | 2.06 |  | 5.43 |  | 3.10 |  | $/mmbtu 2
Crude | (81) |  | Forward crude price | 53.92 |  | 76.25 |  | 55.05 |  | $/barrel
NGL | 2 |  | Forward NGL price | 0.50 |  | 1.21 |  | 0.80 |  | $/gallon
| (119) |  |  |  |  |  |

1 Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2 One million British thermal units (mmbtu).
30

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

| Three months ended March 31,
| 2021 | 2020
(millions of Canadian dollars) |  |
Level 3 net derivative liability at beginning of period | (191) |  | (69) |
Total gain/(loss) |  |
Included in earnings 1 | (72) |  | 349 |
Included in OCI | (5) |  | 9 |
Settlements | 149 |  | 39 |
Level 3 net derivative (liability)/asset at end of period | (119) |  | 328 |

1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
There were no transfers into or out of Level 3 as at March 31, 2021 or December 31, 2020.
NET INVESTMENT HEDGES
We currently have designated a portion of our US dollar denominated debt, as well as a portfolio of foreign exchange forward contracts in prior periods, as a hedge of our net investment in US dollar denominated investments and subsidiaries.
During the three months ended March 31, 2021 and 2020, we recognized an unrealized foreign exchange gain of $105 million and a loss of $708 million, respectively, on the translation of US dollar denominated debt and unrealized loss of nil and $7 million, respectively, on the change in fair value of our outstanding foreign exchange forward contracts in OCI. During the three months ended March 31, 2021 and 2020, we recognized no OCI associated with the settlement of foreign exchange forward contracts or with the settlement of US dollar denominated debt that had matured during the period.
FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS
Certain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $52 million as at March 31, 2021 and December 31, 2020.
We have Restricted long-term investments held in trust totaling $529 million and $553 million as at March 31, 2021 and December 31, 2020, respectively, which are recognized at fair value.
We have a held-to-maturity preferred share investment carried at its amortized cost of $566 million and $567 million as at March 31, 2021 and December 31, 2020, respectively. These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%. The fair value of this preferred share investment is $566 million and $567 million as at March 31, 2021 and December 31, 2020, respectively.
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As at March 31, 2021 and December 31, 2020, our long-term debt had a carrying value of $67.0 billion and $66.1 billion, respectively, before debt issuance costs and a fair value of $72.5 billion and $75.1 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at March 31, 2021 and December 31, 2020, the non-current notes receivable had a carrying value of $1.0 billion and $1.1 billion, respectively, which also approximates their fair value.
The fair value of financial assets and liabilities other than derivative instruments, long-term investments, restricted long-term investments, long-term debt and non-current notes receivable described above approximate their carrying value due to the short period to maturity.
10. INCOME TAXES
The effective income tax rates for the three months ended March 31, 2021 and 2020 were 19.3% and 28.7%, respectively.
The period-over-period decrease in the effective income tax rates is due to the effect of rate-regulated accounting for income taxes and the benefit of foreign tax rate differentials relative to the change in earnings.
11. PENSION AND OTHER POSTRETIREMENT BENEFITS

| Three months ended March 31,
| 2021 | 2020
(millions of Canadian dollars) |  |
Service cost | 48 |  | 42 |
Interest cost | 32 |  | 33 |
Expected return on plan assets | (84) |  | (67) |
Amortization of actuarial loss and prior service costs | 14 |  | 9 |
Net periodic benefit costs | 10 |  | 17 |

12. CONTINGENCIES
We and our subsidiaries are involved in various legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our interim consolidated financial position or results of operations.
TAX MATTERS
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our interim consolidated financial statements and the accompanying notes included in Part I. Item 1. Financial Statements of this quarterly report on Form 10-Q and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of our annual report on Form 10-K for the year ended December 31, 2020.
As of the end of the second quarter of 2020, we continue to qualify as a foreign private issuer for purposes of the United States Securities Exchange Act of 1934, as amended (Exchange Act). 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 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
COVID-19 PANDEMIC
Since the outbreak of COVID-19 in early 2020, our business continuity plans and commercial models have been effective in enabling the continued operation of our business. Initially, the COVID-19 pandemic significantly impacted crude oil market fundamentals which resulted in elevated risks to our business. Crude oil demand experienced an unprecedented drop in mid-2020 as the economy slowed and personal mobility decreased due to government restrictions. This, in turn, led to a decrease in crude oil throughput on our liquids pipelines systems as refinery runs decreased. There has since been a substantial recovery in oil demand as vaccination rates rise and economies continue to reopen. Crude oil prices have also since stabilized, in part as a result of measured global supply management from the Organization of Petroleum Exporting Countries Plus producers.
During the first quarter of 2021, Western Canadian Sedimentary Basin heavy production returned to near recent highs to meet the demand resurgence. However, conventional light production recovery has lagged due to lack of new drilling in 2020 and weaker jet fuel demand. As a result, during the first quarter of 2021, Mainline System throughput substantially recovered to pre-pandemic levels, particularly on the heavy portion of the Mainline System. Utilization of our liquids systems, natural gas pipeline systems and natural gas utility are again relatively strong. Given the continued elevated risks that remain with the ongoing pandemic, we continue to monitor fundamental market conditions for risks to system utilization.
We continue to follow recommendations from public health authorities and medical experts, which vary by jurisdiction, and to employ regular safety processes and procedures in the normal course. Despite ongoing uncertainty as to the duration and impact of the pandemic and corresponding public health measures, our business continuity plans are designed to enable us to manage operational developments related to COVID-19 as they unfold, including those related to construction and integrity projects. We provide an essential service across North America. Our customers, and the communities where we operate, depend on us to safely and reliably provide the energy they need.
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US LINE 3 REPLACEMENT PROGRAM
Construction of the US portion of the Line 3 Replacement Project in Minnesota continues to advance on schedule utilizing industry-leading environmental protection measures and construction techniques and is over half complete. The project is expected to be completed and placed into service in the fourth quarter of 2021.
MAINLINE SYSTEM CONTRACTING
On December 19, 2019, we submitted an application to the Canada Energy Regulator (CER) to implement contracting on our Mainline System. The application for contracted and uncommitted service included the associated terms, conditions and tolls of each service, which would be offered in an open season following approval by the CER.
All active participants have completed Information Requests throughout 2020 and into 2021. The written portion of the Mainline contracting hearing before the CER has been concluded, with oral arguments set for May 19, 2021.
A replacement agreement for the Competitive Tolling Settlement (CTS) is not expected to be in place by June 30, 2021, and in accordance with the terms of the CTS the tolls at the expiry of the CTS will continue on an interim basis, subject to finalization and adjustment applicable to the interim period, if any.
GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS
East Tennessee
East Tennessee Natural Gas, LLC filed a rate case in the second quarter of 2020 and an agreement in principle was reached with shippers in April 2021.
Maritimes & Northeast Pipeline
The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an agreement in principle was reached with shippers in December 2020. A Stipulation and Agreement was filed on February 21, 2021 and approved by the Federal Energy Regulatory Commission (FERC) on April 30, 2021, to be effective June 1, 2021 if no requests for rehearings are filed.
Alliance Pipeline
The US portion of Alliance Pipeline filed a rate case in the second quarter of 2020 and an agreement in principle was reached with shippers in January 2021. A Stipulation and Agreement was filed on March 31, 2021 and we await FERC approval.
GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
2021 Rate Application
On June 30, 2020, Enbridge Gas Inc. (Enbridge Gas) filed Phase 1 of an application with the Ontario Energy Board (OEB) for the setting of rates for 2021. The 2021 rate application was filed in accordance with the parameters of Enbridge Gas's OEB approved Price Cap Incentive Regulation rate setting mechanism and represents the third year of a five-year term. On November 6, 2020, as part of its Decision on Settlement Proposal and Interim Rate Order, the OEB approved Enbridge Gas's Phase 1 Settlement Proposal and interim rates, effective January 1, 2021. Phase 2 of Enbridge Gas's application, addressing 2021 incremental capital module funding requirements, was filed on October 15, 2020.
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SOLAR SELF-POWER PROJECT
Alberta Solar One
In March 2021, we commenced commercial operations on our first self-powering solar generation facility in Alberta and our third across our enterprise. The 10.5-megawatts (MW) solar project, located near Burdett, Alberta, will supply a portion of our Canadian Mainline power requirements with solar energy.
FINANCING UPDATE
On February 10, 2021, we entered into a three year, revolving, extendible, sustainability linked credit facility for $1.0 billion with a syndicate of lenders. As a result of the sustainability linked credit facility and other financing activities completed in 2020, our resilient cash flows and our current liquidity position, we concurrently cancelled a one year, revolving, syndicated credit facility for $3.0 billion, ahead of its scheduled March 2021 maturity.
On February 19, 2021, we closed our inaugural US$500 million two-year Secured Overnight Financing Rate (SOFR) based Floating Rate Note (FRN) offering. The transaction has been reported to be the first SOFR-linked FRN offering by a non-financial issuer in the global fixed income market. Proceeds of this offering were used for repayment of two USD term loans for the equivalent aggregate amount which matured on February 25, 2021.
These financing activities, in combination with the financing activities executed in 2020, are expected to provide significant liquidity and to enable us to fund our current portfolio of capital projects without requiring access to the capital markets throughout 2021 if market access is restricted or pricing is unattractive. Refer to Liquidity and Capital Resources.
ASSET MONETIZATION
Éolien Maritime France SAS
On March 18, 2021, we sold 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to the Canada Pension Plan Investment Board (CPP Investments). CPP Investments will fund their 49% share of all ongoing future development capital. Through our investment in EMF, we own equity interests in three French offshore wind projects, including Saint-Nazaire (25.5%), Fécamp (17.9%) and Calvados (21.7%). The Calvados Offshore Wind Project reached a positive final investment decision in February 2021 and all three projects are now considered commercially secured.
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RESULTS OF OPERATIONS

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars, except per share amounts) |  |  |  |  |
Segment earnings/(loss) before interest, income taxes and depreciation and amortization |  |  |  |  |
Liquids Pipelines | 2,039 |  | 850 |  |  |  |
Gas Transmission and Midstream | 973 |  | (1,054) |  |  |  |
Gas Distribution and Storage | 634 |  | 604 |  |  |  |
Renewable Power Generation | 156 |  | 120 |  |  |  |
Energy Services | 64 |  | 121 |  |  |  |
Eliminations and Other | 220 |  | (966) |  |  |  |
Earnings before interest, income taxes and depreciation and amortization | 4,086 |  | (325) |  |  |  |
Depreciation and amortization | (932) |  | (882) |  |  |  |
Interest expense | (657) |  | (706) |  |  |  |
Income tax (expense)/recovery | (483) |  | 549 |  |  |  |
(Earnings)/loss attributable to noncontrolling interests | (22) |  | 31 |  |  |  |
Preference share dividends | (92) |  | (96) |  |  |  |
Earnings attributable to common shareholders | 1,900 |  | (1,429) |  |  |  |
Earnings/(loss) per common share attributable to common shareholders | 0.94 |  | (0.71) |  |  |  |
Diluted earnings/(loss) per common share attributable to common shareholders | 0.94 |  | (0.71) |  |  |  |

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS
Three months ended March 31, 2021, compared with the three months ended March 31, 2020
Earnings attributable to common shareholders were positively impacted by $3.4 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following factors, some of which relate to the onset of COVID-19 effects in March 2020:
•a non-cash, unrealized derivative fair value gain of $279 million ($211 million after-tax) in 2021, compared with a loss of $2.0 billion ($1.5 billion after-tax) in 2020, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks;
•the absence in 2021 of a non-cash impairment to the carrying value of our investment in DCP Midstream, LLC (DCP Midstream) of $1.7 billion ($1.3 billion after-tax) recognized in 2020;
•the absence in 2021 of a loss of $324 million ($244 million after-tax) resulting from asset and goodwill impairment losses within DCP Midstream recognized in 2020;
•the absence in 2021 of a loss of $159 million ($119 million after-tax) in 2020 resulting from the Texas Eastern Transmission, LP (Texas Eastern) rate case settlement that re-established the Excess Accumulated Deferred Income Tax (EDIT) regulated liability that was previously eliminated in December 2018; and
•the absence in 2021 of a non-cash, write-down of crude oil and natural gas inventories to the lower of cost or market in our Energy Services business segment of $342 million ($255 million after-tax) in 2020.
The positive factors above were partially offset by a non-cash, unrealized gain of $139 million ($105 million after-tax) in 2021, compared with a gain of $476 million ($355 million after-tax) in 2020, 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.
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The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of a comprehensive long-term economic hedging program to mitigate foreign exchange and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on 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 $34 million decrease in earnings attributable to common shareholders is primarily explained by the following significant business factors:
•the absence in 2021 of the recognition of revenues in 2020 from settled rates on Texas Eastern, retroactive to June 1, 2019 in our Gas Transmission and Midstream segment; and
•decreased earnings from our Energy Services segment due to the significant compression of location and quality differentials in certain markets, adverse impacts from the major winter storm experienced across the US Midwest during February 2021 and fewer opportunities to achieve profitable transportation margins on facilities in which Energy Services holds capacity obligations.
The business factors above were partially offset by increased earnings from our Gas Distribution and Storage segment due to higher distribution charges resulting from increases in rates and customer base as well as colder weather experienced in our franchise service areas in 2021 compared to 2020.
BUSINESS SEGMENTS
LIQUIDS PIPELINES

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars) |  |  |  |  |
Earnings before interest, income taxes and depreciation and amortization | 2,039 |  | 850 |  |  |  |

Three months ended March 31, 2021, compared with the three months ended March 31, 2020
Earnings before interest, income taxes and depreciation and amortization (EBITDA) was positively impacted by $1.2 billion due to non-operating, non-cash, unrealized gains of $161 million in 2021, compared with losses of $1.1 billion in 2020, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks.
After taking into consideration the factor above, the remaining $38 million decrease is primarily explained by the following significant business factors:
•lower Mainline System ex-Gretna throughput of 2.7 million barrels per day (mmbpd) in 2021 compared with 2.8 mmbpd in 2020 due to lower volume demand resulting from the COVID-19 pandemic impact on supply and demand for crude oil and related products;
•lower throughput on our Bakken Pipeline System, Seaway Crude Pipeline System and Flanagan South Pipeline driven by similar reasons we noted for the Mainline System; and
•the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average exchange rate in 2021 compared with 2020.
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The business factors above were partially offset by the following positive factors:
•a higher International Joint Tariff Benchmark Toll on our Mainline System of US$4.27 in 2021 compared with US$4.21 in 2020;
•a higher foreign exchange hedge rate used to lock-in US dollar denominated Canadian Mainline revenue;
•CTS surcharges of US$0.11 per barrel; and
•higher throughput on our Athabasca Mainline and Waupisoo pipelines.
GAS TRANSMISSION AND MIDSTREAM

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars) |  |  |  |  |
Earnings/(loss) before interest, income taxes and depreciation and amortization | 973 |  | (1,054) |  |  |  |

Three months ended March 31, 2021, compared with the three months ended March 31, 2020
EBITDA was positively impacted by $2.1 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
•the absence in 2021 of a non-cash impairment to the carrying value of our investment in DCP Midstream of $1.7 billion recognized in 2020;
•the absence in 2021 of a loss of $324 million resulting from asset and goodwill impairment losses within DCP Midstream recognized in 2020; and
•the absence in 2021 of a loss of $159 million in 2020 resulting from the Texas Eastern rate case settlement that re-established the EDIT regulated liability that was previously eliminated in December 2018.
The positive factors above were partially offset by a non-cash, negative equity earnings adjustment of $19 million in 2021 compared with a positive adjustment of $53 million in 2020 relating to changes in the mark-to-market value of derivative financial instruments of our equity method investee, DCP Midstream.
After taking into consideration the factors above, the remaining $90 million decrease is primarily explained by the following significant business factors:
•the absence in 2021 of the recognition of revenues in 2020 from settled rates on Texas Eastern, retroactive to June 1, 2019; and
•the net unfavorable effect of translating US dollar EBITDA at a lower Canadian to US dollar average exchange rate in 2021 compared to the same period in 2020.
The business factors above were partially offset by contributions from the Atlantic Bridge Phase III project that was placed into service in January 2021.
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GAS DISTRIBUTION AND STORAGE

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars) |  |  |  |  |
Earnings before interest, income taxes and depreciation and amortization | 634 |  | 604 |  |  |  |

Three months ended March 31, 2021, compared with the three months ended March 31, 2020
EBITDA was positively impacted by $30 million primarily due to the following:
•higher distribution charges resulting from increases in rates and customer base;
•when compared with the normal weather forecast embedded in rates, weather was warmer in both 2021 and 2020, negatively impacting EBITDA in both years. Warmer than normal weather in 2021 negatively impacted 2021 EBITDA by approximately $24 million while the warmer than normal weather in 2020 negatively impacted 2020 EBITDA by approximately $41 million; and
•higher storage revenue, mainly relating to storage optimization activities.
RENEWABLE POWER GENERATION

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars) |  |  |  |  |
Earnings before interest, income taxes and depreciation and amortization | 156 |  | 120 |  |  |  |

Three months ended March 31, 2021, compared with the three months ended March 31, 2020
EBITDA was positively impacted by $36 million primarily due to the following:
•the sale of a 49% interest of an entity that holds our 50% interest in EMF; and
•stronger wind production at certain offshore wind facilities.
The positive business factors above were partially offset by the following:
•lower wind resources at the Canadian and US wind facilities and the effects from the winter storm in Texas during February 2021.
ENERGY SERVICES

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars) |  |  |  |  |
Earnings before interest, income taxes and depreciation and amortization | 64 |  | 121 |  |  |  |

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.
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Three months ended March 31, 2021, compared with the three months ended March 31, 2020
EBITDA was positively impacted by $5 million due to certain unusual or other non-operating factors, explained by the absence in 2021 of a net negative adjustment to crude oil and natural gas inventories of $342 million in 2020.
The factor above was partially offset by a non-cash, unrealized gain of $139 million in 2021, compared with a gain of $476 million in 2020, 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.
After taking into consideration the factors above, the remaining $62 million decrease is primarily explained by the following:
•the significant compression of location and quality differentials in certain markets;
•adverse impacts from the major winter storm experienced across the US Midwest during February 2021; and
•fewer opportunities to achieve profitable transportation margins on facilities in which Energy Services holds capacity obligations.
ELIMINATIONS AND OTHER

| Three months ended March 31, |  |
| 2021 | 2020 |  |  |
(millions of Canadian dollars) |  |  |  |  |
Earnings/(loss) before interest, income taxes and depreciation and amortization | 220 |  | (966) |  |  |  |

Eliminations and Other includes operating and administrative costs and the impact of foreign exchange hedge settlements, which are not allocated to business segments. Eliminations and Other also includes the impact of new business development activities and corporate investments.
Three months ended March 31, 2021, compared with the three months ended March 31, 2020
EBITDA was positively impacted by $1.1 billion due to certain unusual, infrequent and other non-operating factors, primarily explained by the following:
•a non-cash, unrealized gain of $109 million in 2021, compared with a loss of $898 million in 2020, reflecting the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;
•the absence in 2021 of a loss of $74 million in 2020 from non-cash changes in a corporate guarantee obligation; and
•the absence in 2021 of a loss of $43 million in 2020 from the write-down of certain investments in emerging energy and other technologies.
After taking into consideration the factors above, the remaining $97 million increase is primarily explained by realized gains related to settlements under our enterprise-wide foreign exchange risk management program which substantially offset the foreign currency exposures realized within our business segments' results.
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GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS
The following table summarizes the status of our commercially secured projects, organized by business segment:

|  | Enbridge's Ownership Interest | Estimated Capital Cost 1 | Expenditures to Date 2 | Status | Expected In-Service Date
(Canadian dollars, unless stated otherwise) |  |  |  |
LIQUIDS PIPELINES |  |  |  |
1. | US Line 3 Replacement Program | 100 | % | US$4.0 billion | US$2.8 billion | Under construction | Q4 - 2021
2. | Southern Access Expansion 3 | 100 | % | US$0.5 billion | US$0.5 billion | Under construction | Q4 - 2021
3. | Other - US | 100 | % | US$0.1 billion | US$0.1 billion | Under construction | Q3 - 2021
GAS TRANSMISSION AND MIDSTREAM |  |  |  |
4. | T-South Reliability & Expansion Program | 100 | % | $1.0 billion | $0.8 billion | Under construction | Q4 - 2021
5. | Spruce Ridge Project | 100 | % | $0.5 billion | $0.3 billion | Under construction | Q4 - 2021
6. | Other - US | Various | US$0.8 billion | US$0.3 billion | Various stages | 2021 - 2023
GAS DISTRIBUTION AND STORAGE |  |  |  |
7. | London Line Replacement Project | 100 | % | $0.2 billion | No significant expenditures to date | Pre-construction | Q4 - 2021
8. | Storage Enhancements | 100 | % | $0.1 billion | No significant expenditures to date | Pre-construction | 2021 - 2022
RENEWABLE POWER GENERATION |  |
9. | East-West Tie Line | 25.0 | % | $0.2 billion | $0.1 billion | Under construction | 1H - 2022
10. | Saint-Nazaire France Offshore Wind Project 4 | 25.5 | % | $0.9 billion | $0.3 billion | Under construction | 2H - 2022
(€0.6 billion) | (€0.2 billion)
11. | Fécamp Offshore Wind Project 5 | 17.9 | % | $0.7 billion | $0.2 billion | Under construction | 2023
(€0.5 billion) | (€0.1 billion)
12. | Calvados Offshore Wind Project 6 | 21.7 | % | $0.9 billion | No significant expenditures to date | Under construction | 2024
(€0.6 billion)

1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.
2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to March 31, 2021.
3 The status and in-service date will coincide with the status and in-service date of the US L3R Program.
4 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first quarter of 2021. Our equity contribution is $0.15 billion, with the remainder of the project financed through non-recourse project level debt.
5 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first quarter of 2021. Our equity contribution is $0.10 billion, with the remainder of the project financed through non-recourse project level debt.
6 Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first quarter of 2021. The project is primarily financed through non-recourse project level debt.
A full description of each of our projects is provided in our annual report on Form 10-K. Significant updates that have occurred since the date of filing are discussed below.
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RENEWABLE POWER GENERATION
•Calvados Offshore Wind Project – an offshore wind project located off the northwest coast of France that is expected to generate approximately 448 MW. Project revenues are underpinned by a 20-year fixed price power purchase agreement.
During the first quarter of 2021, we sold 49% of an entity that holds our 50% interest in EMF to CPP Investments. EMF holds equity interests in the Fécamp Offshore Wind Project, the Saint-Nazaire France Offshore Wind Project and the Calvados Offshore Wind Project. CPP Investments will fund their 49% share of all ongoing future development capital.
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:
GAS TRANSMISSION AND MIDSTREAM
•Rio Bravo Pipeline - the Rio Bravo Pipeline is designed to transport up to 4.5 billion cubic feet per day of natural gas from the Agua Dulce supply area to NextDecade's Rio Grande LNG export facility in the Port of Brownsville, Texas. We have acquired the Rio Bravo Pipeline development project from NextDecade. In addition, we have executed a precedent agreement with NextDecade under which we will provide firm transportation capacity on the Rio Bravo Pipeline to NextDecade's Rio Grande LNG export facility for a term of at least 20 years. Construction of the pipeline will be subject to the Rio Grande LNG export facility reaching a final investment decision which is forecasted to occur in the second half of 2021.
•Annova LNG - we had executed an agreement to provide natural gas transportation services to supply the 6.5 million tonnes per annum to the Annova LNG export facility in the Port of Brownsville, Texas for a term of at least 20 years, by expanding our existing Valley Crossing system. However, in the first quarter of 2021 Annova announced that it will not be proceeding with the project citing changes in the global LNG market as the reason for terminating the project.
We also have a portfolio of additional projects under development that have not yet progressed to the point of securement.
LIQUIDITY AND CAPITAL RESOURCES
The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control, including but not limited to financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to help ensure we maintain sufficient liquidity to meet routine operating and future capital requirements. In the near term, we generally expect to utilize cash from operations together with commercial paper issuance and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures, fund debt retirements 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.
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Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives.
CAPITAL MARKET ACCESS
We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for 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, 2021:

| Maturity 1 | Total Facilities | Draws 2 | Available
(millions of Canadian dollars) |  |  |  |
Enbridge Inc. | 2022-2024 | 9,159 |  | 7,390 |  | 1,769 |
Enbridge (U.S.) Inc. | 2022-2024 | 6,913 |  | 3,351 |  | 3,562 |
Enbridge Pipelines Inc. | 2022 | 3,000 |  | 1,358 |  | 1,642 |
Enbridge Gas Inc. | 2022 | 2,000 |  | 1,094 |  | 906 |
Total committed credit facilities |  | 21,072 |  | 13,193 |  | 7,879 |

1 Maturity date is inclusive of the one-year term out option for certain credit facilities.
2 Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
On February 10, 2021, Enbridge Inc. entered into a three year, revolving, extendible, sustainability linked credit facility for $1.0 billion with a syndicate of lenders and concurrently terminated our one year, revolving, syndicated credit facility for $3.0 billion.
On February 25, 2021, two term loans with an aggregate total of US$500 million were repaid with proceeds from a floating rate notes issuance.
In addition to the committed credit facilities noted above, we maintain $845 million of uncommitted demand credit facilities, of which $595 million was unutilized as at March 31, 2021. As at December 31, 2020, we had $849 million of uncommitted demand credit facilities, of which $533 million was unutilized.
Our net available liquidity of $8.3 billion as at March 31, 2021, was inclusive of $465 million of unrestricted cash and cash equivalents as reported in the Consolidated Statements of Financial Position.
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2021, we were in compliance with all debt covenants and we expect to continue to comply with such covenants.
LONG-TERM DEBT ISSUANCE
During the three months ended March 31, 2021, we completed the following long-term debt issuance totaling US$500 million:

Company | Issue Date |  |  | Principal Amount
(millions of Canadian dollars unless otherwise stated) |  |
Enbridge Inc. |  |  |
| February 2021 | Floating rate notes due February 2023 1 | US$500

1 Notes mature in two years and carry an interest rate set to equal SOFR plus a margin of 40 basis points.
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LONG-TERM DEBT REPAYMENTS
During the three months ended March 31, 2021, we completed the following long-term debt repayments totaling $600 million and US$250 million:

Company | Repayment Date |  |  | Principal Amount |
(millions of Canadian dollars unless otherwise stated) |  |  |
Enbridge Inc. |  |  |
| February 2021 | 4.26% medium-term notes |  | $200 |
| March 2021 | 3.16% medium-term notes | $400 |
Spectra Energy Partners, LP |  |  |
| March 2021 | 4.60% senior notes |  | US$250 |

Strong internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA.
There are no material restrictions on our cash. Total restricted cash of $59 million, as reported on the Consolidated Statements of Financial Position, primarily includes cash collateral and future pipeline abandonment costs collected and held in trust. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us.
Excluding current maturities of long-term debt, we had a negative working capital position as at March 31, 2021. The major contributing factor to the negative working capital position was the ongoing funding of our growth capital program.
To address this negative working capital position, we maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due.
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SOURCES AND USES OF CASH

|  |  | Three months ended March 31,
|  |  |  | 2021 | 2020
(millions of Canadian dollars) |  |  |  |  |
Operating activities |  |  |  | 2,564 |  | 2,809 |
Investing activities |  |  |  | (1,958) |  | (1,270) |
Financing activities |  |  |  | (565) |  | (1,386) |
Effect of translation of foreign denominated cash and cash equivalents and restricted cash |  |  |  | (7) |  | 11 |
Net increase in cash and cash equivalents and restricted cash |  |  |  | 34 |  | 164 |

Significant sources and uses of cash for the three months ended March 31, 2021 and 2020 are summarized below:
Operating Activities
The decrease in cash provided by operating activities was primarily attributable to changes in operating assets and liabilities. 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 our business segments, the timing of tax payments, as well as timing of cash receipts and payments generally.
Investing Activities
•The increase in cash used in investing activities was primarily attributable to proceeds received from disposition of 49% of our interest in EMF to CPP Investments in the first quarter of 2021.
•We are continuing with the execution of our growth capital program which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.
Financing Activities
•The decrease in cash used in financing activities was primarily attributable to a decrease in repayments of long-term debt and an increase in commercial paper and credit facility draws.
•The factors above were partially offset by a decrease in issuances of long-term debt.
•Our common share dividend payments increased period-over-period primarily due to the increase in our common share dividend rate.
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SUMMARIZED FINANCIAL INFORMATION
On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP) (the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes.
Consenting SEP notes and EEP notes under Guarantee

SEP Notes 1 | EEP Notes 2
4.750% Senior Notes due 2024 | 4.200% Notes due 2021
3.500% Senior Notes due 2025 | 5.875% Notes due 2025
3.375% Senior Notes due 2026 | 5.950% Notes due 2033
5.950% Senior Notes due 2043 | 6.300% Notes due 2034
4.500% Senior Notes due 2045 | 7.500% Notes due 2038
| 5.500% Notes due 2040
| 7.375% Notes due 2045

1 As at March 31, 2021, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.
2 As at March 31, 2021, the aggregate outstanding principal amount of EEP notes was approximately US$3.0 billion.
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Enbridge Notes under Guarantees

USD Denominated 1 | CAD Denominated 2
Floating Rate Senior Notes due 2022 | 4.850% Senior Notes due 2022
Floating Rate Senior Notes due 2023 | 3.190% Senior Notes due 2022
2.900% Senior Notes due 2022 | 3.940% Senior Notes due 2023
4.000% Senior Notes due 2023 | 3.940% Senior Notes due 2023
3.500% Senior Notes due 2024 | 3.950% Senior Notes due 2024
2.500% Senior Notes due 2025 | 2.440% Senior Notes due 2025
4.250% Senior Notes due 2026 | 3.200% Senior Notes due 2027
3.700% Senior Notes due 2027 | 6.100% Senior Notes due 2028
3.125% Senior Notes due 2029 | 2.990% Senior Notes due 2029
4.500% Senior Notes due 2044 | 7.220% Senior Notes due 2030
5.500% Senior Notes due 2046 | 7.200% Senior Notes due 2032
4.000% Senior Notes due 2049 | 5.570% Senior Notes due 2035
| 5.750% Senior Notes due 2039
| 5.120% Senior Notes due 2040
| 4.240% Senior Notes due 2042
| 4.570% Senior Notes due 2044
| 4.870% Senior Notes due 2044
| 4.560% Senior Notes due 2064

1 As at March 31, 2021, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$8 billion.
2 As at March 31, 2021, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.7 billion.
The following Summarized Combined Statement of Earnings and the Summarized Combined Statements of Financial Position combines the balances of EEP, SEP and Enbridge Inc.
Summarized Combined Statement of Earnings

| Three months ended
| March 31, 2021
(millions of Canadian dollars) |
Operating income | 13 |
Earnings | 916 |
Earnings attributable to common shareholders | 824 |

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Summarized Combined Statements of Financial Position

|  | March 31, 2021 |  | December 31, 2020
(millions of Canadian dollars) |  |  |  |
Accounts receivable from affiliates |  | 2,154 |  |  | 2,108 |
Short-term loans receivable from affiliates |  | 4,915 |  |  | 4,926 |
Other current assets |  | 310 |  |  | 375 |
Long-term loans receivable from affiliates |  | 44,180 |  |  | 43,217 |
Other long-term assets |  | 4,177 |  |  | 4,237 |
Accounts payable to affiliates |  | 1,587 |  |  | 1,267 |
Short-term loans payable to affiliates |  | 4,360 |  |  | 4,117 |
Other current liabilities |  | 4,587 |  |  | 5,628 |
Long-term loans payable to affiliates |  | 35,320 |  |  | 32,035 |
Other long-term liabilities |  | 38,052 |  |  | 41,353 |

The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-Guarantors.
Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee:
•received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;
•was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
•intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.
The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under US federal or state law.
Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.
Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:
•any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;
•the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;
•the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement;
•with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;
•with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or
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•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.
LEGAL AND OTHER UPDATES
LIQUIDS PIPELINES
Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement
In 2019, the Michigan Attorney General filed a complaint in the Michigan Ingham County Circuit Court (the Court) that requests the 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 “as soon as possible after a reasonable notice period to allow orderly adjustments by affected parties”. Ruling on the motions is currently being held in abeyance by the Court pending further developments in the Federal Court cases described below.
On November 13, 2020, the Governor of Michigan and the Director of the Michigan Department of Natural Resources notified us that the State of Michigan (the State) was revoking and terminating the easement granted in 1953 that allows Line 5 to operate across the Straits. The notice demands that the portion of Line 5 that crosses the Straits must be shut down by May 2021. On November 24, 2020, we filed in the US District Court for the Western District of Michigan a Notice of Removal, which removed the State’s November Complaint to Federal Court and a Complaint for Declaratory and Injunctive Relief that requests the US District Court to enjoin the Governor from taking any action to prevent or impede the operation of Line 5. On February 18, 2021, the Judge ruled that the motion to remand back to State Court will be briefed and decided first. Parties were also ordered to collaborate and identify a facilitative mediator. Accordingly, retired US District Court Judge Gerald Rosen was chosen to act as mediator and mediation is underway.
On January 12, 2021, we responded to the Governor’s Notice of Revocation and Termination of Easement. On February 11, 2021, we sent a further letter to the Department of Natural Resources regarding our rights under the easement and renewing the request to meet and have technical discussions to better understand the State’s concerns. We will vigorously defend our ability to operate Line 5 under the 1953 easement in pending Court actions.
In March 2021, we completed the engineering and design phase of the Great Lakes Tunnel Project and we will now proceed with the process of hiring a contractor to construct the tunnel. We are actively pursuing state and federal regulatory permits from the US Army Corps of Engineers’ (Army Corps), the Michigan Department of Environment, Great Lakes & Energy (EGLE) and the Michigan Public Service Commission. The EGLE permits were granted in the first quarter of 2021 and the other permitting review processes are anticipated to continue throughout 2021.
Dakota Access Pipeline
We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of the Dakota Access Pipeline (DAPL). As previously reported, the Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed motions in 2017 with the US Court for the District of Columbia (the District Court) contesting the lawfulness of the (Army Corps) easement for DAPL, including the adequacy of the Army Corps’ environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018.
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On June 14, 2017, the District Court found the Army Corps’ environmental review to be deficient and ordered the Army Corps to conduct further study concerning spill risks from DAPL. In August 2018, the Army Corps completed on remand the further environmental review ordered by the District Court and reaffirmed the issuance of the easement for DAPL. All four plaintiff Tribes subsequently amended their complaints to include claims challenging the adequacy of the Army Corps’ August 2018 remand decision.
On March 25, 2020, in response to amended complaints from the Tribes, the District Court found the Army Corps’ environmental review on remand was deficient and ordered the Army Corps to prepare an Environmental Impact Statement (EIS) to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July 6, 2020, the District Court issued an order vacating the Army Corps’ easement for DAPL and ordering that the pipeline be shut down by August 5, 2020. Dakota Access, LLC and the Army Corps appealed the decision and filed a motion for a stay pending appeal with the US Court of Appeals for the D.C. Circuit. On August 5, 2020, the US Court of Appeals stayed the District Court’s July 6 order to shut down and empty the pipeline, but did not stay the District Court’s March 25 order requiring the Army Corps to prepare an EIS or the District Court’s July 6 order vacating the DAPL easement.
On January 26, 2021, the US Court of Appeals affirmed the District Court’s decision, holding that the Army Corps is required to prepare an EIS and that the Army Corps’ easement for DAPL is vacated. The US Court of Appeals also determined that, absent considering the closure of DAPL in the context of an injunction proceeding, the District Court could not order DAPL’s operations to cease. While not an issue before the US Court of Appeals, the US Court of Appeals also recognized that the Army Corps could consider whether to allow DAPL to continue to operate in the absence of an easement.
In the District Court, the plaintiff Tribes’ motions remain pending for an injunction enjoining DAPL from operating until the Army Corps has completed its EIS and reissued the DAPL easement. Both Dakota Access, LLC and the Army Corps filed briefs in opposition to the Tribes’ request for an injunction. On April 9, 2021, at a hearing before the District Court, the Army Corps indicated that it does not intend, at this time, to exercise its authority to bar DAPL’s continued operation, notwithstanding the absence of an easement. All briefing before the District Court on whether DAPL operations should be enjoined is now complete. On May 3, 2021, in response to the District Court’s request for a status update, the Army Corps advised the court, among other things, that it anticipates completing its EIS by March 2022. The District Court may issue a decision on the injunction request at any time.
OTHER LITIGATION
We and our subsidiaries are involved in various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.
CAPITAL EXPENDITURE COMMITMENTS
We have signed contracts for the purchase of services, pipe and other materials totaling approximately $2.8 billion 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
Refer to Part I. Item 1. Financial Statements - Note 2. Changes in Accounting Policies.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our annual report on Form 10-K for the year ended December 31, 2020. We believe our exposure to market risk has not changed materially since then.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as at March 31, 2021, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.
Changes in Internal Control over Financial Reporting
Under the supervision 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, 2021 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
We are involved in various legal and regulatory actions and proceedings which arise in the ordinary course of business. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations. Refer to Part I. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of other legal proceedings.
ITEM 1A. RISK FACTORS
In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. Risk Factors of our annual report on Form 10-K for the year ended December 31, 2020, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
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ITEM 6. EXHIBITS
Each exhibit identified below is included as a part of this quarterly report. Exhibits included in this filing are designated by an asterisk (“*”); all exhibits not so designated are incorporated by reference to a prior filing as indicated.

Exhibit No. |  | Description
10.1* |  | Form of Enbridge Inc. 2019 Long Term Incentive Plan Stock Option Grant Notice and Stock Option Award Agreement (2021)
10.2* |  | Form of Enbridge Inc. 2019 Long Term Incentive Plan Performance Stock Unit Grant Notice and Performance Stock Unit Award Agreement (2021)
10.3* |  | Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement (2021 Share-settled)
10.4* |  | Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement (2021 Cash-settled)
10.5* |  | Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit - Energy Marketers Grant Notice and Restricted Stock Unit Award Agreement (2021)
10.6* |  | Enbridge Inc. Directors’ Compensation Plan dated February 9, 2021, effective April 1, 2021
22.1* |  | Subsidiary Guarantors
31.1* |  | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* |  | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1* |  | Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2* |  | Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS* |  | 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)

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

|  | ENBRIDGE INC.
|  | (Registrant)
Date: | May 7, 2021 | By: | /s/ Al Monaco
|  | Al Monaco President and Chief Executive Officer
|  |  | (Principal Executive Officer)
Date: | May 7, 2021 | By: | /s/ Colin K. Gruending
|  |  | Colin K. Gruending Executive Vice President and Chief Financial Officer
|  |  | (Principal Financial Officer)

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