Enbridge (ENB) 10-K 11 Feb 22 2021 FY Annual report Financial data

Cover

Cover - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2021	Feb. 04, 2022	Jun. 30, 2021
Entity Listings [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-10934
Entity Registrant Name	ENBRIDGE INC
Entity Incorporation, State or Country Code	Z4
Entity Tax Identification Number	98-0377957
Entity Address, Address Line One	200, 425 - 1st Street S.W.
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Country	CA
Entity Address, Postal Zip Code	T2P 3L8
City Area Code	403
Local Phone Number	231-3900
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 77.7
Entity Common Stock, Shares Outstanding		2,026,274,277
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE: Not applicable.
Entity Central Index Key	0000895728
Document Fiscal Year Focus	2021
Amendment Flag	false
Document Fiscal Period Focus	FY
Common Shares
Entity Listings [Line Items]
Title of 12(b) Security	Common Shares
Trading Symbol	ENB
Security Exchange Name	NYSE
6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078
Entity Listings [Line Items]
Title of 12(b) Security	6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078
Trading Symbol	ENBA
Security Exchange Name	NYSE

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Firm ID	271
Auditor Location	Calgary, Canada

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating revenues
Total operating revenues	$ 47,071	$ 39,087	$ 50,069
Operating expenses
Operating and administrative	6,712	6,749	6,991
Depreciation and amortization	3,852	3,712	3,391
Impairment of long-lived assets	0	0	423
Total operating expenses	39,266	31,130	41,809
Operating income	7,805	7,957	8,260
Income from equity investments (Note 13)	1,711	1,136	1,503
Impairment of equity investments (Note 13)	(111)	(2,351)	0
Other income/(expense)
Net foreign currency gain	286	181	477
Gain/(loss) on dispositions	319	(17)	(300)
Other	374	74	258
Interest expense (Note 18)	(2,655)	(2,790)	(2,663)
Earnings before income taxes	7,729	4,190	7,535
Income tax expense (Note 25)	(1,415)	(774)	(1,708)
Earnings	6,314	3,416	5,827
Earnings attributable to noncontrolling interests	(125)	(53)	(122)
Earnings attributable to controlling interests	6,189	3,363	5,705
Preference share dividends	(373)	(380)	(383)
Earnings attributable to common shareholders	$ 5,816	$ 2,983	$ 5,322
Earnings/(loss) per common share attributable to common shareholders (in CAD per share)	$ 2.87	$ 1.48	$ 2.64
Diluted earnings/(loss) per common share attributable to common shareholders (in CAD per share)	$ 2.87	$ 1.48	$ 2.63
Commodity sales
Operating revenues
Total operating revenues	$ 26,873	$ 19,259	$ 29,309
Operating expenses
Operating costs	26,608	18,890	28,802
Gas distribution revenue
Operating revenues
Total operating revenues	4,026	3,663	4,205
Operating expenses
Operating costs	2,094	1,779	2,202
Transportation and other services
Operating revenues
Total operating revenues	$ 16,172	$ 16,165	$ 16,555

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Earnings	$ 6,314	$ 3,416	$ 5,827
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	162	(457)	(437)
Change in unrealized gain on net investment hedges	49	102	281
Other comprehensive income/(loss) from equity investees	(12)	(1)	40
Excluded components of fair value hedges	(5)	5	0
Reclassification to earnings of loss on cash flow hedges	235	198	127
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	21	13	13
Reclassification to earnings of gain on equity investees	(62)	0	0
Actuarial gain/(loss) on pension and OPEB	394	(167)	(96)
Foreign currency translation adjustments	(507)	(853)	(3,035)
Other comprehensive income/(loss), net of tax	275	(1,160)	(3,107)
Comprehensive income	6,589	2,256	2,720
Comprehensive income attributable to noncontrolling interests	(95)	(22)	(7)
Comprehensive income attributable to controlling interests	6,494	2,234	2,713
Preference share dividends	(373)	(380)	(383)
Comprehensive income attributable to common shareholders	$ 6,121	$ 1,854	$ 2,330

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - CAD ($) $ in Millions	Total	Preference shares (Note 21)	Common Shares	Additional paid-in capital	Deficit	DeficitModified retrospective adoption of ASC	Accumulated other comprehensive income/(loss) (Note 23)	Reciprocal shareholding	Total Enbridge Inc. shareholders’ equity	Noncontrolling interests (Note 20)
Balance at beginning of year at Dec. 31, 2018		$ 7,747	$ 64,677	$ 0	$ (5,538)		$ 2,672	$ (88)		$ 3,965
Increase (Decrease) in Stockholders' Equity
Shares issued on exercise of stock options			69	(61)
Stock-based compensation				34
Repurchase of noncontrolling interest				65
Change in reciprocal interest				117
Other				32
Earnings/(loss) attributable to controlling interests	$ 5,705				5,705
Preference share dividends					(383)
Common share dividends declared					(6,125)
Dividends paid to reciprocal shareholder					18
Accounting Standards Update [Extensible List]	Accounting Standards Update 2016-13 [Member]
Other					9		48
Other comprehensive income/(loss) attributable to common shareholders, net of tax							(2,992)
Change in reciprocal interest								37
Earnings attributable to noncontrolling interests										122
Change in unrealized loss on cash flow hedges										(7)
Foreign currency translation adjustments										(108)
Redemption of noncontrolling interests										(300)
Other comprehensive loss attributable to noncontrolling interests, net of tax										(115)
Comprehensive income attributable to noncontrolling interests										7
Distributions										(254)
Contributions										12
Repurchase of noncontrolling interest	$ (300)									(65)
Other										(1)
Balance at end of year at Dec. 31, 2019	$ 69,407	7,747	64,746	187	(6,314)		(272)	(51)	$ 66,043	3,364
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in CAD per share)	$ 2.95
Shares issued on exercise of stock options			22	(21)
Stock-based compensation				30
Repurchase of noncontrolling interest				0
Change in reciprocal interest				76
Other				5
Earnings/(loss) attributable to controlling interests	$ 3,363				3,363
Preference share dividends					(380)
Common share dividends declared					(6,612)
Dividends paid to reciprocal shareholder					17
Other					(3)		0
Other comprehensive income/(loss) attributable to common shareholders, net of tax							(1,129)
Change in reciprocal interest								22
Earnings attributable to noncontrolling interests										53
Change in unrealized loss on cash flow hedges										(6)
Foreign currency translation adjustments										(25)
Redemption of noncontrolling interests										(112)
Other comprehensive loss attributable to noncontrolling interests, net of tax										(31)
Comprehensive income attributable to noncontrolling interests										22
Distributions										(300)
Contributions										23
Repurchase of noncontrolling interest										0
Other										(1)
Balance at end of year at Dec. 31, 2020	$ 64,363	$ 7,747	64,768	277	(9,995)	$ (66)	(1,401)	(29)	61,367	2,996
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in CAD per share)	$ 3.24
Shares issued on exercise of stock options			31	(23)
Stock-based compensation				28
Repurchase of noncontrolling interest				0
Change in reciprocal interest				98
Other				(15)
Earnings/(loss) attributable to controlling interests	$ 6,189				6,189
Preference share dividends					(373)
Common share dividends declared					(6,818)
Dividends paid to reciprocal shareholder					8
Other					0		0
Other comprehensive income/(loss) attributable to common shareholders, net of tax							305
Change in reciprocal interest								29
Earnings attributable to noncontrolling interests										125
Change in unrealized loss on cash flow hedges										(15)
Foreign currency translation adjustments										(15)
Redemption of noncontrolling interests										(293)
Other comprehensive loss attributable to noncontrolling interests, net of tax										(30)
Comprehensive income attributable to noncontrolling interests										95
Distributions										(271)
Contributions										15
Repurchase of noncontrolling interest										0
Other										0
Balance at end of year at Dec. 31, 2021	$ 63,368		$ 64,799	$ 365	$ (10,989)		$ (1,096)	$ 0	$ 60,826	$ 2,542
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in CAD per share)	$ 3.34

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating activities
Earnings	$ 6,314	$ 3,416	$ 5,827
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	3,852	3,712	3,391
Deferred income tax expense (Note 25)	1,091	447	1,156
Unrealized derivative fair value gain, net (Note 24)	(173)	(756)	(1,751)
Income from equity investments	(1,711)	(1,136)	(1,503)
Distributions from equity investments	1,630	1,392	1,804
Impairment of long-lived assets	0	0	423
Impairment of equity investments	111	2,351	0
(Gain)/loss on dispositions	(319)	(6)	254
Other	77	268	56
Changes in operating assets and liabilities (Note 28)	(1,616)	93	(259)
Net cash provided by operating activities	9,256	9,781	9,398
Investing activities
Capital expenditures	(7,818)	(5,405)	(5,492)
Long-term investments and restricted long-term investments	(640)	(487)	(1,159)
Distributions from equity investments in excess of cumulative earnings	533	705	417
Additions to intangible assets	(275)	(215)	(200)
Acquisitions	(3,785)	(24)	0
Proceeds from dispositions	1,263	265	2,110
Affiliate loans, net	65	(16)	(314)
Other	0	0	(20)
Net cash used in investing activities	(10,657)	(5,177)	(4,658)
Financing activities
Net change in short-term borrowings	394	223	(127)
Net change in commercial paper and credit facility draws	2,960	1,542	825
Debenture and term note issues, net of issue costs	8,032	5,230	6,176
Debenture and term note repayments	(2,264)	(4,463)	(4,668)
Contributions from noncontrolling interests	15	23	12
Distributions to noncontrolling interests	(271)	(300)	(254)
Common shares issued	5	5	18
Preference share dividends	(367)	(380)	(383)
Common share dividends	(6,766)	(6,560)	(5,973)
Redemption of preferred shares held by subsidiary (Note 20)	(415)	0	(300)
Other	(87)	(90)	(71)
Net cash provided by/(used in) financing activities	1,236	(4,770)	(4,745)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	(5)	(20)	44
Net increase/(decrease) in cash and cash equivalents and restricted cash	(170)	(186)	39
Cash and cash equivalents and restricted cash at beginning of year	490	676	637
Cash and cash equivalents and restricted cash at end of year	320	490	676
Supplementary cash flow information
Cash paid for income taxes	489	524	571
Cash paid for interest, net of amount capitalized	2,427	2,538	2,738
Property, plant and equipment non-cash accruals	$ 831	$ 801	$ 730

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) shares in Millions, $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents	$ 286	$ 452
Restricted cash	34	38
Accounts receivable and other (Note 9)	6,862	5,258
Accounts receivable from affiliates	107	66
Inventory (Note 10)	1,670	1,536
Current assets	8,959	7,350
Property, plant and equipment, net (Note 11)	100,067	94,571
Long-term investments (Note 13)	13,324	13,818
Restricted long-term investments (Note 14)	630	553
Deferred amounts and other assets	8,613	8,446
Intangible assets, net (Note 15)	4,008	2,080
Goodwill (Note 16)	32,775	32,688
Deferred income taxes (Note 25)	488	770
Total assets	168,864	160,276
Current liabilities
Short-term borrowings (Note 18)	1,515	1,121
Accounts payable and other (Note 17)	9,767	9,228
Accounts payable to affiliates	90	22
Interest payable	693	651
Current portion of long-term debt (Note 18)	6,164	2,957
Current liabilities	18,229	13,979
Long-term debt (Note 18)	67,961	62,819
Other long-term liabilities	7,617	8,783
Deferred income taxes (Note 25)	11,689	10,332
Liabilities	105,496	95,913
Commitments and contingencies (Note 30)
Share capital (Note 21)
Preference shares	7,747	7,747
Common shares (2,026 outstanding at December 31, 2021 and 2020)	64,799	64,768
Additional paid-in capital	365	277
Deficit	(10,989)	(9,995)
Accumulated other comprehensive loss (Note 23)	(1,096)	(1,401)
Reciprocal shareholding	0	(29)
Total Enbridge Inc. shareholders’ equity	60,826	61,367
Noncontrolling interests (Note 20)	2,542	2,996
Equity	63,368	64,363
Total liabilities and equity	$ 168,864	$ 160,276
Common shares, outstanding (in shares)	2,026	2,026

CONSOLIDATED STATEMENTS OF FI_2

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	2,026	2,026

BUSINESS OVERVIEW

BUSINESS OVERVIEW	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BUSINESS OVERVIEW	BUSINESS OVERVIEW The terms "we," "our," "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge. Enbridge is a publicly traded energy transportation and distribution company. We conduct our business through five business segments: Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation, and Energy Services. These reporting segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance. LIQUIDS PIPELINES Liquids Pipelines consists of pipelines and terminals in Canada and the United States (US) that transport various grades of crude oil and other liquid hydrocarbons, including the Mainline System, Regional Oil Sands System, Gulf Coast and Mid-Continent, Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and Other. This segment also includes Moda Midstream Operating, LLC (Moda) which was acquired on October 12, 2021 (Note 8) and is a component of Gulf Coast and Mid-Continent. GAS TRANSMISSION AND MIDSTREAM Gas Transmission and Midstream consists of our investments in natural gas pipelines and gathering and processing facilities in Canada and the US, including US Gas Transmission, Canadian Gas Transmission, US Midstream and Other. GAS DISTRIBUTION AND STORAGE Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge Gas Inc. (Enbridge Gas), which serves residential, commercial and industrial customers located throughout Ontario. This business segment also includes natural gas distribution activities in Québec and an investment in Noverco Inc. (Noverco). We sold our investment in Noverco to Trencap L.P. on December 30, 2021 (Note 13) . RENEWABLE POWER GENERATION Renewable Power Generation consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery and transmission assets. In North America, assets are primarily located in the provinces of Alberta, Saskatchewan, Ontario and Québec, and in the states of Colorado, Texas, Indiana and West Virginia. We also have offshore wind assets in operation and under development in the United Kingdom, Germany and France. ENERGY SERVICES Our Energy Services businesses in Canada and the US undertake physical commodity marketing activity and logistical services to manage our volume commitments on various pipeline systems. Energy Services also provides energy marketing services to North American refiners, producers and other customers. ELIMINATIONS AND OTHER In addition to the business segments noted above, Eliminations and Other includes operating and administrative costs that are not allocated to business segments as well as a foreign exchange hedging program. Eliminations and Other also includes new business development activities and corporate investments.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
SIGNIFICANT ACCOUNTING POLICIES	SIGNIFICANT ACCOUNTING POLICIES These consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (US GAAP). Amounts are stated in Canadian dollars unless otherwise noted. As a Securities and Exchange Commission (SEC) registrant, we are permitted to use US GAAP for the purposes of meeting both our Canadian and US continuous disclosure requirements. BASIS OF PRESENTATION AND USE OF ESTIMATES The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: variable consideration included in revenue (Note 4); carrying values of regulatory assets and liabilities (Note 7) ; purchase price allocations (Note 8) ; unbilled revenues; expected credit losses; depreciation rates and carrying value of property, plant and equipment (Note 11) ; amortization rates and carrying value of intangible assets (Note 15) ; measurement of goodwill (Note 16) ; fair value of asset retirement obligations (ARO) (Note 19) ; valuation of stock-based compensation (Note 22) ; fair value of financial instruments (Note 24) ; provisions for income taxes (Note 25) ; assumptions used to measure retirement benefits and OPEB (Note 26) ; commitments and contingencies (Note 30) ; and estimates of losses related to environmental remediation obligations (Note 30) . Actual results could differ from these estimates. Certain comparative figures in our consolidated financial statements have been reclassified to conform to the current year's presentation. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include our accounts and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE entity that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We assess the primary beneficiary determination for a VIE on an ongoing basis if there are changes in the facts and circumstances related to a VIE. If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method. REGULATION Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the Canada Energy Regulator (CER), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, the Ontario Energy Board (OEB) and La Régie de l’energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the CER’s Land Matters Consultation Initiative (LMCI). Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. We believe that the recovery of our regulatory assets as at December 31, 2021 is probable over the periods described in Note 7 - Regulatory Matters . Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. The corresponding impact on earnings is included in Interest expense for the interest component and Other income/(expense) for the equity component. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation relating to the equity component would not be recognized. Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified. With the approval of regulators, certain operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred . For certain regulated operations to which US GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with US GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with US GAAP and no regulatory asset is recorded. REVENUE RECOGNITION For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer creditworthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts ratably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote. Certain offshore pipeline transportation contracts require us to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay us a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For the years ended December 31, 2021, 2020 and 2019, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $127 million, $292 million and $169 million, respectively. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utility revenues are recorded based on regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise areas. Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded on a gross basis as the related contracts are not held for trading purposes and we are acting as the principal in the transactions. Our largest non-affiliated customer accounted for approximately 13.5% of our third-party revenues for the year ended December 31, 2021 and 13.6% for the year ended December 31, 2020. No non-affiliated customer exceeded 10% of our third-party revenues for the year ended December 31, 2019. DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Commodity sales, Transportation and other services revenue, Commodity costs, Operating and administrative expense, Net foreign currency gain/(loss) and Interest expense. Derivatives in Qualifying Hedging Relationships We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires us to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges. Cash Flow Hedges We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized in earnings concurrently with the related transaction. If an anticipated hedged transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges We may use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged risk of the asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged risk of the asset or liability ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Net Investment Hedges Gains and losses arising from the translation of our net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA), a component of OCI. 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. As a result, the change in fair value of the foreign currency derivatives as well as the translation of US dollar denominated debt are reflected in OCI. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from the disposal of a foreign operation. Classification of Derivatives We recognize the fair value of derivative instruments in the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Operating activities in the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis. Transaction Costs Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account for these costs as a reduction to Long-term debt in the Consolidated Statements of Financial Position. These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense. EQUITY INVESTMENTS Equity investments over which we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for our proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to, and decreased for distributions received from, the investee. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, we capitalize interest costs associated with the investment during such period. RESTRICTED LONG-TERM INVESTMENTS Long-term investments that are restricted as to withdrawal or usage, for the purposes of the CER’s LMCI, are presented as Restricted long-term investments in the Consolidated Statements of Financial Position. OTHER INVESTMENTS Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not have readily determinable fair values as other investments measured using the fair value measurement alternative (FVMA). These investments are recorded at cost minus impairment, if any, plus or minus the impact of observable price changes occurring in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the FVMA are reviewed for impairment each reporting period and written down to their fair value if objective evidence of impairment is identified. Equity investments with readily determinable fair values are measured at fair value through earnings. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established. Investments in debt securities are classified as available-for-sale and measured at fair value through OCI. NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position. INCOME TAXES Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent that taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income tax expense. FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated to the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting from the translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise. Gains and losses arising from the translation of foreign operations' functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect as at the balance sheet date, while revenues and expenses are translated using monthly average exchange rates. CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased. RESTRICTED CASH Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as Restricted cash in the Consolidated Statements of Financial Position. LOANS AND RECEIVABLES Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. Interest income is recognized in earnings as it is earned with the passage of time. CURRENT EXPECTED CREDIT LOSSES For accounts receivable, a loss allowance matrix is utilized to measure lifetime expected credit losses. The matrix contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations. Other loan receivables and applicable off-balance sheet commitments utilize a discounted cash flow methodology which calculates the current expected credit losses based on historical default probability rates associated with the credit rating of the counterparty and the related term of the loan or commitment, adjusted for forward-looking information and management expectations. NATURAL GAS IMBALANCES The Consolidated Statements of Financial Position include balances as a result of differences in gas volumes received from, and delivered for, customers. As settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates. INVENTORY Inventory is comprised of natural gas held in storage by Enbridge Gas, crude oil and natural gas held primarily by businesses in the Energy Services segment and materials and supplies. Natural gas held in storage by Enbridge Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of gas purchased is deferred as a liability for future refund, or as an asset for collection as approved by the OEB. Other inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs in the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. Materials and supplies inventory is recorded at the lower of average cost or net realizable value. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in-service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation. LEASES We recognize an arrangement as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We recognize right-of-use (ROU) assets and the related lease liabilities in the Consolidated Statements of Financial Position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach applied for other long-lived assets. Lease liabilities and ROU assets require the use of judgment and estimates which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing. DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily consists of costs that regulatory authorities have permitted, or are expected to permit, to be recovered through future rates, including: deferred income taxes; the fair value adjustment to long-term debt; actual cost of removal of previously retired or decommissioned plant assets; and actuarial gains and losses arising from defined benefit pension plans. INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects . Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due. GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1. We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, the assessment of macroeconomic trends, regulatory environments, capital accessibility, operating income trends and industry conditions. Based on our assessment of qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is performed. The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using a combination of discounted cash flow and earnings multiples techniques. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. Cash flow projections include significant judgments and assumptions relating to discount rates and expected future capital expenditures. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units. The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of businesses included in the relevant reporting unit. On April 1, 2021, we performed a quantitative goodwill impairment assessment for the Gas Transmission and Midstream reporting unit and qualitative assessments for the Liquids Pipelines and Gas Distribution and Storage reporting units. Our goodwill impairment assessments did not result in an impairment charge. Also, we did not identify any indicators of goodwill impairment during the remainder of 2021. IMPAIRMENT We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, we will calculate fair value based on the discounted cash flows and write the asset down to the extent that the carrying value exceeds the fair value. With respect to investments in debt securities and equity investments, we assess at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we value the expected discounted cash flows using observable market inputs. We determine whether the decline below carrying value is other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities. If the decline is determined to be other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset. ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. Fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements. PENSION AND OTHER POSTRETIREMENT BENEFITS We sponsor defined benefit and defined contribution pension plans, and defined benefit OPEB plans, which provide group health care, life insurance benefits and other postretirement benefits. Defined benefit pension obligation and net periodic benefit cost are estimated using the projected unit credit method, wh

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2021
Accounting Standards Update and Change in Accounting Principle [Abstract]
CHANGES IN ACCOUNTING POLICIES	CHANGES IN ACCOUNTING POLICIES CHANGES IN ACCOUNTING POLICIES There were no changes in accounting policies during the year ended December 31, 2021. ADOPTION OF NEW ACCOUNTING STANDARDS Accounting for Contract Assets and Liabilities from Contracts with Customers in a Business Combination Effective November 1, 2021, we adopted Accounting Standards Update (ASU) 2021-08 on a retrospective basis beginning January 1, 2021. The new standard was issued in October 2021 to amend business combination accounting specific to contract assets and contract liabilities resulting from contracts with customers, requiring measurement in accordance with Accounting Standards Codification (ASC) 606. The ASU is also applicable to contract assets and contract liabilities from other contracts to which ASC 606 applies, such as contract liabilities from the sale of nonfinancial assets within the scope of ASC 610-20. The adoption of this ASU did not have a material impact on our consolidated financial statements. Reference Rate Reform For eligible hedging relationships existing as at January 1, 2021 and prospectively, we have applied the optional expedient in 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 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. FUTURE ACCOUNTING POLICY CHANGES

REVENUE

REVENUE	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE REVENUE FROM CONTRACTS WITH CUSTOMERS Major Products and Services Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2021 (millions of Canadian dollars) Transportation revenue 9,492 4,364 676 — — — 14,532 Storage and other revenue 147 255 246 — — — 648 Gas gathering and processing revenue — 49 — — — — 49 Gas distribution revenue — — 4,026 — — — 4,026 Electricity and transmission revenue — — — 177 — — 177 Total revenue from contracts with customers 9,639 4,668 4,948 177 — — 19,432 Commodity sales — — — — 26,873 — 26,873 Other revenue 1,2 375 42 13 336 — — 766 Intersegment revenue 567 1 19 (1) 44 (630) — Total revenue 10,581 4,711 4,980 512 26,917 (630) 47,071 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2020 (millions of Canadian dollars) Transportation revenue 9,161 4,523 674 — — — 14,358 Storage and other revenue 94 274 203 — — — 571 Gas gathering and processing revenue — 27 — — — — 27 Gas distribution revenue — — 3,663 — — — 3,663 Electricity and transmission revenue — — — 198 — — 198 Total revenue from contracts with customers 9,255 4,824 4,540 198 — — 18,817 Commodity sales — — — — 19,259 — 19,259 Other revenue 1,2 584 44 17 389 — (23) 1,011 Intersegment revenue 584 2 12 — 24 (622) — Total revenue 10,423 4,870 4,569 587 19,283 (645) 39,087 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2019 (millions of Canadian dollars) Transportation revenue 9,082 4,477 743 — — — 14,302 Storage and other revenue 109 268 201 — — — 578 Gas gathering and processing revenue — 423 — — — — 423 Gas distribution revenue — — 4,210 — — — 4,210 Electricity and transmission revenue — — — 180 — — 180 Commodity sales — 4 — — — — 4 Total revenue from contracts with customers 9,191 5,172 5,154 180 — — 19,697 Commodity sales — — — — 29,305 — 29,305 Other revenue 1,2 659 30 9 387 (2) (16) 1,067 Intersegment revenue 369 5 16 — 71 (461) — Total revenue 10,219 5,207 5,179 567 29,374 (477) 50,069 1 Includes mark-to-market gains from our hedging program for the year ended December 31, 2021 of $59 million, (2020 - $265 million, 2019 - $346 million). 2 Includes revenues from lease contracts. Refer to Note 27 - Leases . We disaggregate revenue 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 December 31, 2021 2,369 213 1,898 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 revenue 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 the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional. Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the year ended December 31, 2021 included in contract liabilities at the beginning of the period is $305 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2021 were $397 million. Performance Obligations Segment Nature of Performance Obligation Liquids Pipelines • Transportation and storage of crude oil and natural gas liquids (NGLs) Gas Transmission and Midstream • Transportation, storage, gathering, compression and treating of natural gas • Transportation of NGLs • Sale of crude oil, natural gas and NGLs Gas Distribution and Storage • Supply and delivery of natural gas • Transportation of natural gas • Storage of natural gas Renewable Power Generation • Generation and transmission of electricity • Delivery of electricity from renewable energy generation facilities There was no material revenue recognized in the year ended December 31, 2021 from performance obligations satisfied in previous periods. Payment Terms Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution and Storage customers are received on a continuous basis based on established billing cycles. Certain contracts in the US offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs are recorded as contract liabilities. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives. Revenue to be Recognized from Unfulfilled Performance Obligations Total revenue from performance obligations expected to be fulfilled in future periods is $59.8 billion, of which $7.4 billion is expected to be recognized during the year ended December 31, 2022. 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 revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts of revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above. SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE Long-Term Transportation Agreements For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed. Variable Consideration Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes are sold or transported and actual tolls and prices are determined. During the year ended December 31, 2021, revenue for the Canadian Mainline has been recognized in accordance with the terms of the Competitive Tolling Settlement (CTS), which expired on June 30, 2021. The tolls in place on June 30, 2021 continue on an interim basis until a new commercial arrangement is implemented and are subject to finalization and adjustment applicable to the interim period, if any. Due to the uncertainty of adjustment to tolling pursuant to a CER decision and potential customer negotiations, interim toll revenue recognized during the year ended December 31, 2021 is considered variable consideration. Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2021 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 70 — 70 Revenue from products and services transferred over time 1 9,639 4,668 4,878 177 19,362 Total revenue from contracts with customers 9,639 4,668 4,948 177 19,432 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2020 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 60 — 60 Revenue from products and services transferred over time 1 9,255 4,824 4,480 198 18,757 Total revenue from contracts with customers 9,255 4,824 4,540 198 18,817 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2019 (millions of Canadian dollars) Revenue from products transferred at a point in time — 4 65 — 69 Revenue from products and services transferred over time 1 9,191 5,168 5,089 180 19,628 Total revenue from contracts with customers 9,191 5,172 5,154 180 19,697 1 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales. Performance Obligations Satisfied Over Time For arrangements involving the transportation and sale of petroleum products and natural gas where the transportation services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period. Determination of Transaction Prices Prices for transportation and gas processing services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation. Prices for commodities sold are determined by reference to market price indices plus or minus a negotiated differential and in certain cases a marketing fee. Prices for natural gas sold and distribution services provided by regulated natural gas distribution operations are prescribed by regulation.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION Segmented information for the years ended December 31, 2021, 2020 and 2019 is as follows: Year ended December 31, 2021 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 10,581 4,711 4,980 512 26,917 (630) 47,071 Commodity and gas distribution costs (25) — (2,147) — (27,174) 644 (28,702) Operating and administrative (3,431) (1,877) (1,143) (180) (48) (33) (6,712) Income/(loss) from equity investments 759 813 42 101 — (4) 1,711 Impairment of equity investments — (111) — — — — (111) Other income/(expense) 13 135 385 75 (8) 379 979 Earnings/(loss) before interest, income tax expense and depreciation and amortization 7,897 3,671 2,117 508 (313) 356 14,236 Depreciation and amortization (3,852) Interest expense (2,655) Income tax expense (1,415) Earnings 6,314 Capital expenditures 1 4,051 2,420 1,343 16 1 54 7,885 Total property, plant and equipment, net 52,530 27,028 16,904 3,315 23 267 100,067 Year ended December 31, 2020 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 10,423 4,870 4,569 587 19,283 (645) 39,087 Commodity and gas distribution costs (20) — (1,810) (2) (19,450) 613 (20,669) Operating and administrative (3,331) (1,859) (1,091) (191) (67) (210) (6,749) Income/(loss) from equity investments 558 479 9 94 (3) (1) 1,136 Impairment of equity investments — (2,351) — — — — (2,351) Other income/(expense) 53 (52) 71 35 1 130 238 Earnings/(loss) before interest, income tax expense and depreciation and amortization 7,683 1,087 1,748 523 (236) (113) 10,692 Depreciation and amortization (3,712) Interest expense (2,790) Income tax expense (774) Earnings 3,416 Capital expenditures 1 2,033 2,130 1,134 81 2 90 5,470 Total property, plant and equipment, net 48,799 25,745 16,079 3,495 24 429 94,571 Year ended December 31, 2019 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 10,219 5,207 5,179 567 29,374 (477) 50,069 Commodity and gas distribution costs (29) — (2,354) (2) (29,091) 472 (31,004) Operating and administrative (3,298) (2,232) (1,149) (189) (44) (79) (6,991) Impairment of long-lived assets (21) (105) — (297) — — (423) Income/(loss) from equity investments 780 682 4 31 8 (2) 1,503 Other income/(expense) 30 (181) 67 1 3 515 435 Earnings before interest, income tax expense and depreciation and amortization 7,681 3,371 1,747 111 250 429 13,589 Depreciation and amortization (3,391) Interest expense (2,663) Income tax expense (1,708) Earnings 5,827 Capital expenditures 1 2,548 1,753 1,100 23 2 124 5,550 Total property, plant and equipment, net 48,783 25,268 15,622 3,658 24 368 93,723 1 Includes allowance for equity funds used during construction. The measurement basis for preparation of segmented information is consistent with the significant accounting policies (Note 2) . GEOGRAPHIC INFORMATION Revenues 1 Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Canada 20,474 16,453 19,954 US 26,597 22,634 30,115 47,071 39,087 50,069 1 Revenues are based on the country of origin of the product or service sold. Property, Plant and Equipment 1 December 31, 2021 2020 (millions of Canadian dollars) Canada 47,102 46,499 US 52,965 48,072 100,067 94,571 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
EARNINGS PER COMMON SHARE	EARNINGS PER COMMON SHARE BASIC Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of approximately 2 million as at December 31, 2021, 5 million as at December 31, 2020, and 6 million as at December 31, 2019, resulting from our reciprocal investment in Noverco. On December 30, 2021, we closed the sale of our non-operating minority ownership of Noverco. Refer to Note 13 - Long-term Investments for more information. 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: December 31, 2021 2020 2019 (number of shares in millions) Weighted average shares outstanding 2,023 2,020 2,017 Effect of dilutive options 2 1 3 Diluted weighted average shares outstanding 2,025 2,021 2,020 For the years ended December 31, 2021, 2020 and 2019, 18.6 million, 29.8 million and 17.8 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $52.89, $51.42 and $53.56, respectively, were excluded from the diluted earnings per common share calculation.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS We record assets and liabilities that result from regulated ratemaking processes that would not be recorded under US GAAP for non-regulated entities. See Note 2 - Significant Accounting Policies for further discussion. Our significant regulated businesses and the related accounting impacts are described below. Under the current authorized rate structure for certain operations, income tax costs are recovered in rates based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of temporary differences that created the deferred income taxes, it is expected that rates will be adjusted to recover these taxes. Since most of these temporary differences are related to property, plant and equipment costs, this recovery is expected to occur over the life of the related assets. LIQUIDS PIPELINES Canadian Mainline Canadian Mainline includes the Canadian portion of our mainline system and is subject to regulation by the CER. Tolls, excluding Lines 8 and 9, are governed by the 10-year CTS which expired on June 30, 2021 (Note 4). The CTS established a Canadian Local Toll for all volumes shipped on the Canadian Mainline and an International Joint Tariff for all volumes shipped from western Canadian receipt points to delivery points on our Lakehead System. Under the CTS, we have recognized a regulatory asset of $2.1 billion a s at December 31, 2021 (2020 - $1.9 billion) to offset deferred income taxes, as a CER rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the CTS. Southern Lights Pipeline The US and Canadian portions of the Southern Lights Pipeline are regulated by the FERC and CER, respectively. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost-of-service toll methodology. Toll adjustments are filed annually with the regulators and provide for the recovery of allowable operating and debt financing costs, plus a pre-determined after-tax return on equity (ROE) of 10%. GAS TRANSMISSION AND MIDSTREAM British Columbia (BC) Pipeline and Maritimes & Northeast (M&N) Canada are regulated by the CER. Rates are approved by the CER through negotiated toll settlement agreements based on cost-of-service. Both our BC Pipeline and M&N Canada systems operate under the terms of their respective negotiated toll settlements, which stipulate an allowable ROE and the continuation and establishment of certain deferral and variance accounts. As both settlement agreements expired in December 2021, we are currently operating under CER-approved interim tolls and negotiating the terms of new toll settlements for periods beginning in 2022. US Gas Transmission Most of our US gas transmission and storage services are regulated by the FERC and may also be subject to the jurisdiction of various other federal, state and local agencies. The FERC regulates natural gas transmission in US interstate commerce including the establishment of rates for services, while rates for intrastate commerce and/or gathering services are regulated by the state gas commissions. Cost-of-service is the basis for the calculation of regulated tariff rates, although the FERC also allows the use of negotiated and discounted rates within contracts with shippers that may result in a rate that is above or below the FERC-regulated recourse rate for that service. GAS DISTRIBUTION AND STORAGE Enbridge Gas Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year Incentive Regulation (IR) framework using a price cap mechanism. The price cap mechanism establishes new rates each year through an annual base rate escalation at inflation less a 0.3% stretch factor, annual updates for certain costs to be passed through to customers, and where applicable, the recovery of material discrete incremental capital investments beyond those that can be funded through base rates. The IR framework includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved ROE. FINANCIAL STATEMENT EFFECTS Accounting for rate-regulated activities has resulted in the recognition of the following regulatory assets and liabilities in the Consolidated Statements of Financial Position: December 31, 2021 2020 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Under-recovery of fuel costs 114 86 2022 Other current regulatory assets 145 146 2022 Total current regulatory assets 1 (Note 9) 259 232 Long-term regulatory assets Deferred income taxes 2 4,176 3,890 Various Long-term debt 3 398 429 2023-2046 Negative salvage 4 243 246 Various Purchase gas variance 215 — 2023 Accounting policy changes 5 157 169 Various Pension plan receivable 6 78 402 Various Other long-term regulatory assets 339 261 Various Total long-term regulatory assets 1 5,606 5,397 Total regulatory assets 5,865 5,629 Current regulatory liabilities Purchase gas variance — 153 2021 Other current regulatory liabilities 106 117 2022 Total current regulatory liabilities 7 106 270 Long-term regulatory liabilities Future removal and site restoration reserves 8 1,543 1,455 Various Regulatory liability related to US income taxes 9 895 941 2050-2072 Pipeline future abandonment costs (Note 14) 649 578 Various Other long-term regulatory liabilities 234 150 Various Total long-term regulatory liabilities 7 3,321 3,124 Total regulatory liabilities 3,427 3,394 1 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in Deferred amounts and other assets. 2 Represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in future regulator-approved rates and recovered from customers. The recovery period depends on the timing of the reversal of temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded. 3 Represents our regulatory offset to the fair value adjustment to debt acquired in our merger with Spectra Energy Corp. (Spectra Energy). The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value. 4 The negative salvage balance represents the recovery in future rates of the actual cost of removal of previously retired or decommissioned plant assets, as approved by the FERC. 5 This deferral reflects unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited, relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and recovered in rates, as previously approved by the OEB. 6 Represents the regulatory offset to our pension liability to the extent that it is expected to be included in regulator-approved future rates and recovered from customers. The settlement period for this balance is not determinable. In the absence of rate-regulated accounting, this regulatory balance and the related pension expense would be recorded in earnings and OCI. 7 Current regulatory liabilities are included in Accounts payable and other, while long-term regulatory liabilities are included in Other long-term liabilities. 8 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the OEB, to fund future costs of removal and site restoration relating to property, plant and equipment. These costs are collected as part of the depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance will occur over the long-term as costs are incurred. In the absence of rate-regulated accounting, depreciation rates would not include a charge for removal and site restoration and costs would be charged to earnings as incurred with recognition of revenue for amounts previously collected.

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2021
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS ACQUISITION Moda Midstream Operating, LLC On October 12, 2021, through a wholly-owned US subsidiary, we acquired all of the outstanding membership interests in Moda for $3.7 billion (US$3.0 billion) of cash plus potential contingent payments of up to US$150 million dependent on performance of the assets (the Acquisition). The Acquisition is also subject to customary closing and working capital adjustments. Moda owns and operates a light crude export platform with very large crude carrier capability. The Acquisition aligns with and advances our US Gulf Coast export strategy and enables connectivity to low-cost and long-lived reserves in the Permian and Eagle Ford basins. We accounted for the Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations . In accordance with valuation methodologies described in ASC 820 Fair Value Measurements , the acquired assets and assumed liabilities were recorded at their estimated fair values as at the date of acquisition. The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Moda: October 12, 2021 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 62 Property, plant and equipment (a) 1,480 Long-term investments (b) 427 Intangible assets (c) 1,781 Current liabilities 59 Long-term liabilities 17 Goodwill (d) 268 Purchase price: Cash 3,755 Contingent consideration (e) 187 3,942 a) Due to the specialized nature of Moda's property, plant and equipment, which includes groups of assets configured for use as storage facilities, pipelines and export terminals, the depreciated replacement cost approach was adopted as the primary valuation methodology. In determining replacement cost, both indirect costing using relevant inflation indices and direct costing using relevant market quotes were utilized. Adjustments were then applied for physical deterioration as well as functional and economic obsolescence. The fair value of land was determined using a market approach, which is based on rents and offerings for comparable properties. b) Long-term investments represent Moda's 20% equity interest in Cactus II Pipeline, LLC (Cactus II). The fair value of Cactus II was determined using the discounted cash flow method. The discounted cash flow method is an income-based approach to valuation which estimates the present value of future projected benefits from the investment. c) Intangible assets consist primarily of customer relationships associated with long-term take-or-pay contracts. Fair value was determined using an income-based approach by estimating the present value of the after-tax earnings attributable to the contracts, including earnings associated with expected renewal terms, and will be amortized on a straight-line basis over an expected useful life of 10 years. d) Goodwill is primarily attributable to uncontracted future revenues, existing assembled assets that cannot be duplicated at the same cost by a new entrant, and enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. The goodwill balance recognized has been assigned to our Liquids Pipelines segment and is tax deductible over 15 years. e) We agreed to pay additional contingent consideration of up to US$150 million to Moda's former membership interest holders if Moda's monthly volumes of crude oil loaded onto a vessel equal or exceed specified throughput levels. These performance requirements terminate the earlier of December 31, 2023 or the date the final contingent payment is made. The US$150 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition. As at December 31, 2021, there were no changes to the amount of contingent consideration recognized. Acquisition-related expenses incurred were approximately $21 million for the year ended December 31, 2021 and are included in Operating and administrative expense in the Consolidated Statements of Earnings. Upon completion of the Acquisition, we began consolidating Moda. For the period beginning October 12, 2021 through to December 31, 2021, Moda generated approximately $80 million in operating revenues and $9 million in earnings attributable to common shareholders. Our supplemental pro forma consolidated financial information for the years ended December 31, 2021 and 2020, including the results of operations for Moda as if the Acquisition had been completed on January 1, 2020, are as follows: Year ended December 31, 2021 2020 (unaudited; millions of Canadian dollars) Operating revenues 47,339 39,435 Earnings attributable to common shareholders 1,2 5,771 2,938 1 Acquisition-related expenses of $21 million (after-tax $16 million) were excluded from earnings attributable to common shareholders for the year ended December 31 2021 and deducted for the year ended December 31, 2020. 2 Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets of $193 million and $207 million (after-tax of $145 million and $155 million) for the years ended December 31, 2021 and 2020, respectively. DISPOSITIONS Line 10 Crude Oil Pipeline In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. (EEP), owned the Canadian and US portions of Line 10, respectively, and the related assets were included in our Liquids Pipelines segment. The transaction closed on June 1, 2020. No gain or loss on disposition was recorded. Montana-Alberta Tie Line In the fourth quarter of 2019, we committed to a plan to sell the Montana-Alberta Tie Line (MATL) transmission asset, a 345 kilometer transmission line from Great Falls, Montana to Lethbridge, Alberta. MATL was included in our Renewable Power Generation segment. The purchase and sale agreement was signed in January 2020. Upon the reclassification and subsequent remeasurement of MATL assets as held for sale, a loss of $297 million was included within Impairment of long-lived assets in the Consolidated Statements of Earnings for the year ended December 31, 2019. On May 1, 2020, we closed the sale of MATL for cash proceeds of approximately $189 million. After closing adjustments, a gain on disposal of $4 million was included in Other income/(expense) in the Consolidated Statements of Earnings. Ozark Gas Transmission In the first quarter of 2020, we agreed to sell our Ozark Gas Transmission and Ozark Gas Gathering assets (Ozark assets). The Ozark assets are composed of a transmission system that extends from southeastern Oklahoma through Arkansas to southeastern Missouri, and a fee-based gathering system that accesses Fayetteville Shale and Arkoma production. These assets were included in our Gas Transmission and Midstream segment. On April 1, 2020, we closed the sale of the Ozark assets for cash proceeds of approximately $63 million. After closing adjustments, a gain on disposal of $1 million was included in Other income/(expense) in the Consolidated Statements of Earnings. Canadian Natural Gas Gathering and Processing Businesses On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses to Brookfield Infrastructure Partners L.P. and its institutional partners for a cash purchase price of approximately $4.3 billion, subject to customary closing adjustments. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations (collectively, Canadian Natural Gas Gathering and Processing Businesses assets); these assets were part of our Gas Transmission and Midstream segment. On October 1, 2018, we closed the sale of the provincially regulated facilities. On December 31, 2019, we closed the sale of the federally regulated facilities for proceeds of approximately $1.7 billion. After closing adjustments, a loss on disposal of $268 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019. As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. St. Lawrence Gas Company, Inc. In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. (St. Lawrence Gas). St. Lawrence Gas assets were included in the Gas Distribution and Storage segment. On November 1, 2019, we closed the sale of St. Lawrence Gas for cash proceeds of approximately $72 million. After closing adjustments, a loss on disposal of $10 million was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019. Enbridge Gas New Brunswick In December 2018, we entered into an agreement for the sale of Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB). EGNB assets were a part of our Gas Distribution and Storage segment. On October 1, 2019, we closed the sale of EGNB to Liberty Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp., for cash proceeds of approximately $331 million. After closing adjustments, a loss on disposal of $3 million was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019. As EGNB assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As such, allocated goodwill of $133 million was included in assets subsequently disposed.

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER	12 Months Ended
	Dec. 31, 2021
Receivables [Abstract]
ACCOUNTS RECEIVABLE AND OTHER	ACCOUNTS RECEIVABLE AND OTHER December 31, 2021 2020 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 4,957 3,923 Short-term portion of derivative assets (Note 24) 529 323 Regulatory assets (Note 7) 259 232 Taxes receivable 407 374 Other 710 406 6,862 5,258 1 Net of allowance for expected credit losses of $87 million as at December 31, 2021 and $70 million as at December 31, 2020.

INVENTORY

INVENTORY	12 Months Ended
	Dec. 31, 2021
Inventory Disclosure [Abstract]
INVENTORY	INVENTORY December 31, 2021 2020 (millions of Canadian dollars) Natural gas 953 710 Crude oil 624 744 Other 93 82 1,670 1,536

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Weighted Average December 31, Depreciation Rate 2021 2020 (millions of Canadian dollars) Pipelines 2.8 % 62,997 57,459 Facilities and equipment 3.1 % 34,331 30,149 Land and right-of-way 1 2.3 % 3,320 2,896 Gas mains, services and other 2.7 % 13,606 12,813 Storage 2.4 % 3,099 2,936 Wind turbines, solar panels and other 4.0 % 4,912 4,877 Other 8.2 % 1,507 1,558 Under construction — % 2,268 5,762 Total property, plant and equipment 126,040 118,450 Total accumulated depreciation (25,973) (23,879) Property, plant and equipment, net 100,067 94,571 1 The measurement of weighted average depreciation rate excludes non-depreciable assets. Depreciation expense for the years ended December 31, 2021, 2020 and 2019 was $3.5 billion, $3.4 billion and $3.0 billion, respectively. IMPAIRMENT Access Northeast Project In 2019, we announced that we terminated the agreements with Eversource Energy and National Grid USA Service Company, Inc. related to the Access Northeast project. As a result, we recognized an impairment loss of $105 million for the year ended December 31, 2019, which is included in Impairment of long-lived assets in the Consolidated Statements of Earnings. Access Northeast is part of our Gas Transmission and Midstream segment. Impairment charges were based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash flows.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES CONSOLIDATED VARIABLE INTEREST ENTITIES Our consolidated VIEs consist of legal entities where we are the primary beneficiary. We are the primary beneficiary when our variable interest(s) provide us with (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. We determine whether we are the primary beneficiary of a VIE by considering qualitative and quantitative factors, including, but not limited to: decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position. December 31, 2021 1 2020 1 (millions of Canadian dollars) Assets Cash and cash equivalents 247 215 Restricted cash 4 1 Accounts receivable and other 99 65 Inventory 9 7 359 288 Property, plant and equipment, net 3,052 3,201 Long-term investments 16 14 Restricted long-term investments 101 84 Deferred amounts and other assets 2 3 Intangible assets, net 108 115 3,638 3,705 Liabilities Accounts payable and other 84 52 Other long-term liabilities 182 175 Deferred income taxes 5 5 271 232 3,367 3,473 1 Excludes assets and liabilities of EEP and Spectra Energy Partners, L.P. (SEP) following the subsidiary guarantees agreement entered on January 22, 2019. See Part II . Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Summarized Financial Information. We do not have obligations to provide additional financial support to any of our consolidated VIEs. UNCONSOLIDATED VARIABLE INTEREST ENTITIES We currently hold interests in several non-consolidated VIEs where we are not the primary beneficiary as we do not have the power to direct the activities of the VIEs that most significantly impact the VIEs' economic performance. These interests include investments in limited partnerships that are assessed to be VIEs due to the limited partners not having substantive kick-out rights or participating rights. The power to direct the activities of a majority of these non-consolidated limited partnership VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee that makes significant decisions for the VIE and none of the partners may make significant decisions unilaterally. The carrying amount of these VIEs and our estimated maximum exposure to loss as at December 31, 2021 and 2020 are presented below: Carrying Maximum December 31, 2021 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 113 195 EIH S.á r.l. 2, 8 38 664 Enbridge Renewable Infrastructure Investments S.á r.l. 3 54 2,121 Rampion Offshore Wind Limited 5 450 508 Vector Pipeline L.P. 6 189 374 Other 4,7 210 426 1,054 4,288 Carrying Maximum December 31, 2020 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 106 187 Éolien Maritime France SAS 2, 8 96 949 Enbridge Renewable Infrastructure Investments S.á r.l. 3 100 2,516 PennEast Pipeline Company, LLC 4 116 371 Rampion Offshore Wind Limited 5 599 650 Vector Pipeline L.P. 6 201 390 Other 7 133 361 1,351 5,424 1 At December 31, 2021 and 2020, the maximum exposure to loss includes guarantees by us for our respective share of the VIE’s borrowing on a bank credit facility. 2 At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the three French offshore wind projects for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $73 million held by us as at December 31, 2021. On March 18, 2021, Enbridge Renewable Infrastructure Holdings S. á r.l. (ERIH) closed the sale of 49% of its interest in EIH S. á r.l. to the Canada Pension Plan Investment Board (CPP Investments). 3 At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $807 million and $904 million held by us as at December 31, 2021 and 2020, respectively. 4 At December 31, 2021, the maximum exposure to loss is limited to our equity investment and at December 31, 2020, the maximum exposure to loss includes the remaining expected contributions to the joint venture. 5 At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in project contracts in which we would be liable for in the event of default by the VIE. 6 At December 31, 2021 and 2020, the maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable for $80 million and $84 million held by us as at December 31, 2021 and 2020, respectively, and an outstanding credit facility for $105 million as at December 31, 2021 and 2020. 7 At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE. 8 At December 31, 2020, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $132 million held by us as at December 31, 2020. In relation to the sale of 49% of EIH S. á r.l.'s interest to CPP Investments, Eolien Maritime France SAS is now reported under EIH S. á r.l. in 2021. We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2021 and 2020.

LONG-TERM INVESTMENTS

LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]
LONG-TERM INVESTMENTS	LONG-TERM INVESTMENTS Ownership December 31, Interest 2021 2020 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines MarEn Bakken Company LLC 1 75.0 % 1,728 1,795 Gray Oak Holdings LLC 2 35.0 % 469 502 Seaway Crude Holdings LLC 50.0 % 2,634 2,668 Illinois Extension Pipeline Company, L.L.C. 3 65.0 % 593 623 Cactus II Pipeline, LLC 4 20.0 % 434 — Other 30.0% - 43.8% 71 73 Gas Transmission and Midstream Alliance Pipeline 5 50.0 % 504 269 Aux Sable 6 42.7% - 50.0% 238 251 DCP Midstream, LLC 7 50.0 % 397 331 Gulfstream Natural Gas System, L.L.C. 50.0 % 1,180 1,175 Nexus Gas Transmission, LLC 50.0 % 1,724 1,745 PennEast Pipeline Company, LLC 20.0 % 12 116 Sabal Trail Transmission, LLC 50.0 % 1,464 1,510 Southeast Supply Header, LLC 50.0 % 82 84 Steckman Ridge, LP 50.0 % 88 90 Vector Pipeline 8 60.0 % 189 201 Offshore - various joint ventures 22.0% - 74.3% 309 338 Other 33.3% 2 4 Gas Distribution and Storage Noverco Common Shares 9 38.9 % — 156 Other 47.6% - 50% 20 13 Renewable Power Generation EIH S.a.r.l. 10 51.0 % 38 96 Enbridge Renewable Infrastructure Investments S.a.r.l. 51.0 % 54 100 Rampion Offshore Wind Limited 24.9 % 450 599 NextBridge Infrastructure LP 25.0 % 186 122 Other 12.0% - 50.0% 93 74 Eliminations and Other Other 42.7% - 50.0% 23 32 OTHER LONG-TERM INVESTMENTS Gas Distribution and Storage Noverco Preferred Shares 9 — 567 Renewable Power Generation Emerging Technologies and Other 32 32 Eliminations and Other Other 11 310 252 13,324 13,818 1 Owns 49% interest in Bakken Pipeline Investments L.L.C., which owns 75% of the Bakken Pipeline System resulting in a 27.6% effective interest in the Bakken Pipeline System. 2 Owns 65% interest in Gray Oak Pipeline, LLC resulting in a 22.8% effective interest in Gray Oak Pipeline, LLC. 3 Owns the Southern Access Extension Project. 4 In October 2021 we acquired an effective 20.0% interest in Cactus II Pipeline, LLC through the acquisition of Moda Midstream Operating, LLC. See Note 8 - Acquisitions and Dispositions for further discussion. 5 Includes Alliance Pipeline Limited Partnership in Canada and Alliance Pipeline L.P. in the US. 6 Includes Aux Sable Canada LP in Canada and Aux Sable Liquid Products LP and Aux Sable Midstream LLC in the US. 7 Our ownership in DCP Midstream, LLC (DCP Midstream) holds an interest of 56.5% in DCP Midstream, LP. 8 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US. 9 On December 30, 2021, we sold our 38.9% common share and preferred share interest of Noverco Inc. 10 On March 18, 2021, we sold 49% of EIH S.a.r.l., an entity that holds our 50% interest in Éolien Maritime France SAS (EMF), to the CPP Investments. This resulted in a 25.5% effective interest in EMF. 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%). 11 Includes investments held and valued at fair value through net income. Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees' assets at the purchase date. As at December 31, 2021, this basis difference was $2.5 billion (2020 - $2.4 billion), of which $730 million (2020 - $657 million) was amortizable. For the years ended December 31, 2021, 2020 and 2019, distributions received from equity investments were $2.2 billion, $2.1 billion and $2.2 billion, respectively. Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows: Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Operating revenues 19,891 13,987 15,687 Operating expenses 16,514 12,223 13,153 Earnings 2,952 2,306 3,016 Earnings attributable to Enbridge 1,711 1,136 1,503 December 31, 2021 2020 (millions of Canadian dollars) Current assets 3,581 3,136 Non-current assets 44,497 45,955 Current liabilities 3,678 3,539 Non-current liabilities 16,950 19,639 Noncontrolling interests 3,786 3,810 Noverco Inc. On June 7, 2021, IPL System Inc., a wholly owned subsidiary of Enbridge, entered into a purchase and sale agreement to sell its 38.9% common share and preferred share interest in Noverco to Trencap L.P. for $1.1 billion in cash. On December 30, 2021, we closed the sale of Noverco for cash proceeds of $1.1 billion. After closing adjustments, a gain on disposal of $303 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2021. Noverco was previously included in our Gas Distribution and Storage segment. IMPAIRMENT OF EQUITY INVESTMENTS PennEast Pipeline Company, LLC PennEast Pipeline Company, LLC (PennEast) is a joint venture formed to develop a natural gas transmission pipeline to serve local distribution companies and power generators in Southeastern Pennsylvania and New Jersey, is owned 20% by Enbridge, and is recorded as an equity method investment. In the third quarter of 2021, PennEast determined further development of the project was no longer viable and development of the project was ceased. As a result, we recorded an other-than-temporary impairment loss of $111 million on our investment for the year ended December 31, 2021 based on the estimated fair value of our share of the net assets. The carrying value of this investment as at December 31, 2021 and 2020 was $12 million and $116 million, respectively. Steckman Ridge, LP Steckman Ridge, LP (Steckman Ridge) is engaged in the storage of natural gas, is owned 50% by Enbridge and is recorded as an equity method investment. During the year ended December 31, 2020, Steckman Ridge’s forecasted performance was adjusted for the expectation that future available capacity will be re-contracted at lower than expected rates and an other than temporary impairment loss on our investment of $221 million for the year ended December 31, 2020 was recorded based on a discounted cash flow analysis. The carrying value of this investment as at December 31, 2021 and 2020 was $88 million and $90 million, respectively. Southeast Supply Header, L.L.C. Southeast Supply Header, L.L.C. (SESH) provides natural gas transmission services from east Texas and northern Louisiana to the southeast markets of the Gulf Coast. SESH is owned 50% by Enbridge and is recorded as an equity method investment. The forecasted performance of SESH was revised during the year ended December 31, 2020 to reflect downward revisions to future negotiated rates as well as higher than expected available capacity levels, caused primarily by a significant contract expiry. An other than temporary impairment loss on our investment of $394 million for the year ended December 31, 2020 was recorded based on a discounted cash flow analysis. The carrying value of this investment as at December 31, 2021 and 2020 was $82 million and $84 million, respectively. 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 year ended December 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. The carrying value of our investment in DCP Midstream as at December 31, 2021 and 2020 was $397 million and $331 million, respectively.

RESTRICTED LONG-TERM INVESTMENT

RESTRICTED LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2021
Assets Held-in-trust [Abstract]
RESTRICTED LONG-TERM INVESTMENTS	RESTRICTED LONG-TERM INVESTMENTS Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline abandonment costs for all CER regulated pipelines as a result of the CER’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues on the Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term liabilities on the Consolidated Statements of Financial Position. We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money market securities in the US and Canada. As at December 31, 2021 and 2020, we had restricted long-term investments held in trust and classified as available-for-sale of $630 million and $553 million, respectively. The cost basis of our debt securities classified as available-for-sale and recorded as part of our restricted long-term investment balance was $383 million and $322 million as at December 31, 2021 and 2020, respectively. Within Other long-term liabilities we had estimated future abandonment costs related to LMCI of $649 million and $578 million as at December 31, 2021 and 2020, respectively (Note 7) .

INTANGIBLE ASSETS

INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
INTANGIBLE ASSETS	INTANGIBLE ASSETS Weighted Average Accumulated December 31, 2021 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Software 12.0 % 2,067 (1,148) 919 Power purchase agreements 4.5 % 63 (21) 42 Project agreement 1 4.0 % 152 (27) 125 Customer relationships 8.5 % 2,532 (215) 2,317 Other intangible assets 3.9 % 475 (116) 359 Under development — % 246 — 246 5,535 (1,527) 4,008 Weighted Average Accumulated December 31, 2020 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Software 10.5 % 2,043 (1,299) 744 Power purchase agreements 4.5 % 63 (18) 45 Project agreement 1 4.0 % 153 (21) 132 Customer relationships 5.0 % 724 (139) 585 Other intangible assets 2.7 % 456 (96) 360 Under development — % 214 — 214 3,653 (1,573) 2,080 1 Represents a project agreement acquired from the merger of Enbridge and Spectra Energy. For the years ended December 31, 2021, 2020 and 2019, our amortization expense related to intangible assets totaled $348 million, $294 million and $296 million, respectively. Our expected amortization expense associated with existing intangible assets for each of the years 2022 to 2026 is $492 million.

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL Liquids Gas Gas Energy Consolidated (millions of Canadian dollars) Balance at January 1, 2020 7,951 19,844 5,356 2 33,153 Foreign exchange and other (123) (364) — — (487) Acquisition — — 22 — 22 Balance at December 31, 2020 1,2 7,828 19,480 5,378 2 32,688 Foreign exchange and other (55) (145) — — (200) Acquisition 3 268 — 19 — 287 Balance at December 31, 2021 1,2 8,041 19,335 5,397 2 32,775 1 Gross cost of goodwill as at December 31, 2021 and 2020 was $34.4 billion and $34.3 billion, respectively. 2 Accumulated impairment as at December 31, 2021 and 2020 was $1.6 billion. 3 In 2021, we recorded $268 million of goodwill related to the acquisition of Moda. See Note 8 - Acquisitions and Dispositions for further discussion.

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2021
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER December 31, 2021 2020 (millions of Canadian dollars) Trade payables and operating accrued liabilities 4,470 3,497 Dividends payable 1,773 1,728 Current deferred credits 853 978 Construction payables and contractor holdbacks 844 855 Current derivative liabilities (Note 24) 717 896 Taxes payable 478 622 Other 632 652 9,767 9,228

DEBT

DEBT	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
DEBT	DEBT December 31, Weighted Average Interest Rate 9 Maturity 2021 2020 (millions of Canadian dollars) Enbridge Inc. US dollar senior notes 3.2 % 2022 - 2051 10,992 8,536 Medium-term notes 3.9 % 2022 - 2064 8,123 8,323 Sustainability-linked bonds 1.1 % 2033 2,363 — Fixed-to-fixed subordinated term notes 1 5.8 % 2080 1,263 1,274 Fixed-to-floating rate subordinated term notes 2 5.8 % 2023 - 2028 6,442 6,477 Floating rate notes 3 2022 - 2023 1,579 956 Commercial paper and credit facility draws 1.0 % 2022 - 2026 7,837 8,719 Other 4 5 5 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 0.4 % 2023 - 2026 4,845 492 Other 4 7 7 Enbridge Energy Partners, L.P. Senior notes 6.5 % 2025 - 2045 3,095 3,886 Enbridge Gas Inc. Medium-term notes 3.8 % 2022 - 2051 9,010 8,485 Debentures 9.1 % 2024 - 2025 210 210 Commercial paper and credit facility draws 0.5 % 2023 1,515 1,121 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 4.0 % 2040 949 1,038 Enbridge Pipelines Inc. Medium-term notes 5 4.0 % 2022 - 2051 5,575 4,775 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 0.7 % 2023 667 1,278 Enbridge Southern Lights LP Senior notes 4.0 % 2040 240 257 Spectra Energy Capital, LLC Senior notes 7.0 % 2032 - 2038 218 220 Spectra Energy Partners, LP Senior notes 3.9 % 2022 - 2048 8,451 8,332 Westcoast Energy Inc. Medium-term notes 4.5 % 2022 - 2041 1,475 1,625 Debentures 8.1 % 2025 - 2026 275 275 Fair value adjustment 667 750 Other 6 (363) (344) Total debt 7 75,640 66,897 Current maturities (6,164) (2,957) Short-term borrowings 8 (1,515) (1,121) Long-term debt 67,961 62,819 1 For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be set to equal to the Five-Year US Treasury Rate plus a margin of 5.31% from years 10 to 30 and a margin of 6.06% from years 30 to 60. 2 For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal to the Canadian Dollar Offered Rate (CDOR) or the London Interbank Offered Rate (LIBOR) plus a margin. The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 3 The notes carry an interest rate equal to the three-month LIBOR plus a margin of 50 basis points and Secured Overnight Financing Rate (SOFR) plus a margin of 40 basis points. 4 Primarily finance lease obligations. 5 Included in medium-term notes is $100 million with a maturity date of 2112. 6 Primarily unamortized discounts, premiums and debt issuance costs. 7 2021 - $36 billion and US$31 billion; 2020 - $35 billion and US$24 billion. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment. 8 Weighted average interest rates on outstanding commercial paper were 0.5% as at December 31, 2021 (2020 - 0.3%). 9 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2021. As at December 31, 2021, all outstanding debt was unsecured. CREDIT FACILITIES The following table provides details of our committed credit facilities as at December 31, 2021: Maturity 1 Total Facilities Draws 2 Available (millions of Canadian dollars) Enbridge Inc. 2022-2026 9,137 7,837 1,300 Enbridge (U.S.) Inc. 2023-2026 6,948 4,845 2,103 Enbridge Pipelines Inc. 2023 3,000 667 2,333 Enbridge Gas Inc. 2023 2,000 1,515 485 Total committed credit facilities 21,085 14,864 6,221 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. On July 22 and 23, 2021, we renewed approximately $8.0 billion of our five-year credit facilities, extending the maturity date out to July 2026. We also extended approximately $10.0 billion of our 364-day extendible credit facilities to July 2022, which includes a one-year term out provision to July 2023. On February 10, 2022 we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025. In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $854 million was unutilized as at December 31, 2021. As at December 31, 2020, we had $849 million of uncommitted demand letter of credit facilities, of which $533 million was unutilized. Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2022 to 2026. As at December 31, 2021 and 2020, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $11.3 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 ISSUANCES During the year ended December 31, 2021, we completed the following long-term debt issuances totaling US$3.9 billion and $3.2 billion: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. February 2021 Floating rate senior-notes due February 2023 1 US$500 June 2021 2.50% Sustainability-linked senior notes due August 2033 US$1,000 June 2021 3.40% senior notes due August 2051 US$500 September 2021 3.10% Sustainability-linked medium-term notes due September 2033 $1,100 September 2021 4.10% medium-term notes due September 2051 $400 October 2021 0.55% senior notes due October 2023 US$500 October 2021 1.60% senior notes due October 2026 US$500 October 2021 3.40% senior notes due August 2051 US$500 Enbridge Gas Inc. September 2021 2.35% medium-term notes due September 2031 $475 September 2021 3.20% medium-term notes due September 2051 $425 Enbridge Pipelines Inc. May 2021 2.82% medium-term notes due May 2031 $400 May 2021 4.20% medium-term notes due May 2051 $400 Spectra Energy Partners, LP September 2021 2.50% senior notes due September 2031 2 US$400 1 Notes carry an interest rate equal to the SOFR plus a margin of 40 basis points. 2 Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP. On January 19, 2022, we closed a $750 million private placement offering of non-call 10-year fixed-to-fixed subordinated notes which mature on January 19, 2082. The net proceeds from the offering will be used to redeem the Preference Shares, Series 17 at par on March 1, 2022. LONG-TERM DEBT REPAYMENTS During the year ended December 31, 2021, we completed the following long-term debt repayments totaling $1.1 billion and US$914 million, respectively: 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 Enbridge Energy Partners, L.P. June 2021 4.20% senior notes US$600 Enbridge Gas Inc. May 2021 2.76% medium-term notes $200 December 2021 4.77% medium-term notes $175 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2021 3.98% senior notes US$64 Enbridge Southern Lights LP June and December 2021 4.01% senior notes $16 Spectra Energy Partners, LP March 2021 4.60% senior notes US$250 Westcoast Energy Inc. October 2021 3.88% medium-term notes $150 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 December 31, 2021, we were in compliance with all debt covenants. INTEREST EXPENSE Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Debentures and term notes 2,850 2,913 2,783 Commercial paper and credit facility draws 70 123 273 Amortization of fair value adjustment (50) (54) (67) Capitalized interest (215) (192) (326) 2,655 2,790 2,663

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS Our ARO relate mostly to the retirement of pipelines, renewable power generation assets and obligations related to right-of way agreements and contractual leases for land use. The discount rates used to estimate the present value of the expected future cash flows for the year ended December 31, 2021 ranged from 0.9% to 9.0% (2020 - 1.8% to 9.0%). A reconciliation of movements in our ARO liabilities is as follows: December 31, 2021 2020 (millions of Canadian dollars) Obligations at beginning of year 496 520 Liabilities disposed — — Liabilities incurred — — Liabilities settled (67) (30) Change in estimate and other 70 — Foreign currency translation adjustment (3) (6) Accretion expense 6 12 Obligations at end of year 502 496 Presented as follows: Accounts payable and other 160 56 Other long-term liabilities 342 440 502 496

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2021
Noncontrolling Interest [Abstract]
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS NONCONTROLLING INTERESTS The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position: December 31, 2021 2020 (millions of Canadian dollars) Algonquin Gas Transmission, L.L.C 377 384 Maritimes & Northeast Pipeline, L.L.C 546 558 Renewable energy assets 1,503 1,646 Westcoast Energy Inc. 1 116 408 2,542 2,996 1 Includes nil and 12 million cumulative redeemable preferred shares as at December 31, 2021 and 2020, respectively. Westcoast Energy Inc. Preferred Shares Redemption On March 20, 2019, Westcoast Energy Inc. (Westcoast) exercised its right to redeem all of its outstanding 5.5% Cumulative Redeemable First Preferred Shares, Series 7 (Series 7 Shares) and all of its outstanding 5.6% Cumulative Redeemable First Preferred Shares, Series 8 (Series 8 Shares) at a price of $25 per Series 7 Share and $25 per Series 8 Share, respectively, for a total payment of $300 million. In addition, payment of $4 million was made for all accrued and unpaid dividends. As a result, we recorded a $300 million decrease in Noncontrolling interests for the year ended December 31, 2019. On January 15, 2021, Westcoast redeemed its Cumulative Five-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 10 with a par value of $115 million. The par value of $115 million was included in Accounts payable and other in the Consolidated Statements of Financial Position as at December 31, 2020. On October 15, 2021, Westcoast redeemed its Cumulative Five-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 12 with a par value of $300 million. As a result, we recorded a decrease of $293 million, which represents the par value less related issuance costs, in Noncontrolling interests for the year ended December 31, 2021.

SHARE CAPITAL

SHARE CAPITAL	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
SHARE CAPITAL	SHARE CAPITAL Our authorized share capital consists of an unlimited number of common shares with no par value and an unlimited number of preference shares. COMMON SHARES 2021 2020 2019 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Balance at beginning of year 2,026 64,768 2,025 64,746 2,022 64,677 Shares issued on exercise of stock options — 31 1 22 3 69 Balance at end of year 2,026 64,799 2,026 64,768 2,025 64,746 PREFERENCE SHARES 2021 2020 2019 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Preference Shares, Series A 5 125 5 125 5 125 Preference Shares, Series B 18 457 18 457 18 457 Preference Shares, Series C 2 43 2 43 2 43 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 20 500 20 500 20 500 Preference Shares, Series H 14 350 14 350 14 350 Preference Shares, Series J 8 199 8 199 8 199 Preference Shares, Series L 16 411 16 411 16 411 Preference Shares, Series N 18 450 18 450 18 450 Preference Shares, Series P 16 400 16 400 16 400 Preference Shares, Series R 16 400 16 400 16 400 Preference Shares, Series 1 16 411 16 411 16 411 Preference Shares, Series 3 24 600 24 600 24 600 Preference Shares, Series 5 8 206 8 206 8 206 Preference Shares, Series 7 10 250 10 250 10 250 Preference Shares, Series 9 11 275 11 275 11 275 Preference Shares, Series 11 20 500 20 500 20 500 Preference Shares, Series 13 14 350 14 350 14 350 Preference Shares, Series 15 11 275 11 275 11 275 Preference Shares, Series 17 30 750 30 750 30 750 Preference Shares, Series 19 20 500 20 500 20 500 Issuance costs (155) (155) (155) Balance at end of year 7,747 7,747 7,747 Characteristics of the preference shares are as follows: Dividend Rate Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.50 % $1.37500 $25 — — Preference Shares, Series B 3.42 % $0.85360 $25 June 1, 2022 Series C Preference Shares, Series C 5 3-month treasury bill plus 2.40% — $25 June 1, 2022 Series B Preference Shares, Series D 4.46 % $1.11500 $25 March 1, 2023 Series E Preference Shares, Series F 4.69 % $1.17224 $25 June 1, 2023 Series G Preference Shares, Series H 4.38 % $1.09400 $25 September 1, 2023 Series I Preference Shares, Series J 4.89 % US$1.22160 US$25 June 1, 2022 Series K Preference Shares, Series L 4.96 % US$1.23972 US$25 September 1, 2022 Series M Preference Shares, Series N 5.09 % $1.27152 $25 December 1, 2023 Series O Preference Shares, Series P 4.38 % $1.09476 $25 March 1, 2024 Series Q Preference Shares, Series R 4.07 % $1.01825 $25 June 1, 2024 Series S Preference Shares, Series 1 5.95 % US$1.48728 US$25 June 1, 2023 Series 2 Preference Shares, Series 3 3.74 % $0.93425 $25 September 1, 2024 Series 4 Preference Shares, Series 5 5.38 % US$1.34383 US$25 March 1, 2024 Series 6 Preference Shares, Series 7 4.45 % $1.11224 $25 March 1, 2024 Series 8 Preference Shares, Series 9 4.10 % $1.02424 $25 December 1, 2024 Series 10 Preference Shares, Series 11 3.94 % $0.98452 $25 March 1, 2025 Series 12 Preference Shares, Series 13 3.04 % $0.76076 $25 June 1, 2025 Series 14 Preference Shares, Series 15 2.98 % $0.74576 $25 September 1, 2025 Series 16 Preference Shares, Series 17 5.15 % $1.28750 $25 March 1, 2022 Series 18 Preference Shares, Series 19 4.90 % $1.22500 $25 March 1, 2023 Series 20 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this feature. 2 Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. 4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in a year) x three-month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in a year) x three-month US Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6). 5 The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.15501 from $0.15349 on March 1, 2021, was increased to $0.15753 from $0.15501 on June 1, 2021, was increased to $0.16081 from $0.15753 on September 1, 2021 and was decreased to $0.15719 from $0.16081 on December 1, 2021, due to reset on a quarterly basis following the issuance thereof. PREFERENCE SHARE REDEMPTION We intend to exercise our right to redeem all of our outstanding cumulative redeemable minimum rate reset preference shares, Series 17, on March 1, 2022 at a price of $25 per Series 17 share, together with all accrued and unpaid dividends, if any. SHAREHOLDER RIGHTS PLAN The Shareholder Rights Plan is designed to encourage the fair treatment of our shareholders in connection with any takeover offer. Rights issued under the plan become exercisable when a person and any related parties acquires or announces its intention to acquire 20% or more of our outstanding common shares without complying with certain provisions set out in the plan or without approval of our Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase our common shares at a 50% discount to the market price at that time.

STOCK OPTION AND STOCK UNIT PLA

STOCK OPTION AND STOCK UNIT PLANS	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
STOCK OPTION AND STOCK UNIT PLANS	STOCK OPTION AND STOCK UNIT PLANS We maintain three long-term incentive compensation plans: the ISO Plan, the PSU Plan and the RSU Plan. Total stock-based compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 was $157 million, $145 million and $117 million, respectively. Disclosure of activity and assumptions for material stock-based compensation plans are included below. INCENTIVE STOCK OPTIONS Certain key employees are granted ISOs to purchase common shares at the grant date market price. ISOs vest in equal annual installments over a four December 31, 2021 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; intrinsic value in millions of Canadian dollars; weighted average exercise price in Canadian dollars) Options outstanding at beginning of year 35,494 48.65 Options granted 4,072 43.86 Options exercised 1 (4,142) 41.85 Options cancelled or expired (1,407) 50.74 Options outstanding at end of year 34,017 49.28 5.7 128 Options vested at end of year 2 22,029 49.84 4.5 64 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $24 million, $13 million and $58 million, respectively, and cash received on exercise was $2 million, $4 million and $1 million, respectively. 2 The total fair value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $25 million, $30 million and $32 million, respectively. Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton option pricing model are as follows: Year ended December 31, 2021 2020 2019 Fair value per option (Canadian dollars) 1 4.10 4.01 4.37 Valuation assumptions Expected option term (years) 2 6 6 5 Expected volatility 3 25.5 % 18.3 % 19.9 % Expected dividend yield 4 7.6 % 5.9 % 6.1 % Risk-free interest rate 5 0.7 % 1.3 % 2.0 % 1 Options granted to US employees are based on NYSE prices. The option value and assumptions shown are based on a weighted average of the US and the Canadian options. The fair values per option for the years ended December 31, 2021, 2020 and 2019 were $3.91, $3.75 and $4.04, respectively, for Canadian employees and US$3.65, US$3.62 and US$4.09, respectively, for US employees. 2 The expected option term is six years based on historical exercise practice and five years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the US Treasury Bond Yields. Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for ISOs was $16 million, $24 million and $32 million, respectively. As at December 31, 2021, unrecognized compensation expense related to non-vested stock-based compensation arrangements granted under the ISO Plan was $11 million. The expense is expected to be fully recognized over a weighted average period of approximately two years. PERFORMANCE STOCK UNITS Under PSU awards for certain key employees, cash awards are paid following a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by Enbridge's weighted average share price for 20 days prior to the maturity of the grant and by a performance multiplier. The performance multiplier ranges from zero, if our performance fails to meet threshold performance levels, to a maximum of two if we perform within the highest range of the performance targets. The performance multiplier is derived through a calculation of our Total Shareholder Return percentile rank, in each case relative to a specified peer group of companies and our distributable cash flow per share, adjusted for unusual, non-operating or non-recurring items, relative to targets established at the time of grant. To calculate the 2021 expense, a multiplier of 0.5 was used for 2021 PSU grants, 0.5 for 2020 PSU grants and 1.3 for the 2019 PSU grants. December 31, 2021 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 3,056 Units granted 1,895 Units cancelled (76) Units matured 1 (1,664) Dividend reinvestment 218 Units outstanding at end of year 3,429 1.1 181 1 The total amount paid during the years ended December 31, 2021, 2020 and 2019 for PSUs was $70 million, $14 million and $19 million, respectively. Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for PSUs was $56 million, $76 million and $40 million, respectively. As at December 31, 2021, unrecognized compensation expense related to non-vested PSUs was $31 million. The expense is expected to be fully recognized over a weighted average period of approximately two years. RESTRICTED STOCK UNITS Under RSU awards, cash awards are paid to certain of our employees vesting in equal installments on each of the first, second and third anniversaries of the grant date. Share settled awards are given to certain senior management employees following a three year maturity period. RSU holders receive cash or shares equal to our weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date. December 31, 2021 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 2,453 Units granted 1,514 Units cancelled (75) Units matured 1 (1,433) Dividend reinvestment 246 Units outstanding at end of year 2,705 1.1 129 1 The total amount paid during the years ended December 31, 2021, 2020 and 2019 for RSUs was $72 million, $27 million and $34 million, respectively. Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for RSUs was $85 million, $44 million and $41 million, respectively. As at December 31, 2021, unrecognized compensation expense related to non-vested RSUs was $62 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.

COMPONENTS OF ACCUMULATED OTHER

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	12 Months Ended
	Dec. 31, 2021
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) Changes in AOCI attributable to our common shareholders for the years ended December 31, 2021, 2020 and 2019 are as follows: Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2021 (1,326) 5 (215) 568 66 (499) (1,401) Other comprehensive income/(loss) retained in AOCI 238 (5) 49 (492) (12) 520 298 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 296 — — — — — 296 Commodity contracts 2 1 — — — — — 1 Foreign exchange contracts 3 5 — — — — — 5 Other contracts 4 2 — — — — — 2 Equity investment disposal — — — — (66) — (66) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — — 28 28 Other 17 — — (20) 3 — — 559 (5) 49 (512) (75) 548 564 Tax impact Income tax on amounts retained in AOCI (61) — — — — (126) (187) Income tax on amounts reclassified to earnings (69) — — — 4 (7) (72) (130) — — — 4 (133) (259) Balance at December 31, 2021 (897) — (166) 56 (5) (84) (1,096) Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2020 (1,073) — (317) 1,396 67 (345) (272) Other comprehensive income/(loss) retained in AOCI (591) 5 115 (828) (2) (221) (1,522) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 253 — — — — — 253 Foreign exchange contracts 3 5 — — — — — 5 Other contracts 4 (2) — — — — — (2) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — — 17 17 (335) 5 115 (828) (2) (204) (1,249) Tax impact Income tax on amounts retained in AOCI 140 — (13) — 1 54 182 Income tax on amounts reclassified to earnings (58) — — — — (4) (62) 82 — (13) — 1 50 120 Balance at December 31, 2020 (1,326) 5 (215) 568 66 (499) (1,401) Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2019 (770) (598) 4,323 34 (317) 2,672 Other comprehensive income/(loss) retained in AOCI (599) 320 (2,927) 34 (124) (3,296) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 157 — — — — 157 Commodity contracts 2 (1) — — — — (1) Foreign exchange contracts 3 5 — — — — 5 Other contracts 4 (3) — — — — (3) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 17 17 (441) 320 (2,927) 34 (107) (3,121) Tax impact Income tax on amounts retained in AOCI 169 (39) — 6 28 164 Income tax on amounts reclassified to earnings (31) — — — (4) (35) 138 (39) — 6 24 129 Other — — — (7) 55 48 Balance at December 31, 2019 (1,073) (317) 1,396 67 (345) (272) 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Transportation and other services revenue, Commodity sales revenue, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenue and Net foreign currency gain in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 These components are included in the computation of net benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS MARKET RISK Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risks). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in US dollar denominated investments and subsidiaries using foreign currency 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 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 3.9%. We are exposed to changes in the fair value of fixed rate debt that arise as a result of 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 fair value via execution of fixed to floating interest rate swaps. As at December 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 including 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 2.0%. 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. TOTAL DERIVATIVE INSTRUMENTS The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments. We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. December 31, 2021 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Derivative Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — — 259 259 (41) 218 Interest rate contracts 64 — — — 64 — 64 Commodity contracts — — — 204 204 (129) 75 Other contracts — — — 2 2 — 2 64 — — 465 529 (170) 359 Deferred amounts and other assets Foreign exchange contracts — — — 240 240 (61) 179 Interest rate contracts 88 — — — 88 (1) 87 Commodity contracts — — — 29 29 (13) 16 Other contracts — — — 3 3 — 3 88 — — 272 360 (75) 285 Accounts payable and other Foreign exchange contracts (15) — (112) (176) (303) 41 (262) Interest rate contracts (150) — — — (150) — (150) Commodity contracts (14) — — (250) (264) 129 (135) Other contracts — — — — — — — (179) — (112) (426) (717) 170 (547) Other long-term liabilities Foreign exchange contracts — — — (423) (423) 61 (362) Interest rate contracts (1) — — (23) (24) 1 (23) Commodity contracts (17) — — (67) (84) 13 (71) Other contracts — — — — — — — (18) — — (513) (531) 75 (456) Total net derivative asset/(liability) Foreign exchange contracts (15) — (112) (100) (227) — (227) Interest rate contracts 1 — — (23) (22) — (22) Commodity contracts (31) — — (84) (115) — (115) Other contracts — — — 5 5 — 5 (45) — (112) (202) (359) — (359) December 31, 2020 Derivative Derivative Derivative Instruments Used as Fair Value Hedges Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — — 180 180 (28) 152 Interest rate contracts — — — — — — — Commodity contracts — — — 143 143 (81) 62 Other contracts — — — — — — — — — — 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 Other contracts — — — — — — — 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) Other contracts — — — — — — — (219) — (87) (753) (1,059) 252 (807) Total net derivative asset/(liability) 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) The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments. 2021 2020 As at December 31, 2022 2023 2024 2025 2026 Thereafter Total Total Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) 2,508 — — — — — 2,508 3,522 Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) 9,245 5,596 4,346 3,174 2,574 492 25,427 17,859 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) 28 29 30 30 28 32 177 265 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 104 92 91 86 85 343 801 885 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) 72,500 — — — — — 72,500 72,500 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 395 47 35 30 26 64 597 4,635 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 2,363 1,784 1,132 — — — 5,279 5,396 Equity contracts (millions of Canadian dollars) 20 26 21 — — — 67 62 Commodity contracts - natural gas (billions of cubic feet) 165 18 5 11 — — 199 173 Commodity contracts - crude oil (millions of barrels) 12 — — — — — 12 15 Commodity contracts - power (megawatt per hour (MW/H) (43) (43) (43) (43) — — (43) 1 (35) 1 1 Total is an average net purchase/(sell) of power. The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: 2021 2020 2019 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (29) (1) (19) Interest rate contracts 252 (595) (559) Commodity contracts (28) 2 (25) Other contracts 1 (3) 10 Fair value hedges Foreign exchange contracts (5) 5 — Net investment hedges Foreign exchange contracts — 13 2 191 (579) (591) Amount of (gain)/loss reclassified from AOCI to earnings Foreign exchange contracts 1 5 5 5 Interest rate contracts 2 296 253 157 Commodity contracts 3 1 — (1) Other contracts 4 2 (2) (3) 304 256 158 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 Transportation and other services revenue, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expenses in the Consolidated Statements of Earnings. We estimate that a loss of $47 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 36 months as at December 31, 2021. Fair Value Derivatives For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings. Year ended December 31, 2021 2020 (millions of Canadian dollars) Unrealized gain/(loss) on derivative 8 (116) Unrealized gain/(loss) on hedged item (15) 133 Realized loss on derivative (41) (12) Realized gain on hedged item 45 — Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Foreign exchange contracts 1 92 902 1,626 Interest rate contracts 2 2 (25) 178 Commodity contracts 3 71 (114) (62) Other contracts 4 8 (7) 9 Total unrealized derivative fair value gain/(loss), net 173 756 1,751 1 For the respective annual periods, reported within Transportation and other services revenue (2021 - $98 million gain; 2020 - $533 million gain; 2019 - $930 million gain) and Net foreign currency gain/(loss) (2021 - $6 million loss; 2020 - $369 million gain; 2019 - $696 million gain) in the Consolidated Statements of Earnings. 2 Reported as an increase within Interest expense in the Consolidated Statements of Earnings. 3 For the respective annual periods, reported within Transportation and other services revenue (2021 - $9 million gain; 2020 - $2 million loss; 2019 - $26 million loss), Commodity sales (2021 - $160 million gain; 2020 - $321 million loss; 2019 - $544 million loss), Commodity costs (2021 - $105 million loss; 2020 - $207 million gain; 2019 - $459 million gain) and Operating and administrative expense (2021 - $7 million gain; 2020 - $2 million gain; 2019 - $49 million gain) 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 December 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. We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2021 2020 (millions of Canadian dollars) Canadian financial institutions 424 481 US financial institutions 130 99 European financial institutions 181 28 Asian financial institutions 30 167 Other 1 122 97 887 872 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at December 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 December 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, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts 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 classify and provide for receivables older than 30 days as past due. 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. 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 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 contracts and NGL and natural gas contracts, basis swaps, commodity swaps, power and energy swaps, as well as physical forward commodity contracts. We do not have any other financial instruments categorized in Level 3. We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value. We have categorized our derivative assets and liabilities measured at fair value as follows: December 31, 2021 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 259 — 259 Interest rate contracts — 64 — 64 Commodity contracts 38 71 95 204 Other contracts — 2 — 2 38 396 95 529 Long-term derivative assets Foreign exchange contracts — 240 — 240 Interest rate contracts — 88 — 88 Commodity contracts — 21 8 29 Other contracts — 3 — 3 — 352 8 360 Financial liabilities Current derivative liabilities Foreign exchange contracts — (303) — (303) Interest rate contracts — (150) — (150) Commodity contracts (52) (66) (146) (264) Other contracts — — — — (52) (519) (146) (717) Long-term derivative liabilities Foreign exchange contracts — (423) — (423) Interest rate contracts — (24) — (24) Commodity contracts — (19) (65) (84) Other contracts — — — — — (466) (65) (531) Total net financial asset/(liability) Foreign exchange contracts — (227) — (227) Interest rate contracts — (22) — (22) Commodity contracts (14) 7 (108) (115) Other contracts — 5 — 5 (14) (237) (108) (359) 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 Interest rate contracts — — — — Commodity contracts 43 33 67 143 Other contracts — — — — 43 213 67 323 Long-term derivative assets Foreign exchange contracts — 466 — 466 Interest rate contracts — 56 — 56 Commodity contracts 1 24 14 39 Other contracts — — — — 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) Other contracts — — — — (1) (1,009) (49) (1,059) Total net financial asset/(liability) 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: December 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 (19) Forward gas price 3.12 9.05 4.49 $/mmbtu 2 Crude 3 Forward crude price 76.02 98.99 91.73 $/barrel Power (60) Forward power price 31.00 125.13 76.23 $/MW/H Commodity contracts - physical 1 Natural gas (56) Forward gas price 2.65 9.25 4.63 $/mmbtu 2 Crude 24 Forward crude price 68.66 97.00 87.97 $/barrel (108) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One million British thermal units (mmbtu). If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices, and for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility. Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 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 (39) (123) Included in OCI (29) 2 Settlements 151 (1) Level 3 net derivative liability at end of period (108) (191) 1 Reported within Transportation and other services revenue, Commodity costs and Operating and administrative expenses in the Consolidated Statements of Earnings. There were no transfers into or out of Level 3 as at December 31, 2021 or 2020. NET INVESTMENT HEDGES We have designated a portion of our US dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of our net investment in US dollar denominated investments and subsidiaries. During the years ended December 31, 2021 and 2020, we recognized unrealized foreign exchange gains of $49 million and $117 million, respectively, on the translation of US dollar denominated debt and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of nil and $13 million, respectively, in OCI. During the years ended December 31, 2021 and 2020, we recognized a realized loss of nil and $15 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts. No realized gains or losses associated with the settlement of US dollar denominated debt that had matured during the period were recognized in OCI during the years ended December 31, 2021 and 2020. FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS Certain long-term investments in other entities with no actively quoted prices are classified as FVMA investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $52 million as at December 31, 2021 and 2020. We have Restricted long-term investments held in trust totaling $630 million and $553 million as at December 31, 2021 and 2020, respectively, which are recognized at fair value. As at December 31, 2021 and 2020, our long-term debt had a carrying value of $74.4 billion and $66.1 billion, respectively, before debt issuance costs and a fair value of $82.0 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 December 31, 2021 and 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.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES INCOME TAX RATE RECONCILIATION Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Earnings before income taxes 7,729 4,190 7,535 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 1,159 629 1,130 Increase/(decrease) resulting from: Provincial and state income taxes 1 228 288 415 Foreign and other statutory rate differentials 2 134 (53) 129 Effects of rate-regulated accounting 3 (139) (145) (63) Foreign allowable interest deductions 4 — (4) (29) Part VI.1 tax, net of federal Part I deduction 5 73 76 78 US Minimum Tax 6 — 44 67 Non-taxable portion of gain on sale of investment 7 (23) — — Valuation allowance 8 5 (6) 26 Intercorporate investments 9 — — (14) Noncontrolling interests (17) (8) (13) Other (5) (47) (18) Income tax expense 1,415 774 1,708 Effective income tax rate 18.3% 18.5% 22.7% 1 The change in provincial and state income taxes from 2020 to 2021 reflects the 2020 impact of state tax apportionment and rate changes in both the US and Canada offset by the increase in earnings from US and Canadian operations in 2021. 2 The change in foreign and other statutory rate differentials from 2020 to 2021 reflects the increase in earnings from US operations partially offset by higher rate benefits from foreign operations. 3 The amount in 2019 included the federal component of the tax benefit of the write-off of regulatory assets. 4 The decrease in foreign allowable interest deductions from 2019 to 2021 was due to changes in the related loan portfolio. 5 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 6 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation. 7 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco. 8 The increase in 2021 is due to the federal component of the tax effect of a valuation allowance on additional deferred tax assets that are not more likely than not to be realized. 9 The amount in 2019 relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate investments such that deferred tax related to outside basis temporary differences was required to be recorded for MATL. COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Earnings before income taxes Canada 3,399 2,789 3,560 US 3,336 407 3,115 Other 994 994 860 7,729 4,190 7,535 Current income taxes Canada 162 165 347 US 80 64 107 Other 82 98 98 324 327 552 Deferred income taxes Canada 344 378 490 US 741 66 672 Other 6 3 (6) 1,091 447 1,156 Income tax expense 1,415 774 1,708 COMPONENTS OF DEFERRED INCOME TAXES Deferred income tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are as follows: December 31, 2021 2020 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (8,721) (7,786) Investments (6,097) (4,649) Regulatory assets (1,245) (1,156) Other (208) (127) Total deferred income tax liabilities (16,271) (13,718) Deferred income tax assets Financial instruments 315 518 Pension and OPEB plans 110 251 Loss carryforwards 3,081 2,005 Other 1,648 1,461 Total deferred income tax assets 5,154 4,235 Less valuation allowance (84) (79) Total deferred income tax assets, net 5,070 4,156 Net deferred income tax liabilities (11,201) (9,562) Presented as follows: Total deferred income tax assets 488 770 Total deferred income tax liabilities (11,689) (10,332) Net deferred income tax liabilities (11,201) (9,562) A valuation allowance has been established for certain loss and credit carryforwards, and outside basis temporary differences on investments that reduce deferred income tax assets to an amount that will more likely than not be realized. As at December 31, 2021, we recognized the benefit of unused tax loss carryforwards of $1.9 billion (2020 - $2.6 billion) in Canada which expire in 2026 and beyond. As at December 31, 2021, we recognized the benefit of unused tax loss carryforwards of $11.0 billion (2020 - $5.8 billion) in the US. Unused tax loss carryforwards of $3.5 billion (2020 - $2.4 billion) begin to expire in 2023, and unused tax loss carryforwards of $7.5 billion (2020 - $3.4 billion) have no expiration. We have not provided for deferred income taxes on the difference between the carrying value of substantially all of our foreign subsidiaries and their corresponding tax basis as the earnings of those subsidiaries are intended to be permanently reinvested in their operations. As such, these investments are not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying values of the investments and their tax bases is largely a result of unremitted earnings and currency translation adjustments. The unremitted earnings and currency translation adjustment for which no deferred taxes have been recognized in respect of foreign subsidiaries were $4.3 billion and $5.5 billion for the periods December 31, 2021 and 2020, respectively. If such earnings are remitted, in the form of dividends or otherwise, we may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is not practicable. Enbridge and certain of our subsidiaries are subject to taxation in Canada, the US and other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations include the US (Federal) and Canada (Federal, Alberta and Ontario). We are open to examination by Canadian tax authorities for the 2012 to 2021 tax years and by US tax authorities for the 2018 to 2021 tax years. We are currently under examination for income tax matters in Canada for the 2014 to 2018 tax years. We are not currently under examination for income tax matters in any other material jurisdiction where we are subject to income tax. UNRECOGNIZED TAX BENEFITS Year ended December 31, 2021 2020 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 121 129 Gross increases for tax positions of current year 1 1 Gross decreases for tax positions of prior year (26) (1) Change in translation of foreign currency (1) (3) Lapses of statute of limitations (19) (5) Unrecognized tax benefits at end of year 76 121 The unrecognized tax benefits as at December 31, 2021, if recognized, would impact our effective income tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on our consolidated financial statements. We recognize accrued interest and penalties related to unrecognized tax benefits as a component of income taxes. Interest and penalties included in income taxes for the years ended December 31, 2021 and 2020 were a $5 million recovery and $3 million expense, respectively. As at December 31, 2021 and 2020, interest and penalties of $12 million and $17 million, respectively, have been accrued.

PENSION AND OTHER POSTRETIREMEN

PENSION AND OTHER POSTRETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2021
Retirement Benefits [Abstract]
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS PENSION PLANS We sponsor Canadian and US contributory and non-contributory registered defined benefit and defined contribution pension plans, which provide benefits covering substantially all employees. The Canadian Plans provide defined benefit and defined contribution pension benefits to our Canadian employees. The US Plans provide defined benefit pension benefits to our US employees. We also sponsor supplemental non-contributory defined benefit pension plans, which provide non-registered benefits for certain employees in Canada and the US. Defined Benefit Pension Plan Benefits Benefits payable from the defined benefit pension plans are based on each plan participant’s years of service and final average remuneration. Some benefits are partially inflation-indexed after a plan participant’s retirement. Our contributions are made in accordance with independent actuarial valuations. Participant contributions to contributory defined benefit pension plans are based upon each plan participant’s current eligible remuneration. Defined Contribution Pension Plan Benefits Our contributions are based on each plan participant’s current eligible remuneration. Our contributions for some defined contribution pension plans are also based on age and years of service. Our defined contribution pension benefit costs are equal to the amount of contributions required to be made by us. Benefit Obligations, Plan Assets and Funded Status The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit pension plans: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 4,855 4,446 1,243 1,230 Service cost 139 148 44 44 Interest cost 101 128 17 31 Participant contributions 28 31 — — Actuarial (gain)/loss 1 (329) 292 (21) 95 Benefits paid (194) (190) (84) (128) Foreign currency exchange rate changes — — (11) (23) Other — — (4) (6) Projected benefit obligation at end of year 2 4,600 4,855 1,184 1,243 Change in plan assets Fair value of plan assets at beginning of year 4,077 3,827 1,062 1,104 Actual return on plan assets 505 288 151 83 Employer contributions 120 121 43 27 Participant contributions 28 31 — — Benefits paid (194) (190) (84) (128) Foreign currency exchange rate changes — — (8) (18) Other — — (4) (6) Fair value of plan assets at end of year 3 4,536 4,077 1,160 1,062 Underfunded status at end of year (64) (778) (24) (181) Presented as follows: Deferred amounts and other assets 250 35 98 — Accounts payable and other (9) (9) (4) (3) Other long-term liabilities (305) (804) (118) (178) (64) (778) (24) (181) 1 Primarily due to increase in the discount rate used to measure the benefit obligations (2020 - primarily due to decrease in the discount rate used to measure the benefit obligations). 2 The accumulated benefit obligation for our Canadian pension plans was $4.3 billion and $4.5 billion as at December 31, 2021 and 2020, respectively. The accumulated benefit obligation for our US pension plans was $1.1 billion and $1.2 billion as at December 31, 2021 and 2020, respectively. 3 Assets in the amount of $13 million (2020 - $11 million) and $84 million (2020 - $59 million), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in grantor trusts and rabbi trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes. Certain of our pension plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the accumulated benefit obligation and fair value of plan assets were as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Accumulated benefit obligation 440 4,094 115 1,207 Fair value of plan assets 247 3,621 — 1,062 Certain of our pension plans have projected benefit obligations in excess of the fair value of plan assets. For these plans, the projected benefit obligation and fair value of plan assets were as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Projected benefit obligation 1,272 4,434 121 1,243 Fair value of plan assets 1,020 3,621 — 1,062 Amount Recognized in Accumulated Other Comprehensive Income The amount of pre-tax AOCI relating to our pension plans are as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Net actuarial loss 226 542 92 233 Prior service credit — — (1) (1) Total amount recognized in AOCI 1 226 542 91 232 1 Excludes amounts related to cumulative translation adjustment. Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our pension plans are as follows: Canada US Year ended December 31, 2021 2020 2019 2021 2020 2019 (millions of Canadian dollars) Service cost 139 148 149 44 44 45 Interest cost 1 101 128 139 17 31 41 Expected return on plan assets 1 (252) (260) (245) (73) (88) (78) Amortization/settlement of net actuarial loss 1 54 42 41 11 1 2 Amortization/curtailment of prior service credit 1 — — — — (1) (1) Net periodic benefit (credit)/cost 42 58 84 (1) (13) 9 Defined contribution benefit cost 7 6 8 — — — Net pension (credit)/cost recognized in Earnings 49 64 92 (1) (13) 9 Amount recognized in OCI: Effect of plan combination — — — — — (6) Amortization/settlement of net actuarial loss (25) (21) (26) (11) (1) (2) Amortization/curtailment of prior service credit — — — — 1 1 Net actuarial (gain)/loss arising during the year (291) 118 115 (99) 100 8 Total amount recognized in OCI (316) 97 89 (110) 100 1 Total amount recognized in Comprehensive income (267) 161 181 (111) 87 10 1 Reported within Other income/(expense) in the Consolidated Statements of Earnings. Actuarial Assumptions The weighted average assumptions made in the measurement of the projected benefit obligation and net periodic benefit cost of our pension plans are as follows: Canada US 2021 2020 2019 2021 2020 2019 Projected benefit obligation Discount rate 3.2 % 2.6 % 3.0 % 2.6 % 2.2 % 3.0 % Rate of salary increase 2.9 % 2.3 % 3.2 % 2.8 % 2.7 % 2.9 % Cash balance interest credit rate N/A N/A N/A 4.3 % 4.3 % 4.5 % Net periodic benefit cost Discount rate 2.6 % 3.0 % 3.8 % 2.2 % 3.0 % 3.9 % Rate of return on plan assets 6.2 % 6.8 % 7.0 % 7.3 % 7.9 % 8.0 % Rate of salary increase 2.3 % 3.2 % 3.2 % 2.7 % 2.9 % 2.9 % Cash balance interest credit rate N/A N/A N/A 4.3 % 4.5 % 4.5 % OTHER POSTRETIREMENT BENEFIT PLANS We sponsor funded and unfunded defined benefit OPEB Plans, which provide non-contributory supplemental health, dental, life and health spending account benefit coverage for certain qualifying retired employees. Benefit Obligations, Plan Assets and Funded Status The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit OPEB plans: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 321 293 254 288 Service cost 6 5 1 2 Interest cost 7 8 3 7 Participant contributions — — 8 4 Actuarial (gain)/loss 1 (51) 21 (69) 17 Benefits paid (9) (6) (22) (28) Plan amendments — — — (33) Foreign currency exchange rate changes — — (3) (4) Other — — 1 1 Accumulated postretirement benefit obligation at end of year 274 321 173 254 Change in plan assets Fair value of plan assets at beginning of year — — 188 188 Actual return on plan assets — — 22 14 Employer contributions 9 6 6 12 Participant contributions — — 8 4 Benefits paid (9) (6) (22) (28) Foreign currency exchange rate changes — — (3) (3) Other — — 2 1 Fair value of plan assets at end of year — — 201 188 Overfunded/(underfunded) status at end of year (274) (321) 28 (66) Presented as follows: Deferred amounts and other assets — — 71 19 Accounts payable and other (12) (13) — (6) Other long-term liabilities (262) (308) (43) (79) (274) (321) 28 (66) 1 Primarily due to increase in the discount rate used to measure the benefit obligations ( 2020 - primarily due to decrease in the discount rate used to measure the benefit obligations) . Certain of our OPEB plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the accumulated benefit obligation and fair value of plan assets were as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Accumulated benefit obligation 274 321 94 191 Fair value of plan assets — — 51 106 Amount Recognized in Accumulated Other Comprehensive Income The amount of pre-tax AOCI relating to our OPEB plans are as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Net actuarial (gain)/loss (35) 15 (104) (7) Prior service credit (1) (1) (37) (44) Total amount recognized in AOCI 1 (36) 14 (141) (51) 1 Excludes amounts related to cumulative translation adjustment. Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows: Canada US Year ended December 31, 2021 2020 2019 2021 2020 2019 (millions of Canadian dollars) Service cost 6 5 5 1 2 2 Interest cost 1 7 8 10 3 7 10 Expected return on plan assets 1 — — — (10) (12) (12) Amortization/settlement of net actuarial gain 1 — (1) (7) (1) (1) — Amortization/curtailment of prior service credit 1 — — (1) (7) (2) (2) Net periodic benefit (credit)/cost recognized in Earnings 13 12 7 (14) (6) (2) Amount recognized in OCI: Amortization/settlement of net actuarial gain — 1 7 1 1 — Amortization/curtailment of prior service credit — — 1 7 2 2 Net actuarial (gain)/loss arising during the year (50) 21 15 (80) 15 (8) Prior service credit — — — — (33) — Total amount recognized in OCI (50) 22 23 (72) (15) (6) Total amount recognized in Comprehensive income (37) 34 30 (86) (21) (8) 1 Reported within Other income/(expense) in the Consolidated Statements of Earnings. Actuarial Assumptions The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligation and net periodic benefit cost of our OPEB plans are as follows: Canada US 2021 2020 2019 2021 2020 2019 Accumulated postretirement benefit obligation Discount rate 3.2 % 2.6 % 3.1 % 2.4 % 2.0 % 2.8 % Net periodic benefit cost Discount rate 2.6 % 3.1 % 3.8 % 2.0 % 2.8 % 4.0 % Rate of return on plan assets N/A N/A N/A 6.0 % 6.7 % 6.7 % Assumed Health Care Cost Trend Rates The assumed rates for the next year used to measure the expected cost of benefits are as follows: Canada US 2021 2020 2021 2020 Health care cost trend rate assumed for next year 4.0 % 4.0 % 7.0 % 6.8 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.0 % 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2037 2037 PLAN ASSETS We manage the investment risk of our pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) our operating environment and financial situation and our ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets. The overall expected rate of return on plan assets is based on the asset allocation targets with estimates for returns based on long-term expectations. The asset allocation targets and major categories of plan assets are as follows: Canada US Target December 31, Target December 31, Asset Category Allocation 2021 2020 Allocation 2021 2020 Equity securities 43.8 % 46.7 % 47.2 % 45.0 % 52.5 % 55.6 % Fixed income securities 28.9 % 29.8 % 29.6 % 20.1 % 18.4 % 17.2 % Alternatives 1 27.3 % 23.5 % 23.2 % 34.9 % 29.1 % 27.2 % 1 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Fund values are based on the net asset value of the funds that invest directly in the aforementioned underlying investments. The values of the investments have been estimated using the capital accounts representing the plan's ownership interest in the funds. Pension Plans The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level: Canada US Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2021 Cash and cash equivalents 180 — — 180 10 — — 10 Equity securities Canada 198 228 — 426 — — — — US 1 — — 1 — — — — Global — 1,693 — 1,693 — 609 — 609 Fixed income securities Government 258 459 — 717 — 86 — 86 Corporate — 453 — 453 — 118 — 118 Alternatives 4 — — 1,064 1,064 — — 337 337 Forward currency contracts — 2 — 2 — — — — Total pension plan assets at fair value 637 2,835 1,064 4,536 10 813 337 1,160 December 31, 2020 Cash and cash equivalents 213 — — 213 5 — — 5 Equity securities Canada 178 188 — 366 — — — — US 2 — — 2 — — — — Global — 1,556 — 1,556 — 590 — 590 Fixed income securities Government 207 378 — 585 — 75 — 75 Corporate — 410 — 410 — 103 — 103 Alternatives 4 — — 912 912 — — 289 289 Forward currency contracts — 33 — 33 — — — — Total pension plan assets at fair value 600 2,565 912 4,077 5 768 289 1,062 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Changes in the net fair value of pension plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Balance at beginning of year 912 852 289 276 Unrealized and realized gains/(losses) 77 (27) 38 7 Purchases and settlements, net 75 87 10 6 Balance at end of year 1,064 912 337 289 OPEB Plans The following table summarizes the fair value of plan assets for our US funded OPEB plans recorded at each fair value hierarchy level: Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2021 Cash and cash equivalents 4 — — 4 Equity securities US — 39 — 39 Global — 75 — 75 Fixed income securities Government 47 6 — 53 Corporate — 8 — 8 Alternatives 4 — — 22 22 Total OPEB plan assets at fair value 51 128 22 201 December 31, 2020 Equity securities US — 35 — 35 Global — 79 — 79 Fixed income securities Government 38 6 — 44 Corporate — 8 — 8 Alternatives 4 — — 22 22 Total OPEB plan assets at fair value 38 128 22 188 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives includes investments in private debt, private equity, infrastructure and real estate. Changes in the net fair value of US funded OPEB plan assets classified as Level 3 in the fair value hierarchy were as follows: December 31, 2021 2020 (millions of Canadian dollars) Balance at beginning of year 22 18 Unrealized and realized gains 2 1 Purchases and settlements, net (2) 3 Balance at end of year 22 22 EXPECTED BENEFIT PAYMENTS Year ending December 31, 2022 2023 2024 2025 2026 2027-2031 (millions of Canadian dollars) Pension Canada 197 203 208 212 217 1,163 US 80 78 78 76 77 374 OPEB Canada 12 12 12 13 13 67 US 17 15 14 13 12 51 EXPECTED EMPLOYER CONTRIBUTIONS In 2022, we expect to contribute approximately $110 million and $4 million to the Canadian and US pension plans, respectively, and $12 million and $6 million to the Canadian and US OPEB plans, respectively. RETIREMENT SAVINGS PLANS In addition to the pension and OPEB plans discussed above, we also have defined contribution employee savings plans available to US employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 6.0% of eligible pay per pay period. For the years ended December 31, 2021, 2020 and 2019, pre-tax employer matching contribution costs were $27 million each year, respectively.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
LEASES	LEASES LESSEE We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 5 months to 25 years as at December 31, 2021. For the years ended December 31, 2021 and 2020, we incurred operating lease expenses of $95 million and $107 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings. For the years ended December 31, 2021 and 2020, operating lease payments to settle lease liabilities were $118 million and $133 million, respectively. Operating lease payments are reported under Operating activities in the Consolidated Statements of Cash Flows. Supplemental Statements of Financial Position Information December 31, 2021 December 31, (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 645 708 Operating lease liabilities - current 3 92 80 Operating lease liabilities - long-term 3 612 681 Total operating lease liabilities 704 761 Finance leases Finance lease right-of-use assets, net 4 49 57 Finance lease liabilities - current 5 13 11 Finance lease liabilities - long-term 3 33 42 Total finance lease liabilities 46 53 Weighted average remaining lease term Operating leases 12 years 13 years Finance leases 7 years 7 years Weighted average discount rate Operating leases 4.1 % 4.1 % Finance leases 3.8 % 3.8 % 1 Affiliate right-of-use assets, current lease liabilities and long-term lease liabilities as at December 31, 2021 were $51 million (December 31, 2020 - $65 million), $5 million (December 31, 2020 - $5 million) and $47 million (December 31, 2020 - $52 million), respectively. 2 Operating lease right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position. 3 Current operating lease liabilities and long-term operating and finance lease liabilities are reported under Accounts payable and other and Other long-term liabilities, respectively, in the Consolidated Statements of Financial Position. 4 Finance lease right-of-use assets are reported under Property, plant and equipment, net in the Consolidated Statements of Financial Position. 5 Current finance lease liabilities are reported under Current portion of long-term debt in the Consolidated Statements of Financial Position. As at December 31, 2021, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance leases (millions of Canadian dollars) 2022 117 15 2023 98 13 2024 91 9 2025 84 2 2026 72 1 Thereafter 455 11 Total undiscounted lease payments 917 51 Less imputed interest (213) (5) Total 704 46 LESSOR We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our operating leases have remaining lease terms of 1 month to 30 years as at December 31, 2021. Year ended December 31, 2021 2020 (millions of Canadian dollars) Operating lease income 263 265 Variable lease income 333 361 Total lease income 1 596 626 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2021, the following table sets out future lease payments to be received under operating lease contracts where we are the lessor: Operating leases (millions of Canadian dollars) 2022 235 2023 215 2024 205 2025 196 2026 191 Thereafter 1,938 Future lease payments 2,980
LEASES	LEASES LESSEE We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 5 months to 25 years as at December 31, 2021. For the years ended December 31, 2021 and 2020, we incurred operating lease expenses of $95 million and $107 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings. For the years ended December 31, 2021 and 2020, operating lease payments to settle lease liabilities were $118 million and $133 million, respectively. Operating lease payments are reported under Operating activities in the Consolidated Statements of Cash Flows. Supplemental Statements of Financial Position Information December 31, 2021 December 31, (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 645 708 Operating lease liabilities - current 3 92 80 Operating lease liabilities - long-term 3 612 681 Total operating lease liabilities 704 761 Finance leases Finance lease right-of-use assets, net 4 49 57 Finance lease liabilities - current 5 13 11 Finance lease liabilities - long-term 3 33 42 Total finance lease liabilities 46 53 Weighted average remaining lease term Operating leases 12 years 13 years Finance leases 7 years 7 years Weighted average discount rate Operating leases 4.1 % 4.1 % Finance leases 3.8 % 3.8 % 1 Affiliate right-of-use assets, current lease liabilities and long-term lease liabilities as at December 31, 2021 were $51 million (December 31, 2020 - $65 million), $5 million (December 31, 2020 - $5 million) and $47 million (December 31, 2020 - $52 million), respectively. 2 Operating lease right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position. 3 Current operating lease liabilities and long-term operating and finance lease liabilities are reported under Accounts payable and other and Other long-term liabilities, respectively, in the Consolidated Statements of Financial Position. 4 Finance lease right-of-use assets are reported under Property, plant and equipment, net in the Consolidated Statements of Financial Position. 5 Current finance lease liabilities are reported under Current portion of long-term debt in the Consolidated Statements of Financial Position. As at December 31, 2021, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance leases (millions of Canadian dollars) 2022 117 15 2023 98 13 2024 91 9 2025 84 2 2026 72 1 Thereafter 455 11 Total undiscounted lease payments 917 51 Less imputed interest (213) (5) Total 704 46 LESSOR We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our operating leases have remaining lease terms of 1 month to 30 years as at December 31, 2021. Year ended December 31, 2021 2020 (millions of Canadian dollars) Operating lease income 263 265 Variable lease income 333 361 Total lease income 1 596 626 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings. As at December 31, 2021, the following table sets out future lease payments to be received under operating lease contracts where we are the lessor: Operating leases (millions of Canadian dollars) 2022 235 2023 215 2024 205 2025 196 2026 191 Thereafter 1,938 Future lease payments 2,980

CHANGES IN OPERATING ASSETS AND

CHANGES IN OPERATING ASSETS AND LIABILITIES	12 Months Ended
	Dec. 31, 2021
CHANGES IN OPERATING ASSETS AND LIABILITIES
CHANGES IN OPERATING ASSETS AND LIABILITIES	CHANGES IN OPERATING ASSETS AND LIABILITIES Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Accounts receivable and other (1,228) 1,546 (547) Accounts receivable from affiliates (38) 8 6 Inventory (118) (254) (24) Deferred amounts and other assets (195) (586) 133 Accounts payable and other (63) (770) 63 Accounts payable to affiliates 52 1 (24) Interest payable 43 31 (41) Other long-term liabilities (69) 117 175 (1,616) 93 (259)

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS Related party transactions are conducted in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. We provide transportation services to several significantly influenced investees which we record as transportation and other servic es revenue. We also purchase and sell natural gas and crude oil with several of our significantly influenced investees. Thes e revenues and costs are recorded as commodity sales and commodity costs. We contract for firm transportation services to meet our annual natural gas supply requirements which we record as gas distribution costs. Our transactions with significantly influenced investees are as follows: Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Transportation and other services 149 133 140 Commodity sales 20 21 107 Operating and administrative 1 292 252 241 Commodity costs 2 790 518 773 Gas distribution costs 131 135 133 1 During the years December 31, 2021, 2020 and 2019, we had Operating and administrative costs from the Seaway Crude Pipeline System of $389 million, $342 million and $327 million, respectively. These costs are a result of an operational contract where we utilize capacity on Seaway Crude Pipeline System assets for use in our Liquids Pipelines business. The costs are offset by recoveries recorded on expenses incurred by us on behalf of our significantly influenced investees of $104 million, $94 million and $86 million for the years ended December 31, 2021, 2020 and 2019. 2 During the years December 31, 2021, 2020 and 2019, we had Commodity costs from the Aux Sable Canada LP. of $447 million, $91 million and $272 million, respectively. LONG-TERM NOTES RECEIVABLE FROM AFFILIATES As at December 31, 2021, amounts receivable from affiliates include a series of loans totaling $954 million ($1,108 million as at December 31, 2020), which require quarterly or semi-annual interest payments at annual interest rates ranging from 3% to 8%. Interest income recognized from these notes totaled $39 million, $44 million and $40 million for the years ended December 31, 2021, 2020 and 2019, respectively. The amounts receivable from affiliates are included in Deferred amounts and other assets in the Consolidated Statements of Financial position.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS As at December 31, 2021, we have commitments as detailed below: Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Annual debt maturities 1 73,809 6,164 7,910 4,559 4,357 11,007 39,812 Interest obligations 2 36,044 2,531 2,389 2,229 2,073 1,925 24,897 Purchase of services, pipe and other materials, including transportation 3 7,876 2,945 1,010 736 561 607 2,017 Maintenance agreements 346 41 20 20 21 21 223 Right-of-ways commitments 1,249 35 35 35 36 37 1,071 Total 119,324 11,716 11,364 7,579 7,048 13,597 68,020 1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discounts, debt issuance costs, finance lease obligations and fair value adjustment. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. 2 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates. 3 Includes capital and operating commitments. Consists primarily of gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments. ENVIRONMENTAL We are subject to various Canadian and US federal, state and local laws relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us. Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge and its affiliates are, at times, subject to environmental remediation at various sites where we operate. We manage this environmental risk through appropriate environmental policies, programs and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with our operating activities. AUX SABLE On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. On November 27, 2019, the counterparty filed an amended amended claim providing further particulars of its claim against Aux Sable, increasing its damages claimed, and adding defendants Aux Sable Liquid Products Inc. and Aux Sable Extraction LLC (general partners of the previously existing defendants). Aux Sable filed an amended Statement of Defence responding to the amended amended claim on January 31, 2020. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on our consolidated financial position or results of operations. TAX MATTERS We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review. 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.

GUARANTEES

GUARANTEES	12 Months Ended
	Dec. 31, 2021
Guarantees [Abstract]
GUARANTEES	GUARANTEES In the normal course of conducting business, we may enter into agreements which indemnify third parties and affiliates. We may also be a party to agreements with subsidiaries, jointly owned entities, unconsolidated entities such as equity method investees, or entities with other ownership arrangements that require us to provide financial and performance guarantees. Financial guarantees include stand-by letters of credit, debt guarantees, surety bonds and indemnifications. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Consolidated Statements of Financial Position. Performance guarantees require us to make payments to a third party if the guaranteed entity does not perform on its contractual obligations, such as debt agreements, purchase or sale agreements, and construction contracts and leases. We typically enter into these arrangements to facilitate commercial transactions with third parties. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations, warranties or covenants, loss or damages to property, environmental liabilities, and litigation and contingent liabilities. We may indemnify third parties for certain liabilities relating to environmental matters arising from operations prior to the purchase or transfer of certain assets and interests. Similarly, we may indemnify the purchaser of assets for certain tax liabilities incurred while we owned the assets, a misrepresentation related to taxes that result in a loss to the purchaser or other certain tax liabilities related to those assets. The likelihood of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We cannot reasonably estimate the total maximum potential amounts that could become payable to third parties and affiliates under such agreements described above; however, historically, we have not made any significant payments under guarantee or indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the guarantee or indemnification obligation, there are circumstances where the amount and duration are unlimited. As at December 31, 2021 guarantees and indemnifications have not had, and are not reasonably likely to have, a material effect on our financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED) Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2021 Operating revenues 12,187 10,948 11,466 12,470 47,071 Operating income 2,548 1,816 1,388 2,053 7,805 Earnings 2,014 1,521 814 1,965 6,314 Earnings attributable to controlling interests 1,992 1,484 780 1,933 6,189 Earnings attributable to common shareholders 1,900 1,394 682 1,840 5,816 Earnings per common share Basic 0.94 0.69 0.34 0.91 2.87 Diluted 0.94 0.69 0.34 0.91 2.87 2020 Operating revenues 12,013 7,956 9,110 10,008 39,087 Operating income 1,513 2,098 2,095 2,251 7,957 Earnings/(loss) (1,364) 1,777 1,104 1,899 3,416 Earnings/(loss) attributable to controlling interests (1,333) 1,741 1,084 1,871 3,363 Earnings/(loss) attributable to common shareholders (1,429) 1,647 990 1,775 2,983 Earnings/(loss) per common share Basic (0.71) 0.82 0.49 0.88 1.48 Diluted (0.71) 0.82 0.49 0.88 1.48

SIGNIFICANT ACCOUNTING POLICI_2

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
BASIS OF PRESENTATION AND USE OF ESTIMATES	(Note 7) ; purchase price allocations (Note 8) ; unbilled revenues; expected credit losses; depreciation rates and carrying value of property, plant and equipment (Note 11) ; amortization rates and carrying value of intangible assets (Note 15) ; measurement of goodwill (Note 16) ; fair value of asset retirement obligations (ARO) (Note 19) ; valuation of stock-based compensation (Note 22) ; fair value of financial instruments (Note 24) ; provisions for income taxes (Note 25) ; assumptions used to measure retirement benefits and OPEB (Note 26) ; commitments and contingencies (Note 30) ; and estimates of losses related to environmental remediation obligations (Note 30) . Actual results could differ from these estimates.
RECLASSIFICATION	Certain comparative figures in our consolidated financial statements have been reclassified to conform to the current year's presentation.
PRINCIPLES OF CONSOLIDATION	All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method.
REGULATION	REGULATION Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the Canada Energy Regulator (CER), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, the Ontario Energy Board (OEB) and La Régie de l’energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the CER’s Land Matters Consultation Initiative (LMCI). Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. We believe that the recovery of our regulatory assets as at December 31, 2021 is probable over the periods described in Note 7 - Regulatory Matters . Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. The corresponding impact on earnings is included in Interest expense for the interest component and Other income/(expense) for the equity component. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation relating to the equity component would not be recognized. Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified. With the approval of regulators, certain operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred . For certain regulated operations to which US GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with US GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with US GAAP and no regulatory asset is recorded.
REVENUE RECOGNITION/NATURAL GAS IMBALANCES	REVENUE RECOGNITION For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer creditworthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts ratably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote. Certain offshore pipeline transportation contracts require us to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay us a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For the years ended December 31, 2021, 2020 and 2019, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $127 million, $292 million and $169 million, respectively. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utility revenues are recorded based on regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise areas. Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded on a gross basis as the related contracts are not held for trading purposes and we are acting as the principal in the transactions. NATURAL GAS IMBALANCES The Consolidated Statements of Financial Position include balances as a result of differences in gas volumes received from, and delivered for, customers. As settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates.
DERIVATIVE INSTRUMENTS AND HEDGING	DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Commodity sales, Transportation and other services revenue, Commodity costs, Operating and administrative expense, Net foreign currency gain/(loss) and Interest expense. Derivatives in Qualifying Hedging Relationships We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires us to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges. Cash Flow Hedges We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized in earnings concurrently with the related transaction. If an anticipated hedged transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges We may use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged risk of the asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged risk of the asset or liability ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Net Investment Hedges Gains and losses arising from the translation of our net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA), a component of OCI. 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. As a result, the change in fair value of the foreign currency derivatives as well as the translation of US dollar denominated debt are reflected in OCI. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from the disposal of a foreign operation. Classification of Derivatives We recognize the fair value of derivative instruments in the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Operating activities in the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis. Transaction Costs Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account for these costs as a reduction to Long-term debt in the Consolidated Statements of Financial Position. These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense.
EQUITY INVESTMENTS	EQUITY INVESTMENTS Equity investments over which we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for our proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to, and decreased for distributions received from, the investee. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, we capitalize interest costs associated with the investment during such period.
RESTRICTED LONG-TERM INVESTMENTS	RESTRICTED LONG-TERM INVESTMENTS Long-term investments that are restricted as to withdrawal or usage, for the purposes of the CER’s LMCI, are presented as Restricted long-term investments in the Consolidated Statements of Financial Position.
OTHER INVESTMENTS	OTHER INVESTMENTS Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not have readily determinable fair values as other investments measured using the fair value measurement alternative (FVMA). These investments are recorded at cost minus impairment, if any, plus or minus the impact of observable price changes occurring in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the FVMA are reviewed for impairment each reporting period and written down to their fair value if objective evidence of impairment is identified. Equity investments with readily determinable fair values are measured at fair value through earnings. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established. Investments in debt securities are classified as available-for-sale and measured at fair value through OCI.
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position.
INCOME TAXES	INCOME TAXES Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent that taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income tax expense.
FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION	FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated to the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting from the translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise. Gains and losses arising from the translation of foreign operations' functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect as at the balance sheet date, while revenues and expenses are translated using monthly average exchange rates.
CASH AND CASH EQUIVALENTS	CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased.
RESTRICTED CASH	RESTRICTED CASH Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as Restricted cash in the Consolidated Statements of Financial Position.
LOANS AND RECEIVABLES	LOANS AND RECEIVABLES Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. Interest income is recognized in earnings as it is earned with the passage of time.
CURRENT EXPECTED CREDIT LOSSES	CURRENT EXPECTED CREDIT LOSSES For accounts receivable, a loss allowance matrix is utilized to measure lifetime expected credit losses. The matrix contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations. Other loan receivables and applicable off-balance sheet commitments utilize a discounted cash flow methodology which calculates the current expected credit losses based on historical default probability rates associated with the credit rating of the counterparty and the related term of the loan or commitment, adjusted for forward-looking information and management expectations.
INVENTORY	INVENTORY Inventory is comprised of natural gas held in storage by Enbridge Gas, crude oil and natural gas held primarily by businesses in the Energy Services segment and materials and supplies. Natural gas held in storage by Enbridge Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of gas purchased is deferred as a liability for future refund, or as an asset for collection as approved by the OEB. Other inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs in the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. Materials and supplies inventory is recorded at the lower of average cost or net realizable value.
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in-service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation.
LEASES	LEASES We recognize an arrangement as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We recognize right-of-use (ROU) assets and the related lease liabilities in the Consolidated Statements of Financial Position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach applied for other long-lived assets. Lease liabilities and ROU assets require the use of judgment and estimates which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing.
DEFERRED AMOUNTS AND OTHER ASSETS	DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily consists of costs that regulatory authorities have permitted, or are expected to permit, to be recovered through future rates, including: deferred income taxes; the fair value adjustment to long-term debt; actual cost of removal of previously retired or decommissioned plant assets; and actuarial gains and losses arising from defined benefit pension plans.
INTANGIBLE ASSETS	INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects . Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due.
GOODWILL	GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1. We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, the assessment of macroeconomic trends, regulatory environments, capital accessibility, operating income trends and industry conditions. Based on our assessment of qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is performed. The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using a combination of discounted cash flow and earnings multiples techniques. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. Cash flow projections include significant judgments and assumptions relating to discount rates and expected future capital expenditures. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units. The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of businesses included in the relevant reporting unit. On April 1, 2021, we performed a quantitative goodwill impairment assessment for the Gas Transmission and Midstream reporting unit and qualitative assessments for the Liquids Pipelines and Gas Distribution and Storage reporting units. Our goodwill impairment assessments did not result in an impairment charge. Also, we did not identify any indicators of goodwill impairment during the remainder of 2021.
IMPAIRMENT	IMPAIRMENT We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, we will calculate fair value based on the discounted cash flows and write the asset down to the extent that the carrying value exceeds the fair value. With respect to investments in debt securities and equity investments, we assess at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we value the expected discounted cash flows using observable market inputs. We determine whether the decline below carrying value is other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities. If the decline is determined to be other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset.
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. Fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements.
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS We sponsor defined benefit and defined contribution pension plans, and defined benefit OPEB plans, which provide group health care, life insurance benefits and other postretirement benefits. Defined benefit pension obligation and net periodic benefit cost are estimated using the projected unit credit method, which incorporates management’s best estimates of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors, including discount rates and mortality. The OPEB benefit obligation and net periodic benefit cost are estimated using the projected unit credit method, where benefits are attributed to years of service, taking into consideration projection of benefit costs. We use mortality tables issued by the Society of Actuaries in the US (revised in 2021) and the Canadian Institute of Actuaries (revised in 2014) to measure the benefit obligations of our US pension plans (the US Plans) and our Canadian pension plans (the Canadian Plans), respectively. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments we anticipate making under each of the respective plans. Funded pension and OPEB plan assets are measured at fair value. The expected return on funded pension and OPEB plan assets is determined using market-related values and assumptions on the invested asset mix consistent with the investment policies relating to the plan assets. The market-related values reflect estimated return on investments consistent with long-term historical averages for similar assets. Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets for that period (for funded pension and OPEB plans) or from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate, changes in headcount and salary inflation experience. The excess of the fair value of a plan’s assets over the fair value of a plan’s benefit obligation is recognized as Deferred amounts and other assets in the Consolidated Statements of Financial Position. The excess of the fair value of a plan’s benefit obligation over the fair value of a plan’s assets is recognized as Accounts payable and other and Other long-term liabilities in the Consolidated Statements of Financial Position. Net periodic benefit cost is charged to earnings and includes: • cost of benefits provided in exchange for employee services rendered during the year (current service cost); • interest cost of plan obligations; • expected return on plan assets (for funded pension and OPEB plans); • amortization of prior service costs on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans; and • amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans. Cumulative unrecognized net actuarial gains and losses and prior service costs arising from defined benefit pension plans for our non-utility operations and from defined benefit OPEB plans are presented as a component of AOCI in the Consolidated Statements of Changes in Equity. Any unrecognized actuarial gains and losses and prior service costs and credits related to those plans that arise during the period are recognized as a component of OCI, net of tax. Cumulative unrecognized net actuarial gains and losses and prior service costs arising from defined benefit pension plans for our utility operations, which have been permitted or are expected to be permitted by the regulators, to be recovered through future rates, are presented as a component of Deferred amounts and other assets in the Consolidated Statements of Financial Position. Our utility operations also record regulatory adjustments to reflect the difference between certain net periodic benefit costs for accounting purposes and net periodic benefit costs for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent net periodic benefit costs are expected to be collected from or refunded to customers, respectively, in future rates. In the absence of rate regulation, regulatory assets or liabilities would not be recorded and net periodic benefit costs would be charged to earnings and OCI on an accrual basis. For defined contribution plans, contributions made by us are expensed in the period in which the contribution occurs.
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION Incentive Stock Options (ISO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISO granted as calculated by the Black-Scholes-Merton model and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility, with a corresponding credit to Additional paid-in capital. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised.
COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES	COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in Accounts payable and other and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in the Consolidated Statements of Financial Position. Liabilities for other commitments and contingencies are recognized when, after fully analyzing available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred, and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we recognize the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. We expense legal costs associated with loss contingencies as such costs are incurred.
CHANGES IN ACCOUNTING POLICIES	CHANGES IN ACCOUNTING POLICIES There were no changes in accounting policies during the year ended December 31, 2021. ADOPTION OF NEW ACCOUNTING STANDARDS Accounting for Contract Assets and Liabilities from Contracts with Customers in a Business Combination Effective November 1, 2021, we adopted Accounting Standards Update (ASU) 2021-08 on a retrospective basis beginning January 1, 2021. The new standard was issued in October 2021 to amend business combination accounting specific to contract assets and contract liabilities resulting from contracts with customers, requiring measurement in accordance with Accounting Standards Codification (ASC) 606. The ASU is also applicable to contract assets and contract liabilities from other contracts to which ASC 606 applies, such as contract liabilities from the sale of nonfinancial assets within the scope of ASC 610-20. The adoption of this ASU did not have a material impact on our consolidated financial statements. Reference Rate Reform For eligible hedging relationships existing as at January 1, 2021 and prospectively, we have applied the optional expedient in 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 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. FUTURE ACCOUNTING POLICY CHANGES Disclosures About Government Assistance ASU 2021-10 was issued in November 2021 to increase the transparency of government assistance to business entities. The ASU adds new disclosure requirements for transactions with government that are accounted for using a grant or contribution accounting model by analogy. The required disclosures include information about the nature of transactions, accounting policy applied, impacted financial statement line items and significant terms and conditions. ASU 2021-10 is effective January 1, 2022 and can be applied either prospectively or retrospectively with early adoption permitted. The adoption of ASU 2021-10 is not expected to have a material impact on our consolidated financial statements. Accounting for Certain Lessor Leases with Variable Lease Payments ASU 2021-05 was issued in July 2021 to amend lessor accounting for certain leases with variable lease payments that do not depend on a reference index or a rate and would have resulted in the recognition of a loss at lease commencement if classified as a sales-type or a direct financing lease. The ASU amends the classification requirements of such leases for lessors to result in an operating lease classification. ASU 2021-05 is effective January 1, 2022 and can be applied either retrospectively or prospectively with early adoption permitted. The adoption of ASU 2021-05 is not expected to have a material impact on our consolidated financial statements. Accounting for Modifications or Exchanges of Certain Equity-Classified Contracts ASU 2021-04 was issued in May 2021 to clarify issuer accounting for modifications or exchanges of freestanding equity-classified written call options that remain equity classified after modification or exchange. The ASU requires an issuer to determine the accounting for the modification or exchange based on the economic substance of the modification or exchange. ASU 2021-04 is effective January 1, 2022 and should be applied prospectively. The adoption of ASU 2021-04 is not expected to have a material impact on our consolidated financial statements. 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. The adoption of ASU 2020-06 is not expected to have a material impact on our consolidated financial statements.

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	Major Products and Services Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2021 (millions of Canadian dollars) Transportation revenue 9,492 4,364 676 — — — 14,532 Storage and other revenue 147 255 246 — — — 648 Gas gathering and processing revenue — 49 — — — — 49 Gas distribution revenue — — 4,026 — — — 4,026 Electricity and transmission revenue — — — 177 — — 177 Total revenue from contracts with customers 9,639 4,668 4,948 177 — — 19,432 Commodity sales — — — — 26,873 — 26,873 Other revenue 1,2 375 42 13 336 — — 766 Intersegment revenue 567 1 19 (1) 44 (630) — Total revenue 10,581 4,711 4,980 512 26,917 (630) 47,071 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2020 (millions of Canadian dollars) Transportation revenue 9,161 4,523 674 — — — 14,358 Storage and other revenue 94 274 203 — — — 571 Gas gathering and processing revenue — 27 — — — — 27 Gas distribution revenue — — 3,663 — — — 3,663 Electricity and transmission revenue — — — 198 — — 198 Total revenue from contracts with customers 9,255 4,824 4,540 198 — — 18,817 Commodity sales — — — — 19,259 — 19,259 Other revenue 1,2 584 44 17 389 — (23) 1,011 Intersegment revenue 584 2 12 — 24 (622) — Total revenue 10,423 4,870 4,569 587 19,283 (645) 39,087 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated Year ended December 31, 2019 (millions of Canadian dollars) Transportation revenue 9,082 4,477 743 — — — 14,302 Storage and other revenue 109 268 201 — — — 578 Gas gathering and processing revenue — 423 — — — — 423 Gas distribution revenue — — 4,210 — — — 4,210 Electricity and transmission revenue — — — 180 — — 180 Commodity sales — 4 — — — — 4 Total revenue from contracts with customers 9,191 5,172 5,154 180 — — 19,697 Commodity sales — — — — 29,305 — 29,305 Other revenue 1,2 659 30 9 387 (2) (16) 1,067 Intersegment revenue 369 5 16 — 71 (461) — Total revenue 10,219 5,207 5,179 567 29,374 (477) 50,069 1 Includes mark-to-market gains from our hedging program for the year ended December 31, 2021 of $59 million, (2020 - $265 million, 2019 - $346 million). 2 Includes revenues from lease contracts. Refer to Note 27 - Leases .
Contract with Customer, Asset and Liability	Contract Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at December 31, 2021 2,369 213 1,898 Balance as at December 31, 2020 2,042 226 1,815
Performance Obligations	Performance Obligations Segment Nature of Performance Obligation Liquids Pipelines • Transportation and storage of crude oil and natural gas liquids (NGLs) Gas Transmission and Midstream • Transportation, storage, gathering, compression and treating of natural gas • Transportation of NGLs • Sale of crude oil, natural gas and NGLs Gas Distribution and Storage • Supply and delivery of natural gas • Transportation of natural gas • Storage of natural gas Renewable Power Generation • Generation and transmission of electricity • Delivery of electricity from renewable energy generation facilities
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2021 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 70 — 70 Revenue from products and services transferred over time 1 9,639 4,668 4,878 177 19,362 Total revenue from contracts with customers 9,639 4,668 4,948 177 19,432 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2020 (millions of Canadian dollars) Revenue from products transferred at a point in time — — 60 — 60 Revenue from products and services transferred over time 1 9,255 4,824 4,480 198 18,757 Total revenue from contracts with customers 9,255 4,824 4,540 198 18,817 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Consolidated Year ended December 31, 2019 (millions of Canadian dollars) Revenue from products transferred at a point in time — 4 65 — 69 Revenue from products and services transferred over time 1 9,191 5,168 5,089 180 19,628 Total revenue from contracts with customers 9,191 5,172 5,154 180 19,697 1 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
Schedule of reporting information by segment	Segmented information for the years ended December 31, 2021, 2020 and 2019 is as follows: Year ended December 31, 2021 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 10,581 4,711 4,980 512 26,917 (630) 47,071 Commodity and gas distribution costs (25) — (2,147) — (27,174) 644 (28,702) Operating and administrative (3,431) (1,877) (1,143) (180) (48) (33) (6,712) Income/(loss) from equity investments 759 813 42 101 — (4) 1,711 Impairment of equity investments — (111) — — — — (111) Other income/(expense) 13 135 385 75 (8) 379 979 Earnings/(loss) before interest, income tax expense and depreciation and amortization 7,897 3,671 2,117 508 (313) 356 14,236 Depreciation and amortization (3,852) Interest expense (2,655) Income tax expense (1,415) Earnings 6,314 Capital expenditures 1 4,051 2,420 1,343 16 1 54 7,885 Total property, plant and equipment, net 52,530 27,028 16,904 3,315 23 267 100,067 Year ended December 31, 2020 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 10,423 4,870 4,569 587 19,283 (645) 39,087 Commodity and gas distribution costs (20) — (1,810) (2) (19,450) 613 (20,669) Operating and administrative (3,331) (1,859) (1,091) (191) (67) (210) (6,749) Income/(loss) from equity investments 558 479 9 94 (3) (1) 1,136 Impairment of equity investments — (2,351) — — — — (2,351) Other income/(expense) 53 (52) 71 35 1 130 238 Earnings/(loss) before interest, income tax expense and depreciation and amortization 7,683 1,087 1,748 523 (236) (113) 10,692 Depreciation and amortization (3,712) Interest expense (2,790) Income tax expense (774) Earnings 3,416 Capital expenditures 1 2,033 2,130 1,134 81 2 90 5,470 Total property, plant and equipment, net 48,799 25,745 16,079 3,495 24 429 94,571 Year ended December 31, 2019 Liquids Pipelines Gas Transmission and Midstream Gas Distribution and Storage Renewable Power Generation Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 10,219 5,207 5,179 567 29,374 (477) 50,069 Commodity and gas distribution costs (29) — (2,354) (2) (29,091) 472 (31,004) Operating and administrative (3,298) (2,232) (1,149) (189) (44) (79) (6,991) Impairment of long-lived assets (21) (105) — (297) — — (423) Income/(loss) from equity investments 780 682 4 31 8 (2) 1,503 Other income/(expense) 30 (181) 67 1 3 515 435 Earnings before interest, income tax expense and depreciation and amortization 7,681 3,371 1,747 111 250 429 13,589 Depreciation and amortization (3,391) Interest expense (2,663) Income tax expense (1,708) Earnings 5,827 Capital expenditures 1 2,548 1,753 1,100 23 2 124 5,550 Total property, plant and equipment, net 48,783 25,268 15,622 3,658 24 368 93,723 1 Includes allowance for equity funds used during construction.
Schedule of revenues by geographical segments	Revenues 1 Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Canada 20,474 16,453 19,954 US 26,597 22,634 30,115 47,071 39,087 50,069 1 Revenues are based on the country of origin of the product or service sold.
Schedule of property, plant and equipment by geographical segments	Property, Plant and Equipment 1 December 31, 2021 2020 (millions of Canadian dollars) Canada 47,102 46,499 US 52,965 48,072 100,067 94,571 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Schedule of Weighted Average Shares Outstanding Used to Calculate Basic and Diluted Earnings Per Share	Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows: December 31, 2021 2020 2019 (number of shares in millions) Weighted average shares outstanding 2,023 2,020 2,017 Effect of dilutive options 2 1 3 Diluted weighted average shares outstanding 2,025 2,021 2,020

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Schedule of Regulatory Assets	December 31, 2021 2020 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Under-recovery of fuel costs 114 86 2022 Other current regulatory assets 145 146 2022 Total current regulatory assets 1 (Note 9) 259 232 Long-term regulatory assets Deferred income taxes 2 4,176 3,890 Various Long-term debt 3 398 429 2023-2046 Negative salvage 4 243 246 Various Purchase gas variance 215 — 2023 Accounting policy changes 5 157 169 Various Pension plan receivable 6 78 402 Various Other long-term regulatory assets 339 261 Various Total long-term regulatory assets 1 5,606 5,397 Total regulatory assets 5,865 5,629 Current regulatory liabilities Purchase gas variance — 153 2021 Other current regulatory liabilities 106 117 2022 Total current regulatory liabilities 7 106 270 Long-term regulatory liabilities Future removal and site restoration reserves 8 1,543 1,455 Various Regulatory liability related to US income taxes 9 895 941 2050-2072 Pipeline future abandonment costs (Note 14) 649 578 Various Other long-term regulatory liabilities 234 150 Various Total long-term regulatory liabilities 7 3,321 3,124 Total regulatory liabilities 3,427 3,394 1 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in Deferred amounts and other assets. 2 Represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in future regulator-approved rates and recovered from customers. The recovery period depends on the timing of the reversal of temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded. 3 Represents our regulatory offset to the fair value adjustment to debt acquired in our merger with Spectra Energy Corp. (Spectra Energy). The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value. 4 The negative salvage balance represents the recovery in future rates of the actual cost of removal of previously retired or decommissioned plant assets, as approved by the FERC. 5 This deferral reflects unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited, relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and recovered in rates, as previously approved by the OEB. 6 Represents the regulatory offset to our pension liability to the extent that it is expected to be included in regulator-approved future rates and recovered from customers. The settlement period for this balance is not determinable. In the absence of rate-regulated accounting, this regulatory balance and the related pension expense would be recorded in earnings and OCI. 7 Current regulatory liabilities are included in Accounts payable and other, while long-term regulatory liabilities are included in Other long-term liabilities. 8 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the OEB, to fund future costs of removal and site restoration relating to property, plant and equipment. These costs are collected as part of the depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance will occur over the long-term as costs are incurred. In the absence of rate-regulated accounting, depreciation rates would not include a charge for removal and site restoration and costs would be charged to earnings as incurred with recognition of revenue for amounts previously collected.
Schedule of Regulatory Liabilities	December 31, 2021 2020 Recovery/Refund (millions of Canadian dollars) Current regulatory assets Under-recovery of fuel costs 114 86 2022 Other current regulatory assets 145 146 2022 Total current regulatory assets 1 (Note 9) 259 232 Long-term regulatory assets Deferred income taxes 2 4,176 3,890 Various Long-term debt 3 398 429 2023-2046 Negative salvage 4 243 246 Various Purchase gas variance 215 — 2023 Accounting policy changes 5 157 169 Various Pension plan receivable 6 78 402 Various Other long-term regulatory assets 339 261 Various Total long-term regulatory assets 1 5,606 5,397 Total regulatory assets 5,865 5,629 Current regulatory liabilities Purchase gas variance — 153 2021 Other current regulatory liabilities 106 117 2022 Total current regulatory liabilities 7 106 270 Long-term regulatory liabilities Future removal and site restoration reserves 8 1,543 1,455 Various Regulatory liability related to US income taxes 9 895 941 2050-2072 Pipeline future abandonment costs (Note 14) 649 578 Various Other long-term regulatory liabilities 234 150 Various Total long-term regulatory liabilities 7 3,321 3,124 Total regulatory liabilities 3,427 3,394 1 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in Deferred amounts and other assets. 2 Represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in future regulator-approved rates and recovered from customers. The recovery period depends on the timing of the reversal of temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded. 3 Represents our regulatory offset to the fair value adjustment to debt acquired in our merger with Spectra Energy Corp. (Spectra Energy). The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value. 4 The negative salvage balance represents the recovery in future rates of the actual cost of removal of previously retired or decommissioned plant assets, as approved by the FERC. 5 This deferral reflects unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited, relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and recovered in rates, as previously approved by the OEB. 6 Represents the regulatory offset to our pension liability to the extent that it is expected to be included in regulator-approved future rates and recovered from customers. The settlement period for this balance is not determinable. In the absence of rate-regulated accounting, this regulatory balance and the related pension expense would be recorded in earnings and OCI. 7 Current regulatory liabilities are included in Accounts payable and other, while long-term regulatory liabilities are included in Other long-term liabilities. 8 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the OEB, to fund future costs of removal and site restoration relating to property, plant and equipment. These costs are collected as part of the depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance will occur over the long-term as costs are incurred. In the absence of rate-regulated accounting, depreciation rates would not include a charge for removal and site restoration and costs would be charged to earnings as incurred with recognition of revenue for amounts previously collected.

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Tables)	12 Months Ended
	Dec. 31, 2021
Business Combinations [Abstract]
Summary of Estimated Fair Values Assigned to Net Assets and Final Purchase Price Allocation	The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Moda: October 12, 2021 (millions of Canadian dollars) Fair value of net assets acquired: Current assets 62 Property, plant and equipment (a) 1,480 Long-term investments (b) 427 Intangible assets (c) 1,781 Current liabilities 59 Long-term liabilities 17 Goodwill (d) 268 Purchase price: Cash 3,755 Contingent consideration (e) 187 3,942 a) Due to the specialized nature of Moda's property, plant and equipment, which includes groups of assets configured for use as storage facilities, pipelines and export terminals, the depreciated replacement cost approach was adopted as the primary valuation methodology. In determining replacement cost, both indirect costing using relevant inflation indices and direct costing using relevant market quotes were utilized. Adjustments were then applied for physical deterioration as well as functional and economic obsolescence. The fair value of land was determined using a market approach, which is based on rents and offerings for comparable properties. b) Long-term investments represent Moda's 20% equity interest in Cactus II Pipeline, LLC (Cactus II). The fair value of Cactus II was determined using the discounted cash flow method. The discounted cash flow method is an income-based approach to valuation which estimates the present value of future projected benefits from the investment. c) Intangible assets consist primarily of customer relationships associated with long-term take-or-pay contracts. Fair value was determined using an income-based approach by estimating the present value of the after-tax earnings attributable to the contracts, including earnings associated with expected renewal terms, and will be amortized on a straight-line basis over an expected useful life of 10 years. d) Goodwill is primarily attributable to uncontracted future revenues, existing assembled assets that cannot be duplicated at the same cost by a new entrant, and enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. The goodwill balance recognized has been assigned to our Liquids Pipelines segment and is tax deductible over 15 years. e) We agreed to pay additional contingent consideration of up to US$150 million to Moda's former membership interest holders if Moda's monthly volumes of crude oil loaded onto a vessel equal or exceed specified throughput levels. These performance requirements terminate the earlier of December 31, 2023 or the date the final contingent payment is made. The US$150 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition. As at December 31, 2021, there were no changes to the amount of contingent consideration recognized.
Schedule of Supplemental Pro Forma Consolidated Financial Information	Our supplemental pro forma consolidated financial information for the years ended December 31, 2021 and 2020, including the results of operations for Moda as if the Acquisition had been completed on January 1, 2020, are as follows: Year ended December 31, 2021 2020 (unaudited; millions of Canadian dollars) Operating revenues 47,339 39,435 Earnings attributable to common shareholders 1,2 5,771 2,938 1 Acquisition-related expenses of $21 million (after-tax $16 million) were excluded from earnings attributable to common shareholders for the year ended December 31 2021 and deducted for the year ended December 31, 2020. 2 Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets of $193 million and $207 million (after-tax of $145 million and $155 million) for the years ended December 31, 2021 and 2020, respectively.

ACCOUNTS RECEIVABLE AND OTHER (

ACCOUNTS RECEIVABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2021
Receivables [Abstract]
Schedule of accounts receivable and other	December 31, 2021 2020 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 4,957 3,923 Short-term portion of derivative assets (Note 24) 529 323 Regulatory assets (Note 7) 259 232 Taxes receivable 407 374 Other 710 406 6,862 5,258 1 Net of allowance for expected credit losses of $87 million as at December 31, 2021 and $70 million as at December 31, 2020.

INVENTORY (Tables)

INVENTORY (Tables)	12 Months Ended
	Dec. 31, 2021
Inventory Disclosure [Abstract]
Schedule of inventory	December 31, 2021 2020 (millions of Canadian dollars) Natural gas 953 710 Crude oil 624 744 Other 93 82 1,670 1,536

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Weighted Average December 31, Depreciation Rate 2021 2020 (millions of Canadian dollars) Pipelines 2.8 % 62,997 57,459 Facilities and equipment 3.1 % 34,331 30,149 Land and right-of-way 1 2.3 % 3,320 2,896 Gas mains, services and other 2.7 % 13,606 12,813 Storage 2.4 % 3,099 2,936 Wind turbines, solar panels and other 4.0 % 4,912 4,877 Other 8.2 % 1,507 1,558 Under construction — % 2,268 5,762 Total property, plant and equipment 126,040 118,450 Total accumulated depreciation (25,973) (23,879) Property, plant and equipment, net 100,067 94,571 1 The measurement of weighted average depreciation rate excludes non-depreciable assets.

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Assets and Liabilities of Consolidated VIEs	The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position. December 31, 2021 1 2020 1 (millions of Canadian dollars) Assets Cash and cash equivalents 247 215 Restricted cash 4 1 Accounts receivable and other 99 65 Inventory 9 7 359 288 Property, plant and equipment, net 3,052 3,201 Long-term investments 16 14 Restricted long-term investments 101 84 Deferred amounts and other assets 2 3 Intangible assets, net 108 115 3,638 3,705 Liabilities Accounts payable and other 84 52 Other long-term liabilities 182 175 Deferred income taxes 5 5 271 232 3,367 3,473 1 Excludes assets and liabilities of EEP and Spectra Energy Partners, L.P. (SEP) following the subsidiary guarantees agreement entered on January 22, 2019. See Part II . Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Summarized Financial Information.
Schedule of the Carrying Amount of Interest in VIEs	The carrying amount of these VIEs and our estimated maximum exposure to loss as at December 31, 2021 and 2020 are presented below: Carrying Maximum December 31, 2021 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 113 195 EIH S.á r.l. 2, 8 38 664 Enbridge Renewable Infrastructure Investments S.á r.l. 3 54 2,121 Rampion Offshore Wind Limited 5 450 508 Vector Pipeline L.P. 6 189 374 Other 4,7 210 426 1,054 4,288 Carrying Maximum December 31, 2020 the VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 106 187 Éolien Maritime France SAS 2, 8 96 949 Enbridge Renewable Infrastructure Investments S.á r.l. 3 100 2,516 PennEast Pipeline Company, LLC 4 116 371 Rampion Offshore Wind Limited 5 599 650 Vector Pipeline L.P. 6 201 390 Other 7 133 361 1,351 5,424 1 At December 31, 2021 and 2020, the maximum exposure to loss includes guarantees by us for our respective share of the VIE’s borrowing on a bank credit facility. 2 At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the three French offshore wind projects for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $73 million held by us as at December 31, 2021. On March 18, 2021, Enbridge Renewable Infrastructure Holdings S. á r.l. (ERIH) closed the sale of 49% of its interest in EIH S. á r.l. to the Canada Pension Plan Investment Board (CPP Investments). 3 At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $807 million and $904 million held by us as at December 31, 2021 and 2020, respectively. 4 At December 31, 2021, the maximum exposure to loss is limited to our equity investment and at December 31, 2020, the maximum exposure to loss includes the remaining expected contributions to the joint venture. 5 At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in project contracts in which we would be liable for in the event of default by the VIE. 6 At December 31, 2021 and 2020, the maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable for $80 million and $84 million held by us as at December 31, 2021 and 2020, respectively, and an outstanding credit facility for $105 million as at December 31, 2021 and 2020. 7 At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE. 8 At December 31, 2020, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $132 million held by us as at December 31, 2020. In relation to the sale of 49% of EIH S. á r.l.'s interest to CPP Investments, Eolien Maritime France SAS is now reported under EIH S. á r.l. in 2021.

LONG-TERM INVESTMENTS (Tables)

LONG-TERM INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Long-Term Investments	Ownership December 31, Interest 2021 2020 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines MarEn Bakken Company LLC 1 75.0 % 1,728 1,795 Gray Oak Holdings LLC 2 35.0 % 469 502 Seaway Crude Holdings LLC 50.0 % 2,634 2,668 Illinois Extension Pipeline Company, L.L.C. 3 65.0 % 593 623 Cactus II Pipeline, LLC 4 20.0 % 434 — Other 30.0% - 43.8% 71 73 Gas Transmission and Midstream Alliance Pipeline 5 50.0 % 504 269 Aux Sable 6 42.7% - 50.0% 238 251 DCP Midstream, LLC 7 50.0 % 397 331 Gulfstream Natural Gas System, L.L.C. 50.0 % 1,180 1,175 Nexus Gas Transmission, LLC 50.0 % 1,724 1,745 PennEast Pipeline Company, LLC 20.0 % 12 116 Sabal Trail Transmission, LLC 50.0 % 1,464 1,510 Southeast Supply Header, LLC 50.0 % 82 84 Steckman Ridge, LP 50.0 % 88 90 Vector Pipeline 8 60.0 % 189 201 Offshore - various joint ventures 22.0% - 74.3% 309 338 Other 33.3% 2 4 Gas Distribution and Storage Noverco Common Shares 9 38.9 % — 156 Other 47.6% - 50% 20 13 Renewable Power Generation EIH S.a.r.l. 10 51.0 % 38 96 Enbridge Renewable Infrastructure Investments S.a.r.l. 51.0 % 54 100 Rampion Offshore Wind Limited 24.9 % 450 599 NextBridge Infrastructure LP 25.0 % 186 122 Other 12.0% - 50.0% 93 74 Eliminations and Other Other 42.7% - 50.0% 23 32 OTHER LONG-TERM INVESTMENTS Gas Distribution and Storage Noverco Preferred Shares 9 — 567 Renewable Power Generation Emerging Technologies and Other 32 32 Eliminations and Other Other 11 310 252 13,324 13,818 1 Owns 49% interest in Bakken Pipeline Investments L.L.C., which owns 75% of the Bakken Pipeline System resulting in a 27.6% effective interest in the Bakken Pipeline System. 2 Owns 65% interest in Gray Oak Pipeline, LLC resulting in a 22.8% effective interest in Gray Oak Pipeline, LLC. 3 Owns the Southern Access Extension Project. 4 In October 2021 we acquired an effective 20.0% interest in Cactus II Pipeline, LLC through the acquisition of Moda Midstream Operating, LLC. See Note 8 - Acquisitions and Dispositions for further discussion. 5 Includes Alliance Pipeline Limited Partnership in Canada and Alliance Pipeline L.P. in the US. 6 Includes Aux Sable Canada LP in Canada and Aux Sable Liquid Products LP and Aux Sable Midstream LLC in the US. 7 Our ownership in DCP Midstream, LLC (DCP Midstream) holds an interest of 56.5% in DCP Midstream, LP. 8 Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US. 9 On December 30, 2021, we sold our 38.9% common share and preferred share interest of Noverco Inc. 10 On March 18, 2021, we sold 49% of EIH S.a.r.l., an entity that holds our 50% interest in Éolien Maritime France SAS (EMF), to the CPP Investments. This resulted in a 25.5% effective interest in EMF. 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%). 11 Includes investments held and valued at fair value through net income.
Summary of Combined Financial Information	Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows: Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Operating revenues 19,891 13,987 15,687 Operating expenses 16,514 12,223 13,153 Earnings 2,952 2,306 3,016 Earnings attributable to Enbridge 1,711 1,136 1,503 December 31, 2021 2020 (millions of Canadian dollars) Current assets 3,581 3,136 Non-current assets 44,497 45,955 Current liabilities 3,678 3,539 Non-current liabilities 16,950 19,639 Noncontrolling interests 3,786 3,810

INTANGIBLE ASSETS (Tables)

INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of intangible assets	Weighted Average Accumulated December 31, 2021 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Software 12.0 % 2,067 (1,148) 919 Power purchase agreements 4.5 % 63 (21) 42 Project agreement 1 4.0 % 152 (27) 125 Customer relationships 8.5 % 2,532 (215) 2,317 Other intangible assets 3.9 % 475 (116) 359 Under development — % 246 — 246 5,535 (1,527) 4,008 Weighted Average Accumulated December 31, 2020 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Software 10.5 % 2,043 (1,299) 744 Power purchase agreements 4.5 % 63 (18) 45 Project agreement 1 4.0 % 153 (21) 132 Customer relationships 5.0 % 724 (139) 585 Other intangible assets 2.7 % 456 (96) 360 Under development — % 214 — 214 3,653 (1,573) 2,080

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of goodwill	Liquids Gas Gas Energy Consolidated (millions of Canadian dollars) Balance at January 1, 2020 7,951 19,844 5,356 2 33,153 Foreign exchange and other (123) (364) — — (487) Acquisition — — 22 — 22 Balance at December 31, 2020 1,2 7,828 19,480 5,378 2 32,688 Foreign exchange and other (55) (145) — — (200) Acquisition 3 268 — 19 — 287 Balance at December 31, 2021 1,2 8,041 19,335 5,397 2 32,775 1 Gross cost of goodwill as at December 31, 2021 and 2020 was $34.4 billion and $34.3 billion, respectively. 2 Accumulated impairment as at December 31, 2021 and 2020 was $1.6 billion. 3 In 2021, we recorded $268 million of goodwill related to the acquisition of Moda. See Note 8 - Acquisitions and Dispositions for further discussion.

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2021
Payables and Accruals [Abstract]
Schedule of accounts payable and other	December 31, 2021 2020 (millions of Canadian dollars) Trade payables and operating accrued liabilities 4,470 3,497 Dividends payable 1,773 1,728 Current deferred credits 853 978 Construction payables and contractor holdbacks 844 855 Current derivative liabilities (Note 24) 717 896 Taxes payable 478 622 Other 632 652 9,767 9,228

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Schedule of Debt	December 31, Weighted Average Interest Rate 9 Maturity 2021 2020 (millions of Canadian dollars) Enbridge Inc. US dollar senior notes 3.2 % 2022 - 2051 10,992 8,536 Medium-term notes 3.9 % 2022 - 2064 8,123 8,323 Sustainability-linked bonds 1.1 % 2033 2,363 — Fixed-to-fixed subordinated term notes 1 5.8 % 2080 1,263 1,274 Fixed-to-floating rate subordinated term notes 2 5.8 % 2023 - 2028 6,442 6,477 Floating rate notes 3 2022 - 2023 1,579 956 Commercial paper and credit facility draws 1.0 % 2022 - 2026 7,837 8,719 Other 4 5 5 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 0.4 % 2023 - 2026 4,845 492 Other 4 7 7 Enbridge Energy Partners, L.P. Senior notes 6.5 % 2025 - 2045 3,095 3,886 Enbridge Gas Inc. Medium-term notes 3.8 % 2022 - 2051 9,010 8,485 Debentures 9.1 % 2024 - 2025 210 210 Commercial paper and credit facility draws 0.5 % 2023 1,515 1,121 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 4.0 % 2040 949 1,038 Enbridge Pipelines Inc. Medium-term notes 5 4.0 % 2022 - 2051 5,575 4,775 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 0.7 % 2023 667 1,278 Enbridge Southern Lights LP Senior notes 4.0 % 2040 240 257 Spectra Energy Capital, LLC Senior notes 7.0 % 2032 - 2038 218 220 Spectra Energy Partners, LP Senior notes 3.9 % 2022 - 2048 8,451 8,332 Westcoast Energy Inc. Medium-term notes 4.5 % 2022 - 2041 1,475 1,625 Debentures 8.1 % 2025 - 2026 275 275 Fair value adjustment 667 750 Other 6 (363) (344) Total debt 7 75,640 66,897 Current maturities (6,164) (2,957) Short-term borrowings 8 (1,515) (1,121) Long-term debt 67,961 62,819 1 For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be set to equal to the Five-Year US Treasury Rate plus a margin of 5.31% from years 10 to 30 and a margin of 6.06% from years 30 to 60. 2 For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal to the Canadian Dollar Offered Rate (CDOR) or the London Interbank Offered Rate (LIBOR) plus a margin. The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 3 The notes carry an interest rate equal to the three-month LIBOR plus a margin of 50 basis points and Secured Overnight Financing Rate (SOFR) plus a margin of 40 basis points. 4 Primarily finance lease obligations. 5 Included in medium-term notes is $100 million with a maturity date of 2112. 6 Primarily unamortized discounts, premiums and debt issuance costs. 7 2021 - $36 billion and US$31 billion; 2020 - $35 billion and US$24 billion. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment. 8 Weighted average interest rates on outstanding commercial paper were 0.5% as at December 31, 2021 (2020 - 0.3%). 9 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2021.
Schedule of Committed Credit Facilities	The following table provides details of our committed credit facilities as at December 31, 2021: Maturity 1 Total Facilities Draws 2 Available (millions of Canadian dollars) Enbridge Inc. 2022-2026 9,137 7,837 1,300 Enbridge (U.S.) Inc. 2023-2026 6,948 4,845 2,103 Enbridge Pipelines Inc. 2023 3,000 667 2,333 Enbridge Gas Inc. 2023 2,000 1,515 485 Total committed credit facilities 21,085 14,864 6,221 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.
Schedule of Long-term Debt Issuances	LONG-TERM DEBT ISSUANCES During the year ended December 31, 2021, we completed the following long-term debt issuances totaling US$3.9 billion and $3.2 billion: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. February 2021 Floating rate senior-notes due February 2023 1 US$500 June 2021 2.50% Sustainability-linked senior notes due August 2033 US$1,000 June 2021 3.40% senior notes due August 2051 US$500 September 2021 3.10% Sustainability-linked medium-term notes due September 2033 $1,100 September 2021 4.10% medium-term notes due September 2051 $400 October 2021 0.55% senior notes due October 2023 US$500 October 2021 1.60% senior notes due October 2026 US$500 October 2021 3.40% senior notes due August 2051 US$500 Enbridge Gas Inc. September 2021 2.35% medium-term notes due September 2031 $475 September 2021 3.20% medium-term notes due September 2051 $425 Enbridge Pipelines Inc. May 2021 2.82% medium-term notes due May 2031 $400 May 2021 4.20% medium-term notes due May 2051 $400 Spectra Energy Partners, LP September 2021 2.50% senior notes due September 2031 2 US$400 1 Notes carry an interest rate equal to the SOFR plus a margin of 40 basis points. 2 Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.
Schedule of Long-Term Debt Repayments	During the year ended December 31, 2021, we completed the following long-term debt repayments totaling $1.1 billion and US$914 million, respectively: 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 Enbridge Energy Partners, L.P. June 2021 4.20% senior notes US$600 Enbridge Gas Inc. May 2021 2.76% medium-term notes $200 December 2021 4.77% medium-term notes $175 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2021 3.98% senior notes US$64 Enbridge Southern Lights LP June and December 2021 4.01% senior notes $16 Spectra Energy Partners, LP March 2021 4.60% senior notes US$250 Westcoast Energy Inc. October 2021 3.88% medium-term notes $150
Schedule of Interest Expense	INTEREST EXPENSE Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Debentures and term notes 2,850 2,913 2,783 Commercial paper and credit facility draws 70 123 273 Amortization of fair value adjustment (50) (54) (67) Capitalized interest (215) (192) (326) 2,655 2,790 2,663

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Reconciliation of movements in the Company's ARO	A reconciliation of movements in our ARO liabilities is as follows: December 31, 2021 2020 (millions of Canadian dollars) Obligations at beginning of year 496 520 Liabilities disposed — — Liabilities incurred — — Liabilities settled (67) (30) Change in estimate and other 70 — Foreign currency translation adjustment (3) (6) Accretion expense 6 12 Obligations at end of year 502 496 Presented as follows: Accounts payable and other 160 56 Other long-term liabilities 342 440 502 496

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2021
Noncontrolling Interest [Abstract]
Schedule of noncontrolling interests	The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position: December 31, 2021 2020 (millions of Canadian dollars) Algonquin Gas Transmission, L.L.C 377 384 Maritimes & Northeast Pipeline, L.L.C 546 558 Renewable energy assets 1,503 1,646 Westcoast Energy Inc. 1 116 408 2,542 2,996 1 Includes nil and 12 million cumulative redeemable preferred shares as at December 31, 2021 and 2020, respectively.

SHARE CAPITAL (Tables)

SHARE CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Schedule of common shares	COMMON SHARES 2021 2020 2019 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Balance at beginning of year 2,026 64,768 2,025 64,746 2,022 64,677 Shares issued on exercise of stock options — 31 1 22 3 69 Balance at end of year 2,026 64,799 2,026 64,768 2,025 64,746
Schedule of preference shares	PREFERENCE SHARES 2021 2020 2019 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Preference Shares, Series A 5 125 5 125 5 125 Preference Shares, Series B 18 457 18 457 18 457 Preference Shares, Series C 2 43 2 43 2 43 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 20 500 20 500 20 500 Preference Shares, Series H 14 350 14 350 14 350 Preference Shares, Series J 8 199 8 199 8 199 Preference Shares, Series L 16 411 16 411 16 411 Preference Shares, Series N 18 450 18 450 18 450 Preference Shares, Series P 16 400 16 400 16 400 Preference Shares, Series R 16 400 16 400 16 400 Preference Shares, Series 1 16 411 16 411 16 411 Preference Shares, Series 3 24 600 24 600 24 600 Preference Shares, Series 5 8 206 8 206 8 206 Preference Shares, Series 7 10 250 10 250 10 250 Preference Shares, Series 9 11 275 11 275 11 275 Preference Shares, Series 11 20 500 20 500 20 500 Preference Shares, Series 13 14 350 14 350 14 350 Preference Shares, Series 15 11 275 11 275 11 275 Preference Shares, Series 17 30 750 30 750 30 750 Preference Shares, Series 19 20 500 20 500 20 500 Issuance costs (155) (155) (155) Balance at end of year 7,747 7,747 7,747
Schedule of characteristics of preference shares	Characteristics of the preference shares are as follows: Dividend Rate Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.50 % $1.37500 $25 — — Preference Shares, Series B 3.42 % $0.85360 $25 June 1, 2022 Series C Preference Shares, Series C 5 3-month treasury bill plus 2.40% — $25 June 1, 2022 Series B Preference Shares, Series D 4.46 % $1.11500 $25 March 1, 2023 Series E Preference Shares, Series F 4.69 % $1.17224 $25 June 1, 2023 Series G Preference Shares, Series H 4.38 % $1.09400 $25 September 1, 2023 Series I Preference Shares, Series J 4.89 % US$1.22160 US$25 June 1, 2022 Series K Preference Shares, Series L 4.96 % US$1.23972 US$25 September 1, 2022 Series M Preference Shares, Series N 5.09 % $1.27152 $25 December 1, 2023 Series O Preference Shares, Series P 4.38 % $1.09476 $25 March 1, 2024 Series Q Preference Shares, Series R 4.07 % $1.01825 $25 June 1, 2024 Series S Preference Shares, Series 1 5.95 % US$1.48728 US$25 June 1, 2023 Series 2 Preference Shares, Series 3 3.74 % $0.93425 $25 September 1, 2024 Series 4 Preference Shares, Series 5 5.38 % US$1.34383 US$25 March 1, 2024 Series 6 Preference Shares, Series 7 4.45 % $1.11224 $25 March 1, 2024 Series 8 Preference Shares, Series 9 4.10 % $1.02424 $25 December 1, 2024 Series 10 Preference Shares, Series 11 3.94 % $0.98452 $25 March 1, 2025 Series 12 Preference Shares, Series 13 3.04 % $0.76076 $25 June 1, 2025 Series 14 Preference Shares, Series 15 2.98 % $0.74576 $25 September 1, 2025 Series 16 Preference Shares, Series 17 5.15 % $1.28750 $25 March 1, 2022 Series 18 Preference Shares, Series 19 4.90 % $1.22500 $25 March 1, 2023 Series 20 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this feature. 2 Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. 4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in a year) x three-month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in a year) x three-month US Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6).

STOCK OPTION AND STOCK UNIT P_2

STOCK OPTION AND STOCK UNIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Schedule of outstanding stock options	December 31, 2021 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; intrinsic value in millions of Canadian dollars; weighted average exercise price in Canadian dollars) Options outstanding at beginning of year 35,494 48.65 Options granted 4,072 43.86 Options exercised 1 (4,142) 41.85 Options cancelled or expired (1,407) 50.74 Options outstanding at end of year 34,017 49.28 5.7 128 Options vested at end of year 2 22,029 49.84 4.5 64 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $24 million, $13 million and $58 million, respectively, and cash received on exercise was $2 million, $4 million and $1 million, respectively. 2 The total fair value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $25 million, $30 million and $32 million, respectively.
Schedule of weighted average assumptions used to determine the fair value of stock options granted	Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton option pricing model are as follows: Year ended December 31, 2021 2020 2019 Fair value per option (Canadian dollars) 1 4.10 4.01 4.37 Valuation assumptions Expected option term (years) 2 6 6 5 Expected volatility 3 25.5 % 18.3 % 19.9 % Expected dividend yield 4 7.6 % 5.9 % 6.1 % Risk-free interest rate 5 0.7 % 1.3 % 2.0 % 1 Options granted to US employees are based on NYSE prices. The option value and assumptions shown are based on a weighted average of the US and the Canadian options. The fair values per option for the years ended December 31, 2021, 2020 and 2019 were $3.91, $3.75 and $4.04, respectively, for Canadian employees and US$3.65, US$3.62 and US$4.09, respectively, for US employees. 2 The expected option term is six years based on historical exercise practice and five years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the US Treasury Bond Yields.
Share-based payment arrangement, performance shares, activity	December 31, 2021 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 3,056 Units granted 1,895 Units cancelled (76) Units matured 1 (1,664) Dividend reinvestment 218 Units outstanding at end of year 3,429 1.1 181 1 The total amount paid during the years ended December 31, 2021, 2020 and 2019 for PSUs was $70 million, $14 million and $19 million, respectively.
Schedule of outstanding stock units	December 31, 2021 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 2,453 Units granted 1,514 Units cancelled (75) Units matured 1 (1,433) Dividend reinvestment 246 Units outstanding at end of year 2,705 1.1 129 1 The total amount paid during the years ended December 31, 2021, 2020 and 2019 for RSUs was $72 million, $27 million and $34 million, respectively.

COMPONENTS OF ACCUMULATED OTH_2

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Tables)	12 Months Ended
	Dec. 31, 2021
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Schedule of changes in AOCI attributable to Enbridge common shareholders	Changes in AOCI attributable to our common shareholders for the years ended December 31, 2021, 2020 and 2019 are as follows: Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2021 (1,326) 5 (215) 568 66 (499) (1,401) Other comprehensive income/(loss) retained in AOCI 238 (5) 49 (492) (12) 520 298 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 296 — — — — — 296 Commodity contracts 2 1 — — — — — 1 Foreign exchange contracts 3 5 — — — — — 5 Other contracts 4 2 — — — — — 2 Equity investment disposal — — — — (66) — (66) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — — 28 28 Other 17 — — (20) 3 — — 559 (5) 49 (512) (75) 548 564 Tax impact Income tax on amounts retained in AOCI (61) — — — — (126) (187) Income tax on amounts reclassified to earnings (69) — — — 4 (7) (72) (130) — — — 4 (133) (259) Balance at December 31, 2021 (897) — (166) 56 (5) (84) (1,096) Cash Flow Hedges Excluded Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2020 (1,073) — (317) 1,396 67 (345) (272) Other comprehensive income/(loss) retained in AOCI (591) 5 115 (828) (2) (221) (1,522) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 253 — — — — — 253 Foreign exchange contracts 3 5 — — — — — 5 Other contracts 4 (2) — — — — — (2) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — — 17 17 (335) 5 115 (828) (2) (204) (1,249) Tax impact Income tax on amounts retained in AOCI 140 — (13) — 1 54 182 Income tax on amounts reclassified to earnings (58) — — — — (4) (62) 82 — (13) — 1 50 120 Balance at December 31, 2020 (1,326) 5 (215) 568 66 (499) (1,401) Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2019 (770) (598) 4,323 34 (317) 2,672 Other comprehensive income/(loss) retained in AOCI (599) 320 (2,927) 34 (124) (3,296) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 157 — — — — 157 Commodity contracts 2 (1) — — — — (1) Foreign exchange contracts 3 5 — — — — 5 Other contracts 4 (3) — — — — (3) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 17 17 (441) 320 (2,927) 34 (107) (3,121) Tax impact Income tax on amounts retained in AOCI 169 (39) — 6 28 164 Income tax on amounts reclassified to earnings (31) — — — (4) (35) 138 (39) — 6 24 129 Other — — — (7) 55 48 Balance at December 31, 2019 (1,073) (317) 1,396 67 (345) (272) 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Transportation and other services revenue, Commodity sales revenue, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenue and Net foreign currency gain in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 These components are included in the computation of net benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of the Consolidated Statements of Financial Position location and carrying value of derivative instruments	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. December 31, 2021 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Derivative Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — — 259 259 (41) 218 Interest rate contracts 64 — — — 64 — 64 Commodity contracts — — — 204 204 (129) 75 Other contracts — — — 2 2 — 2 64 — — 465 529 (170) 359 Deferred amounts and other assets Foreign exchange contracts — — — 240 240 (61) 179 Interest rate contracts 88 — — — 88 (1) 87 Commodity contracts — — — 29 29 (13) 16 Other contracts — — — 3 3 — 3 88 — — 272 360 (75) 285 Accounts payable and other Foreign exchange contracts (15) — (112) (176) (303) 41 (262) Interest rate contracts (150) — — — (150) — (150) Commodity contracts (14) — — (250) (264) 129 (135) Other contracts — — — — — — — (179) — (112) (426) (717) 170 (547) Other long-term liabilities Foreign exchange contracts — — — (423) (423) 61 (362) Interest rate contracts (1) — — (23) (24) 1 (23) Commodity contracts (17) — — (67) (84) 13 (71) Other contracts — — — — — — — (18) — — (513) (531) 75 (456) Total net derivative asset/(liability) Foreign exchange contracts (15) — (112) (100) (227) — (227) Interest rate contracts 1 — — (23) (22) — (22) Commodity contracts (31) — — (84) (115) — (115) Other contracts — — — 5 5 — 5 (45) — (112) (202) (359) — (359) December 31, 2020 Derivative Derivative Derivative Instruments Used as Fair Value Hedges Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts — — — 180 180 (28) 152 Interest rate contracts — — — — — — — Commodity contracts — — — 143 143 (81) 62 Other contracts — — — — — — — — — — 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 Other contracts — — — — — — — 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) Other contracts — — — — — — — (219) — (87) (753) (1,059) 252 (807) Total net derivative asset/(liability) 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)
Summary of the maturity and notional principal or quantity outstanding related to derivative instruments	The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments. 2021 2020 As at December 31, 2022 2023 2024 2025 2026 Thereafter Total Total Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars) 2,508 — — — — — 2,508 3,522 Foreign exchange contracts - US dollar forwards - sell (millions of US dollars) 9,245 5,596 4,346 3,174 2,574 492 25,427 17,859 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) 28 29 30 30 28 32 177 265 Foreign exchange contracts - Euro forwards - sell (millions of Euro) 104 92 91 86 85 343 801 885 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) 72,500 — — — — — 72,500 72,500 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 395 47 35 30 26 64 597 4,635 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 2,363 1,784 1,132 — — — 5,279 5,396 Equity contracts (millions of Canadian dollars) 20 26 21 — — — 67 62 Commodity contracts - natural gas (billions of cubic feet) 165 18 5 11 — — 199 173 Commodity contracts - crude oil (millions of barrels) 12 — — — — — 12 15 Commodity contracts - power (megawatt per hour (MW/H) (43) (43) (43) (43) — — (43) 1 (35) 1 1 Total is an average net purchase/(sell) of power.
Schedule of effect of cash flow hedges and net investment hedges on consolidated earnings and consolidated comprehensive income, before income taxes	The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: 2021 2020 2019 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (29) (1) (19) Interest rate contracts 252 (595) (559) Commodity contracts (28) 2 (25) Other contracts 1 (3) 10 Fair value hedges Foreign exchange contracts (5) 5 — Net investment hedges Foreign exchange contracts — 13 2 191 (579) (591) Amount of (gain)/loss reclassified from AOCI to earnings Foreign exchange contracts 1 5 5 5 Interest rate contracts 2 296 253 157 Commodity contracts 3 1 — (1) Other contracts 4 2 (2) (3) 304 256 158 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 Transportation and other services revenue, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expenses in the Consolidated Statements of Earnings. Year ended December 31, 2021 2020 (millions of Canadian dollars) Unrealized gain/(loss) on derivative 8 (116) Unrealized gain/(loss) on hedged item (15) 133 Realized loss on derivative (41) (12) Realized gain on hedged item 45 —
Schedule of unrealized gains and losses associated with changes in the fair value of non-qualifying derivatives	The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Foreign exchange contracts 1 92 902 1,626 Interest rate contracts 2 2 (25) 178 Commodity contracts 3 71 (114) (62) Other contracts 4 8 (7) 9 Total unrealized derivative fair value gain/(loss), net 173 756 1,751 1 For the respective annual periods, reported within Transportation and other services revenue (2021 - $98 million gain; 2020 - $533 million gain; 2019 - $930 million gain) and Net foreign currency gain/(loss) (2021 - $6 million loss; 2020 - $369 million gain; 2019 - $696 million gain) in the Consolidated Statements of Earnings. 2 Reported as an increase within Interest expense in the Consolidated Statements of Earnings. 3 For the respective annual periods, reported within Transportation and other services revenue (2021 - $9 million gain; 2020 - $2 million loss; 2019 - $26 million loss), Commodity sales (2021 - $160 million gain; 2020 - $321 million loss; 2019 - $544 million loss), Commodity costs (2021 - $105 million loss; 2020 - $207 million gain; 2019 - $459 million gain) and Operating and administrative expense (2021 - $7 million gain; 2020 - $2 million gain; 2019 - $49 million gain) in the Consolidated Statements of Earnings.
Schedule of group credit concentrations and maximum credit exposure, with respect to derivative instruments	We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2021 2020 (millions of Canadian dollars) Canadian financial institutions 424 481 US financial institutions 130 99 European financial institutions 181 28 Asian financial institutions 30 167 Other 1 122 97 887 872 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
Schedule of derivative assets and liabilities measured at fair value	We have categorized our derivative assets and liabilities measured at fair value as follows: December 31, 2021 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 259 — 259 Interest rate contracts — 64 — 64 Commodity contracts 38 71 95 204 Other contracts — 2 — 2 38 396 95 529 Long-term derivative assets Foreign exchange contracts — 240 — 240 Interest rate contracts — 88 — 88 Commodity contracts — 21 8 29 Other contracts — 3 — 3 — 352 8 360 Financial liabilities Current derivative liabilities Foreign exchange contracts — (303) — (303) Interest rate contracts — (150) — (150) Commodity contracts (52) (66) (146) (264) Other contracts — — — — (52) (519) (146) (717) Long-term derivative liabilities Foreign exchange contracts — (423) — (423) Interest rate contracts — (24) — (24) Commodity contracts — (19) (65) (84) Other contracts — — — — — (466) (65) (531) Total net financial asset/(liability) Foreign exchange contracts — (227) — (227) Interest rate contracts — (22) — (22) Commodity contracts (14) 7 (108) (115) Other contracts — 5 — 5 (14) (237) (108) (359) 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 Interest rate contracts — — — — Commodity contracts 43 33 67 143 Other contracts — — — — 43 213 67 323 Long-term derivative assets Foreign exchange contracts — 466 — 466 Interest rate contracts — 56 — 56 Commodity contracts 1 24 14 39 Other contracts — — — — 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) Other contracts — — — — (1) (1,009) (49) (1,059) Total net financial asset/(liability) 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)
Schedule of significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments	The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 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 (19) Forward gas price 3.12 9.05 4.49 $/mmbtu 2 Crude 3 Forward crude price 76.02 98.99 91.73 $/barrel Power (60) Forward power price 31.00 125.13 76.23 $/MW/H Commodity contracts - physical 1 Natural gas (56) Forward gas price 2.65 9.25 4.63 $/mmbtu 2 Crude 24 Forward crude price 68.66 97.00 87.97 $/barrel (108) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One million British thermal units (mmbtu).
Schedule of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy	Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 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 (39) (123) Included in OCI (29) 2 Settlements 151 (1) Level 3 net derivative liability at end of period (108) (191) 1 Reported within Transportation and other services revenue, Commodity costs and Operating and administrative expenses in the Consolidated Statements of Earnings.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Schedule of income tax rate reconciliation	INCOME TAX RATE RECONCILIATION Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Earnings before income taxes 7,729 4,190 7,535 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 1,159 629 1,130 Increase/(decrease) resulting from: Provincial and state income taxes 1 228 288 415 Foreign and other statutory rate differentials 2 134 (53) 129 Effects of rate-regulated accounting 3 (139) (145) (63) Foreign allowable interest deductions 4 — (4) (29) Part VI.1 tax, net of federal Part I deduction 5 73 76 78 US Minimum Tax 6 — 44 67 Non-taxable portion of gain on sale of investment 7 (23) — — Valuation allowance 8 5 (6) 26 Intercorporate investments 9 — — (14) Noncontrolling interests (17) (8) (13) Other (5) (47) (18) Income tax expense 1,415 774 1,708 Effective income tax rate 18.3% 18.5% 22.7% 1 The change in provincial and state income taxes from 2020 to 2021 reflects the 2020 impact of state tax apportionment and rate changes in both the US and Canada offset by the increase in earnings from US and Canadian operations in 2021. 2 The change in foreign and other statutory rate differentials from 2020 to 2021 reflects the increase in earnings from US operations partially offset by higher rate benefits from foreign operations. 3 The amount in 2019 included the federal component of the tax benefit of the write-off of regulatory assets. 4 The decrease in foreign allowable interest deductions from 2019 to 2021 was due to changes in the related loan portfolio. 5 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada. 6 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation. 7 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco. 8 The increase in 2021 is due to the federal component of the tax effect of a valuation allowance on additional deferred tax assets that are not more likely than not to be realized. 9 The amount in 2019 relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate investments such that deferred tax related to outside basis temporary differences was required to be recorded for MATL.
Schedule of components of pretax earnings and income taxes	COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Earnings before income taxes Canada 3,399 2,789 3,560 US 3,336 407 3,115 Other 994 994 860 7,729 4,190 7,535 Current income taxes Canada 162 165 347 US 80 64 107 Other 82 98 98 324 327 552 Deferred income taxes Canada 344 378 490 US 741 66 672 Other 6 3 (6) 1,091 447 1,156 Income tax expense 1,415 774 1,708
Schedule of major components of deferred income tax assets and liabilities	Major components of deferred income tax assets and liabilities are as follows: December 31, 2021 2020 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (8,721) (7,786) Investments (6,097) (4,649) Regulatory assets (1,245) (1,156) Other (208) (127) Total deferred income tax liabilities (16,271) (13,718) Deferred income tax assets Financial instruments 315 518 Pension and OPEB plans 110 251 Loss carryforwards 3,081 2,005 Other 1,648 1,461 Total deferred income tax assets 5,154 4,235 Less valuation allowance (84) (79) Total deferred income tax assets, net 5,070 4,156 Net deferred income tax liabilities (11,201) (9,562) Presented as follows: Total deferred income tax assets 488 770 Total deferred income tax liabilities (11,689) (10,332) Net deferred income tax liabilities (11,201) (9,562)
Schedule of unrecognized tax benefits	UNRECOGNIZED TAX BENEFITS Year ended December 31, 2021 2020 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 121 129 Gross increases for tax positions of current year 1 1 Gross decreases for tax positions of prior year (26) (1) Change in translation of foreign currency (1) (3) Lapses of statute of limitations (19) (5) Unrecognized tax benefits at end of year 76 121

PENSION AND OTHER POSTRETIREM_2

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2021
Retirement Benefits [Abstract]
Schedule of Changes in Projected Benefit Obligation, Plan Assets and Funded Status	The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit pension plans: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 4,855 4,446 1,243 1,230 Service cost 139 148 44 44 Interest cost 101 128 17 31 Participant contributions 28 31 — — Actuarial (gain)/loss 1 (329) 292 (21) 95 Benefits paid (194) (190) (84) (128) Foreign currency exchange rate changes — — (11) (23) Other — — (4) (6) Projected benefit obligation at end of year 2 4,600 4,855 1,184 1,243 Change in plan assets Fair value of plan assets at beginning of year 4,077 3,827 1,062 1,104 Actual return on plan assets 505 288 151 83 Employer contributions 120 121 43 27 Participant contributions 28 31 — — Benefits paid (194) (190) (84) (128) Foreign currency exchange rate changes — — (8) (18) Other — — (4) (6) Fair value of plan assets at end of year 3 4,536 4,077 1,160 1,062 Underfunded status at end of year (64) (778) (24) (181) Presented as follows: Deferred amounts and other assets 250 35 98 — Accounts payable and other (9) (9) (4) (3) Other long-term liabilities (305) (804) (118) (178) (64) (778) (24) (181) 1 Primarily due to increase in the discount rate used to measure the benefit obligations (2020 - primarily due to decrease in the discount rate used to measure the benefit obligations). 2 The accumulated benefit obligation for our Canadian pension plans was $4.3 billion and $4.5 billion as at December 31, 2021 and 2020, respectively. The accumulated benefit obligation for our US pension plans was $1.1 billion and $1.2 billion as at December 31, 2021 and 2020, respectively. 3 Assets in the amount of $13 million (2020 - $11 million) and $84 million (2020 - $59 million), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in grantor trusts and rabbi trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes. Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Accumulated benefit obligation 440 4,094 115 1,207 Fair value of plan assets 247 3,621 — 1,062 Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Projected benefit obligation 1,272 4,434 121 1,243 Fair value of plan assets 1,020 3,621 — 1,062
Schedule of Accumulated Benefit Obligation and Fair Value of Plan Assets	Certain of our OPEB plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the accumulated benefit obligation and fair value of plan assets were as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Accumulated benefit obligation 274 321 94 191 Fair value of plan assets — — 51 106
Schedule of Amounts Recognized in AOCI	The amount of pre-tax AOCI relating to our pension plans are as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Net actuarial loss 226 542 92 233 Prior service credit — — (1) (1) Total amount recognized in AOCI 1 226 542 91 232 1 Excludes amounts related to cumulative translation adjustment. The amount of pre-tax AOCI relating to our OPEB plans are as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Net actuarial (gain)/loss (35) 15 (104) (7) Prior service credit (1) (1) (37) (44) Total amount recognized in AOCI 1 (36) 14 (141) (51) 1 Excludes amounts related to cumulative translation adjustment.
Schedule of Net Benefit Costs Recognized	The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our pension plans are as follows: Canada US Year ended December 31, 2021 2020 2019 2021 2020 2019 (millions of Canadian dollars) Service cost 139 148 149 44 44 45 Interest cost 1 101 128 139 17 31 41 Expected return on plan assets 1 (252) (260) (245) (73) (88) (78) Amortization/settlement of net actuarial loss 1 54 42 41 11 1 2 Amortization/curtailment of prior service credit 1 — — — — (1) (1) Net periodic benefit (credit)/cost 42 58 84 (1) (13) 9 Defined contribution benefit cost 7 6 8 — — — Net pension (credit)/cost recognized in Earnings 49 64 92 (1) (13) 9 Amount recognized in OCI: Effect of plan combination — — — — — (6) Amortization/settlement of net actuarial loss (25) (21) (26) (11) (1) (2) Amortization/curtailment of prior service credit — — — — 1 1 Net actuarial (gain)/loss arising during the year (291) 118 115 (99) 100 8 Total amount recognized in OCI (316) 97 89 (110) 100 1 Total amount recognized in Comprehensive income (267) 161 181 (111) 87 10 1 Reported within Other income/(expense) in the Consolidated Statements of Earnings. The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows: Canada US Year ended December 31, 2021 2020 2019 2021 2020 2019 (millions of Canadian dollars) Service cost 6 5 5 1 2 2 Interest cost 1 7 8 10 3 7 10 Expected return on plan assets 1 — — — (10) (12) (12) Amortization/settlement of net actuarial gain 1 — (1) (7) (1) (1) — Amortization/curtailment of prior service credit 1 — — (1) (7) (2) (2) Net periodic benefit (credit)/cost recognized in Earnings 13 12 7 (14) (6) (2) Amount recognized in OCI: Amortization/settlement of net actuarial gain — 1 7 1 1 — Amortization/curtailment of prior service credit — — 1 7 2 2 Net actuarial (gain)/loss arising during the year (50) 21 15 (80) 15 (8) Prior service credit — — — — (33) — Total amount recognized in OCI (50) 22 23 (72) (15) (6) Total amount recognized in Comprehensive income (37) 34 30 (86) (21) (8) 1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
Schedule of Actuarial Assumptions Used	The weighted average assumptions made in the measurement of the projected benefit obligation and net periodic benefit cost of our pension plans are as follows: Canada US 2021 2020 2019 2021 2020 2019 Projected benefit obligation Discount rate 3.2 % 2.6 % 3.0 % 2.6 % 2.2 % 3.0 % Rate of salary increase 2.9 % 2.3 % 3.2 % 2.8 % 2.7 % 2.9 % Cash balance interest credit rate N/A N/A N/A 4.3 % 4.3 % 4.5 % Net periodic benefit cost Discount rate 2.6 % 3.0 % 3.8 % 2.2 % 3.0 % 3.9 % Rate of return on plan assets 6.2 % 6.8 % 7.0 % 7.3 % 7.9 % 8.0 % Rate of salary increase 2.3 % 3.2 % 3.2 % 2.7 % 2.9 % 2.9 % Cash balance interest credit rate N/A N/A N/A 4.3 % 4.5 % 4.5 % The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligation and net periodic benefit cost of our OPEB plans are as follows: Canada US 2021 2020 2019 2021 2020 2019 Accumulated postretirement benefit obligation Discount rate 3.2 % 2.6 % 3.1 % 2.4 % 2.0 % 2.8 % Net periodic benefit cost Discount rate 2.6 % 3.1 % 3.8 % 2.0 % 2.8 % 4.0 % Rate of return on plan assets N/A N/A N/A 6.0 % 6.7 % 6.7 %
Schedule of Other Postretirement Benefits	The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit OPEB plans: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 321 293 254 288 Service cost 6 5 1 2 Interest cost 7 8 3 7 Participant contributions — — 8 4 Actuarial (gain)/loss 1 (51) 21 (69) 17 Benefits paid (9) (6) (22) (28) Plan amendments — — — (33) Foreign currency exchange rate changes — — (3) (4) Other — — 1 1 Accumulated postretirement benefit obligation at end of year 274 321 173 254 Change in plan assets Fair value of plan assets at beginning of year — — 188 188 Actual return on plan assets — — 22 14 Employer contributions 9 6 6 12 Participant contributions — — 8 4 Benefits paid (9) (6) (22) (28) Foreign currency exchange rate changes — — (3) (3) Other — — 2 1 Fair value of plan assets at end of year — — 201 188 Overfunded/(underfunded) status at end of year (274) (321) 28 (66) Presented as follows: Deferred amounts and other assets — — 71 19 Accounts payable and other (12) (13) — (6) Other long-term liabilities (262) (308) (43) (79) (274) (321) 28 (66) 1 Primarily due to increase in the discount rate used to measure the benefit obligations ( 2020 - primarily due to decrease in the discount rate used to measure the benefit obligations)
Schedule of Assumed Health Care Cost Trend Rates	The assumed rates for the next year used to measure the expected cost of benefits are as follows: Canada US 2021 2020 2021 2020 Health care cost trend rate assumed for next year 4.0 % 4.0 % 7.0 % 6.8 % Rate to which the cost trend is assumed to decline (ultimate trend rate) 4.0 % 4.0 % 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2037 2037
Schedule of Allocation of Plan Assets	The asset allocation targets and major categories of plan assets are as follows: Canada US Target December 31, Target December 31, Asset Category Allocation 2021 2020 Allocation 2021 2020 Equity securities 43.8 % 46.7 % 47.2 % 45.0 % 52.5 % 55.6 % Fixed income securities 28.9 % 29.8 % 29.6 % 20.1 % 18.4 % 17.2 % Alternatives 1 27.3 % 23.5 % 23.2 % 34.9 % 29.1 % 27.2 % 1 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Fund values are based on the net asset value of the funds that invest directly in the aforementioned underlying investments. The values of the investments have been estimated using the capital accounts representing the plan's ownership interest in the funds.
Schedule of Changes in Fair Value of Plan Assets	The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level: Canada US Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2021 Cash and cash equivalents 180 — — 180 10 — — 10 Equity securities Canada 198 228 — 426 — — — — US 1 — — 1 — — — — Global — 1,693 — 1,693 — 609 — 609 Fixed income securities Government 258 459 — 717 — 86 — 86 Corporate — 453 — 453 — 118 — 118 Alternatives 4 — — 1,064 1,064 — — 337 337 Forward currency contracts — 2 — 2 — — — — Total pension plan assets at fair value 637 2,835 1,064 4,536 10 813 337 1,160 December 31, 2020 Cash and cash equivalents 213 — — 213 5 — — 5 Equity securities Canada 178 188 — 366 — — — — US 2 — — 2 — — — — Global — 1,556 — 1,556 — 590 — 590 Fixed income securities Government 207 378 — 585 — 75 — 75 Corporate — 410 — 410 — 103 — 103 Alternatives 4 — — 912 912 — — 289 289 Forward currency contracts — 33 — 33 — — — — Total pension plan assets at fair value 600 2,565 912 4,077 5 768 289 1,062 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Changes in the net fair value of pension plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada US December 31, 2021 2020 2021 2020 (millions of Canadian dollars) Balance at beginning of year 912 852 289 276 Unrealized and realized gains/(losses) 77 (27) 38 7 Purchases and settlements, net 75 87 10 6 Balance at end of year 1,064 912 337 289 OPEB Plans The following table summarizes the fair value of plan assets for our US funded OPEB plans recorded at each fair value hierarchy level: Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2021 Cash and cash equivalents 4 — — 4 Equity securities US — 39 — 39 Global — 75 — 75 Fixed income securities Government 47 6 — 53 Corporate — 8 — 8 Alternatives 4 — — 22 22 Total OPEB plan assets at fair value 51 128 22 201 December 31, 2020 Equity securities US — 35 — 35 Global — 79 — 79 Fixed income securities Government 38 6 — 44 Corporate — 8 — 8 Alternatives 4 — — 22 22 Total OPEB plan assets at fair value 38 128 22 188 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 Alternatives includes investments in private debt, private equity, infrastructure and real estate. Changes in the net fair value of US funded OPEB plan assets classified as Level 3 in the fair value hierarchy were as follows: December 31, 2021 2020 (millions of Canadian dollars) Balance at beginning of year 22 18 Unrealized and realized gains 2 1 Purchases and settlements, net (2) 3 Balance at end of year 22 22
Schedule of Expected Benefit Payments and Employer Contributions	Year ending December 31, 2022 2023 2024 2025 2026 2027-2031 (millions of Canadian dollars) Pension Canada 197 203 208 212 217 1,163 US 80 78 78 76 77 374 OPEB Canada 12 12 12 13 13 67 US 17 15 14 13 12 51

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Assets and liabilities, lessee	Supplemental Statements of Financial Position Information December 31, 2021 December 31, (millions of Canadian dollars, except lease term and discount rate) Operating leases 1 Operating lease right-of-use assets, net 2 645 708 Operating lease liabilities - current 3 92 80 Operating lease liabilities - long-term 3 612 681 Total operating lease liabilities 704 761 Finance leases Finance lease right-of-use assets, net 4 49 57 Finance lease liabilities - current 5 13 11 Finance lease liabilities - long-term 3 33 42 Total finance lease liabilities 46 53 Weighted average remaining lease term Operating leases 12 years 13 years Finance leases 7 years 7 years Weighted average discount rate Operating leases 4.1 % 4.1 % Finance leases 3.8 % 3.8 % 1 Affiliate right-of-use assets, current lease liabilities and long-term lease liabilities as at December 31, 2021 were $51 million (December 31, 2020 - $65 million), $5 million (December 31, 2020 - $5 million) and $47 million (December 31, 2020 - $52 million), respectively. 2 Operating lease right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position. 3 Current operating lease liabilities and long-term operating and finance lease liabilities are reported under Accounts payable and other and Other long-term liabilities, respectively, in the Consolidated Statements of Financial Position. 4 Finance lease right-of-use assets are reported under Property, plant and equipment, net in the Consolidated Statements of Financial Position. 5 Current finance lease liabilities are reported under Current portion of long-term debt in the Consolidated Statements of Financial Position.
Lessee, operating lease liability, maturity	As at December 31, 2021, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance leases (millions of Canadian dollars) 2022 117 15 2023 98 13 2024 91 9 2025 84 2 2026 72 1 Thereafter 455 11 Total undiscounted lease payments 917 51 Less imputed interest (213) (5) Total 704 46
Lessee, finance lease liability, maturity	As at December 31, 2021, our operating and finance lease liabilities are expected to mature as follows: Operating leases Finance leases (millions of Canadian dollars) 2022 117 15 2023 98 13 2024 91 9 2025 84 2 2026 72 1 Thereafter 455 11 Total undiscounted lease payments 917 51 Less imputed interest (213) (5) Total 704 46
Operating lease, lease income	Year ended December 31, 2021 2020 (millions of Canadian dollars) Operating lease income 263 265 Variable lease income 333 361 Total lease income 1 596 626 1 Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings.
Lessor, operating lease, payments to be received, maturity	As at December 31, 2021, the following table sets out future lease payments to be received under operating lease contracts where we are the lessor: Operating leases (millions of Canadian dollars) 2022 235 2023 215 2024 205 2025 196 2026 191 Thereafter 1,938 Future lease payments 2,980

CHANGES IN OPERATING ASSETS A_2

CHANGES IN OPERATING ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2021
CHANGES IN OPERATING ASSETS AND LIABILITIES
Schedule of changes in operating assets and liabilities	Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Accounts receivable and other (1,228) 1,546 (547) Accounts receivable from affiliates (38) 8 6 Inventory (118) (254) (24) Deferred amounts and other assets (195) (586) 133 Accounts payable and other (63) (770) 63 Accounts payable to affiliates 52 1 (24) Interest payable 43 31 (41) Other long-term liabilities (69) 117 175 (1,616) 93 (259)

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
Our Transactions with Equity Investees	Our transactions with significantly influenced investees are as follows: Year ended December 31, 2021 2020 2019 (millions of Canadian dollars) Transportation and other services 149 133 140 Commodity sales 20 21 107 Operating and administrative 1 292 252 241 Commodity costs 2 790 518 773 Gas distribution costs 131 135 133 1 During the years December 31, 2021, 2020 and 2019, we had Operating and administrative costs from the Seaway Crude Pipeline System of $389 million, $342 million and $327 million, respectively. These costs are a result of an operational contract where we utilize capacity on Seaway Crude Pipeline System assets for use in our Liquids Pipelines business. The costs are offset by recoveries recorded on expenses incurred by us on behalf of our significantly influenced investees of $104 million, $94 million and $86 million for the years ended December 31, 2021, 2020 and 2019.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Schedule of commitments	As at December 31, 2021, we have commitments as detailed below: Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Annual debt maturities 1 73,809 6,164 7,910 4,559 4,357 11,007 39,812 Interest obligations 2 36,044 2,531 2,389 2,229 2,073 1,925 24,897 Purchase of services, pipe and other materials, including transportation 3 7,876 2,945 1,010 736 561 607 2,017 Maintenance agreements 346 41 20 20 21 21 223 Right-of-ways commitments 1,249 35 35 35 36 37 1,071 Total 119,324 11,716 11,364 7,579 7,048 13,597 68,020 1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discounts, debt issuance costs, finance lease obligations and fair value adjustment. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. 2 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates. 3 Includes capital and operating commitments. Consists primarily of gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments.

QUARTERLY FINANCIAL DATA (UNA_2

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information	Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2021 Operating revenues 12,187 10,948 11,466 12,470 47,071 Operating income 2,548 1,816 1,388 2,053 7,805 Earnings 2,014 1,521 814 1,965 6,314 Earnings attributable to controlling interests 1,992 1,484 780 1,933 6,189 Earnings attributable to common shareholders 1,900 1,394 682 1,840 5,816 Earnings per common share Basic 0.94 0.69 0.34 0.91 2.87 Diluted 0.94 0.69 0.34 0.91 2.87 2020 Operating revenues 12,013 7,956 9,110 10,008 39,087 Operating income 1,513 2,098 2,095 2,251 7,957 Earnings/(loss) (1,364) 1,777 1,104 1,899 3,416 Earnings/(loss) attributable to controlling interests (1,333) 1,741 1,084 1,871 3,363 Earnings/(loss) attributable to common shareholders (1,429) 1,647 990 1,775 2,983 Earnings/(loss) per common share Basic (0.71) 0.82 0.49 0.88 1.48 Diluted (0.71) 0.82 0.49 0.88 1.48

BUSINESS OVERVIEW (Details)

BUSINESS OVERVIEW (Details)	12 Months Ended
	Dec. 31, 2021segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments	5

SIGNIFICANT ACCOUNTING POLICI_3

SIGNIFICANT ACCOUNTING POLICIES - REGULATION (Details) - CAD ($)	Dec. 31, 2021	Dec. 31, 2020
REGULATION
Regulatory assets (Note 7)	$ 5,865,000,000	$ 5,629,000,000
Deferral for Depreciation for Phase-In Plans under U.S. GAAP Guidance
REGULATION
Regulatory assets (Note 7)	$ 0

SIGNIFICANT ACCOUNTING POLICI_4

SIGNIFICANT ACCOUNTING POLICIES - REVENUE RECOGNITION (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 305
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 127	$ 292	$ 169

SIGNIFICANT ACCOUNTING POLICI_5

SIGNIFICANT ACCOUNTING POLICIES - PROPERTY, PLANT AND EQUIPMENT (Details)	12 Months Ended
	Dec. 31, 2021depreciation_method
Accounting Policies [Abstract]
Number of primary methods of depreciation which are utilized	2

SIGNIFICANT ACCOUNTING POLICI_6

SIGNIFICANT ACCOUNTING POLICIES - STOCK-BASED COMPENSATION (Details)	12 Months Ended
	Dec. 31, 2021
Performance Stock Units (PSUs)
STOCK-BASED COMPENSATION
Vesting period	3 years
Annual vesting (percent)	33.33%
Restricted Stock Units (RSU)
STOCK-BASED COMPENSATION
Vesting period	3 years

REVENUE (Details)

REVENUE (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									$ 19,432	$ 18,817	$ 19,697
Total operating revenues	$ 12,470	$ 11,466	$ 10,948	$ 12,187	$ 10,008	$ 9,110	$ 7,956	$ 12,013	47,071	39,087	50,069
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									70	60	69
Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									19,362	18,757	19,628
Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									14,532	14,358	14,302
Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									648	571	578
Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									49	27	423
Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,026	3,663	4,210
Total operating revenues									4,026	3,663	4,205
Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									177	198	180
Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											4
Revenue not from contract with customers									26,873	19,259	29,305
Total operating revenues									26,873	19,259	29,309
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									766	1,011	1,067
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									9,639	9,255	9,191
Liquids Pipelines | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Liquids Pipelines | Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									9,639	9,255	9,191
Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,668	4,824	5,172
Gas Transmission and Midstream | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	4
Gas Transmission and Midstream | Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,668	4,824	5,168
Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,948	4,540	5,154
Gas Distribution and Storage | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									70	60	65
Gas Distribution and Storage | Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,878	4,480	5,089
Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									177	198	180
Renewable Power Generation | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Renewable Power Generation | Transferred over Time
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									177	198	180
Business segments | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									9,639	9,255	9,191
Total operating revenues									10,581	10,423	10,219
Business segments | Liquids Pipelines | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									9,492	9,161	9,082
Business segments | Liquids Pipelines | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									147	94	109
Business segments | Liquids Pipelines | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Liquids Pipelines | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Liquids Pipelines | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Liquids Pipelines | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											0
Revenue not from contract with customers									0	0	0
Business segments | Liquids Pipelines | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									375	584	659
Business segments | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,668	4,824	5,172
Total operating revenues									4,711	4,870	5,207
Business segments | Gas Transmission and Midstream | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,364	4,523	4,477
Business segments | Gas Transmission and Midstream | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									255	274	268
Business segments | Gas Transmission and Midstream | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									49	27	423
Business segments | Gas Transmission and Midstream | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Gas Transmission and Midstream | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Gas Transmission and Midstream | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											4
Revenue not from contract with customers									0	0	0
Business segments | Gas Transmission and Midstream | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									42	44	30
Business segments | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,948	4,540	5,154
Total operating revenues									4,980	4,569	5,179
Business segments | Gas Distribution and Storage | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									676	674	743
Business segments | Gas Distribution and Storage | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									246	203	201
Business segments | Gas Distribution and Storage | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Gas Distribution and Storage | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4,026	3,663	4,210
Business segments | Gas Distribution and Storage | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Gas Distribution and Storage | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											0
Revenue not from contract with customers									0	0	0
Business segments | Gas Distribution and Storage | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									13	17	9
Business segments | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									177	198	180
Total operating revenues									512	587	567
Business segments | Renewable Power Generation | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Renewable Power Generation | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Renewable Power Generation | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Renewable Power Generation | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Renewable Power Generation | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									177	198	180
Business segments | Renewable Power Generation | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											0
Revenue not from contract with customers									0	0	0
Business segments | Renewable Power Generation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									336	389	387
Business segments | Energy Services
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Total operating revenues									26,917	19,283	29,374
Business segments | Energy Services | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Energy Services | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Energy Services | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Energy Services | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Energy Services | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Business segments | Energy Services | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											0
Revenue not from contract with customers									26,873	19,259	29,305
Business segments | Energy Services | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	0	(2)
Eliminations and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Total operating revenues									(630)	(645)	(477)
Eliminations and Other | Transportation revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Storage and other revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Gas gathering and processing revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Gas distribution revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Electricity and transmission revenue
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0	0	0
Eliminations and Other | Commodity sales
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers											0
Revenue not from contract with customers									0	0	0
Eliminations and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0	(23)	(16)
Intersegment revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(630)	(622)	(461)
Intersegment revenue | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									567	584	369
Intersegment revenue | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									1	2	5
Intersegment revenue | Gas Distribution and Storage
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									19	12	16
Intersegment revenue | Renewable Power Generation
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(1)	0	0
Intersegment revenue | Energy Services
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									$ 44	$ 24	$ 71

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Mark-to-market gains (losses)	$ 59	$ 265	$ 346
Revenue recognized	305
Increase (decrease) in contract with customers, liability	397
Remaining performance obligation	59,800
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	$ 7,400
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period	1 year

REVENUE - Contract Balances (De

REVENUE - Contract Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Accounts receivable, net	$ 2,369	$ 2,042
Contract with customer, asset	213	226
Contract with customer, liability	$ 1,898	$ 1,815

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segmented Information
Revenues	$ 12,470	$ 11,466	$ 10,948	$ 12,187	$ 10,008	$ 9,110	$ 7,956	$ 12,013	$ 47,071	$ 39,087	$ 50,069
Commodity and gas distribution costs									(28,702)	(20,669)	(31,004)
Operating and administrative									(6,712)	(6,749)	(6,991)
Income/(loss) from equity investments									1,711	1,136	1,503
Impairment of equity investments									(111)	(2,351)	0
Other income/(expense)									979	238	435
Impairment of long-lived assets											(423)
Earnings/(loss) before interest, income tax expense and depreciation and amortization									14,236	10,692	13,589
Depreciation and amortization									(3,852)	(3,712)	(3,391)
Interest expense									(2,655)	(2,790)	(2,663)
Income tax expense									(1,415)	(774)	(1,708)
Earnings									6,314	3,416	5,827
Capital expenditures									7,885	5,470	5,550
Property, plant and equipment, net (Note 11)	100,067				94,571				100,067	94,571	93,723
Business segments | Liquids Pipelines
Segmented Information
Revenues									10,581	10,423	10,219
Commodity and gas distribution costs									(25)	(20)	(29)
Operating and administrative									(3,431)	(3,331)	(3,298)
Income/(loss) from equity investments									759	558	780
Impairment of equity investments									0	0
Other income/(expense)									13	53	30
Impairment of long-lived assets											(21)
Earnings/(loss) before interest, income tax expense and depreciation and amortization									7,897	7,683	7,681
Capital expenditures									4,051	2,033	2,548
Property, plant and equipment, net (Note 11)	52,530				48,799				52,530	48,799	48,783
Business segments | Gas Transmission and Midstream
Segmented Information
Revenues									4,711	4,870	5,207
Commodity and gas distribution costs									0	0	0
Operating and administrative									(1,877)	(1,859)	(2,232)
Income/(loss) from equity investments									813	479	682
Impairment of equity investments									(111)	(2,351)
Other income/(expense)									135	(52)	(181)
Impairment of long-lived assets											(105)
Earnings/(loss) before interest, income tax expense and depreciation and amortization									3,671	1,087	3,371
Capital expenditures									2,420	2,130	1,753
Property, plant and equipment, net (Note 11)	27,028				25,745				27,028	25,745	25,268
Business segments | Gas Distribution and Storage
Segmented Information
Revenues									4,980	4,569	5,179
Commodity and gas distribution costs									(2,147)	(1,810)	(2,354)
Operating and administrative									(1,143)	(1,091)	(1,149)
Income/(loss) from equity investments									42	9	4
Impairment of equity investments									0	0
Other income/(expense)									385	71	67
Impairment of long-lived assets											0
Earnings/(loss) before interest, income tax expense and depreciation and amortization									2,117	1,748	1,747
Capital expenditures									1,343	1,134	1,100
Property, plant and equipment, net (Note 11)	16,904				16,079				16,904	16,079	15,622
Business segments | Renewable Power Generation
Segmented Information
Revenues									512	587	567
Commodity and gas distribution costs									0	(2)	(2)
Operating and administrative									(180)	(191)	(189)
Income/(loss) from equity investments									101	94	31
Impairment of equity investments									0	0
Other income/(expense)									75	35	1
Impairment of long-lived assets											(297)
Earnings/(loss) before interest, income tax expense and depreciation and amortization									508	523	111
Capital expenditures									16	81	23
Property, plant and equipment, net (Note 11)	3,315				3,495				3,315	3,495	3,658
Business segments | Energy Services
Segmented Information
Revenues									26,917	19,283	29,374
Commodity and gas distribution costs									(27,174)	(19,450)	(29,091)
Operating and administrative									(48)	(67)	(44)
Income/(loss) from equity investments									0	(3)	8
Impairment of equity investments									0	0
Other income/(expense)									(8)	1	3
Impairment of long-lived assets											0
Earnings/(loss) before interest, income tax expense and depreciation and amortization									(313)	(236)	250
Capital expenditures									1	2	2
Property, plant and equipment, net (Note 11)	23				24				23	24	24
Eliminations and Other
Segmented Information
Revenues									(630)	(645)	(477)
Commodity and gas distribution costs									644	613	472
Operating and administrative									(33)	(210)	(79)
Income/(loss) from equity investments									(4)	(1)	(2)
Impairment of equity investments									0	0
Other income/(expense)									379	130	515
Impairment of long-lived assets											0
Earnings/(loss) before interest, income tax expense and depreciation and amortization									356	(113)	429
Capital expenditures									54	90	124
Property, plant and equipment, net (Note 11)	$ 267				$ 429				$ 267	$ 429	$ 368
Customer Concentration Risk | Sales Revenue, Net | Largest Non-Affiliated Customer
Narrative
Concentration (percent)									13.50%	13.60%

SEGMENTED INFORMATION - GEOGRAP

SEGMENTED INFORMATION - GEOGRAPHIC INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Geographic Information
Revenues	$ 12,470	$ 11,466	$ 10,948	$ 12,187	$ 10,008	$ 9,110	$ 7,956	$ 12,013	$ 47,071	$ 39,087	$ 50,069
Property, plant and equipment, net	100,067				94,571				100,067	94,571	93,723
Canada
Geographic Information
Revenues									20,474	16,453	19,954
Property, plant and equipment, net	47,102				46,499				47,102	46,499
US
Geographic Information
Revenues									26,597	22,634	$ 30,115
Property, plant and equipment, net	$ 52,965				$ 48,072				$ 52,965	$ 48,072

EARNINGS PER COMMON SHARE (Deta

EARNINGS PER COMMON SHARE (Details) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share [Abstract]
Weighted average number of common shares outstanding (shares)	2	5	6
Weighted average shares outstanding (in shares)	2,023	2,020	2,017
Effect of dilutive options (in shares)	2	1	3
Diluted weighted average shares outstanding (in shares)	2,025	2,021	2,020
Anti-dilutive stock options excluded from diluted earnings per common share calculation (in shares)	18.6	29.8	17.8
Weighted average exercise price of anti-dilutive stock options (in CAD per share)	$ 52.89	$ 51.42	$ 53.56

REGULATORY MATTERS - Liquids Pi

REGULATORY MATTERS - Liquids Pipelines (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 5,865	$ 5,629
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Term of CTS establishing a Canadian Local Toll	10 years
Regulatory assets	$ 2,100	$ 1,900
Southern Lights Pipeline
Public Utilities, General Disclosures [Line Items]
Pre-determined after-tax rate of return on equity (ROE) (as a percent)	10.00%

REGULATORY MATTERS - Enbridge G

REGULATORY MATTERS - Enbridge Gas Distribution Inc. (Narrative) (Details) - Enbridge Gas Distribution	12 Months Ended
	Dec. 31, 2021
Public Utilities, General Disclosures [Line Items]
Term of incentive regulation framework	5 years
Inflation stretch factor (percent)	0.30%
Earnings allowed to be retained under earnings sharing mechanism (as a percent)	1.50%

REGULATORY MATTERS - Schedule o

REGULATORY MATTERS - Schedule of Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Regulatory Assets [Line Items]
Regulatory assets (Note 7)	$ 259	$ 232
Noncurrent regulatory assets	5,606	5,397
Regulatory assets	5,865	5,629
Regulatory Liabilities [Line Items]
Current regulatory liabilities	106	270
Noncurrent regulatory liabilities	3,321	3,124
Regulatory liabilities	3,427	3,394
Purchased gas variance
Regulatory Liabilities [Line Items]
Current regulatory liabilities	0	153
Other Regulatory Assets (Liabilities)
Regulatory Liabilities [Line Items]
Current regulatory liabilities	106	117
Noncurrent regulatory liabilities	234	150
Future removal and restoration costs
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	1,543	1,455
U.S income Taxes
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	895	941
Pipeline future abandonment costs
Regulatory Liabilities [Line Items]
Noncurrent regulatory liabilities	649	578
Purchase gas variance
Regulatory Assets [Line Items]
Noncurrent regulatory assets	215	0
Under-recovery of fuel costs
Regulatory Assets [Line Items]
Regulatory assets (Note 7)	114	86
Deferred income taxes
Regulatory Assets [Line Items]
Noncurrent regulatory assets	4,176	3,890
Long-term debt
Regulatory Assets [Line Items]
Noncurrent regulatory assets	398	429
Pension plans and OPEB
Regulatory Assets [Line Items]
Noncurrent regulatory assets	78	402
Negative salvage
Regulatory Assets [Line Items]
Noncurrent regulatory assets	243	246
Accounting policy changes
Regulatory Assets [Line Items]
Noncurrent regulatory assets	157	169
Other Regulatory Assets (Liabilities)
Regulatory Assets [Line Items]
Regulatory assets (Note 7)	145	146
Noncurrent regulatory assets	$ 339	$ 261

ACQUISITIONS AND DISPOSITIONS -

ACQUISITIONS AND DISPOSITIONS - Acquisitions (Narrative) (Details) - Moda Midstream Operating, LLC (Moda) $ in Millions, $ in Millions	Oct. 12, 2021USD ($)	Oct. 12, 2021CAD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2021CAD ($)	Oct. 12, 2021CAD ($)
Business Acquisition [Line Items]
Cash	$ 3,000	$ 3,755
Contingent consideration	$ 150				$ 187
Ownership interest acquired (as a percent)	20.00%				20.00%
Amortized on a straight-line basis over an expected useful life	10 years	10 years
Tax deductible period	15 years	15 years
Acquisition-related expenses/transaction costs incurred				$ 21
Revenues generated by acquiree			$ 80
Earnings generated by acquiree			$ 9

ACQUISITIONS AND DISPOSITIONS_2

ACQUISITIONS AND DISPOSITIONS - Summary of Estimated Fair Values Assigned to Net Assets (Details) $ in Millions, $ in Millions	Oct. 12, 2021USD ($)	Oct. 12, 2021CAD ($)	Dec. 31, 2021CAD ($)	Oct. 12, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Fair value of net assets acquired:
Goodwill			$ 32,775		$ 32,688	$ 33,153
Moda Midstream Operating, LLC (Moda)
Fair value of net assets acquired:
Current assets				$ 62
Property, plant and equipment, net				1,480
Long-term investments				427
Intangible assets				1,781
Current liabilities				(59)
Long-term liabilities				17
Goodwill				268
Purchase price:
Cash	$ 3,000	$ 3,755
Contingent consideration	$ 150			$ 187
Purchase price		$ 3,942

ACQUISITIONS AND DISPOSITIONS_3

ACQUISITIONS AND DISPOSITIONS - Schedule of Supplemental Pro Forma Consolidated Financial Information (Details) - Moda Midstream Operating, LLC (Moda) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Operating revenues	$ 47,339	$ 39,435
Earnings attributable to common shareholders	5,771	2,938
Acquisition-related expenses	21
Acquisition-related expenses, after tax	16
Amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets	193	207
Amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets, after tax	$ 145	$ 155

ACQUISITIONS AND DISPOSITIONS_4

ACQUISITIONS AND DISPOSITIONS - Dispositions (Narrative) (Details) $ in Millions	Jun. 01, 2020CAD ($)	May 01, 2020CAD ($)	Apr. 01, 2020CAD ($)	Dec. 31, 2019CAD ($)	Nov. 01, 2019CAD ($)	Oct. 01, 2019USD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Oct. 01, 2019CAD ($)	Jul. 04, 2018CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of assets							$ 319,000,000	$ 6,000,000	$ (254,000,000)
Disposal group, held-for-sale, not discontinued operations | Montana-Alberta Tie Line (MATL)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of long-lived assets to be disposed of									297,000,000
Disposal group, held-for-sale, not discontinued operations | Line 10 Crude Oil
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest	$ 0
Dispositions | Montana-Alberta Tie Line (MATL)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest		$ 4,000,000
Cash proceeds from sale of interest		$ 189,000,000
Dispositions | Ozark Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest			$ 1,000,000
Cash proceeds from sale of interest			$ 63,000,000
Dispositions | St. Lawrence Gas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest									(10,000,000)
Cash proceeds from sale of interest					$ 72,000,000
Dispositions | Enbridge Gas New Brunswick
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal of interest									(3,000,000)
Cash proceeds from sale of interest						$ 331
Goodwill included in assets subsequently disposed										$ 133,000,000
Dispositions | Canadian Natural Gas Gathering and Processing Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration											$ 4,300,000,000
Federally Regulated Facilities | Dispositions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of assets				$ 1,700,000,000
Gain on disposal of assets									$ (268,000,000)

ACCOUNTS RECEIVABLE AND OTHER_2

ACCOUNTS RECEIVABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Receivables [Abstract]
Trade receivables and unbilled revenues	$ 4,957	$ 3,923
Current derivative assets	529	323
Regulatory assets (Note 7)	259	232
Taxes receivable	407	374
Other	710	406
Accounts receivable and other (Note 9)	6,862	5,258
Allowance for doubtful accounts receivable	$ 87	$ 70

INVENTORY (Details)

INVENTORY (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Inventory Disclosure [Abstract]
Natural gas	$ 953	$ 710
Crude oil	624	744
Other	93	82
Total	$ 1,670	$ 1,536

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 126,040	$ 118,450
Total accumulated depreciation	(25,973)	(23,879)
Property, plant and equipment, net	$ 100,067	94,571
Pipelines
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.80%
Total property, plant and equipment	$ 62,997	57,459
Facilities and equipment
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	3.10%
Total property, plant and equipment	$ 34,331	30,149
Land and right-of-way
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.30%
Total property, plant and equipment	$ 3,320	2,896
Gas mains, services and other
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.70%
Total property, plant and equipment	$ 13,606	12,813
Storage
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	2.40%
Total property, plant and equipment	$ 3,099	2,936
Wind turbines, solar panels and other
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	4.00%
Total property, plant and equipment	$ 4,912	4,877
Other
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	8.20%
Total property, plant and equipment	$ 1,507	1,558
Under construction
Property, Plant and Equipment [Line Items]
Weighted Average Depreciation Rate (percent)	0.00%
Total property, plant and equipment	$ 2,268	$ 5,762

PROPERTY, PLANT AND EQUIPMENT_2

PROPERTY, PLANT AND EQUIPMENT - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Depreciation expense	$ 3,500	$ 3,400	$ 3,000
Impairment loss			423
Access Northeast Project
Property, Plant and Equipment [Line Items]
Impairment loss			$ 105

VARIABLE INTEREST ENTITIES - Sc

VARIABLE INTEREST ENTITIES - Schedule of Assets and Liabilities of Consolidated VIEs (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Assets
Cash and cash equivalents	$ 286	$ 452
Restricted cash	34	38
Accounts receivable and other	6,862	5,258
Inventory	1,670	1,536
Current assets	8,959	7,350
Property, plant and equipment, net	100,067	94,571	$ 93,723
Long-term investments	13,324	13,818
Restricted long-term investments	630	553
Deferred amounts and other assets	8,613	8,446
Intangible assets, net	4,008	2,080
Total assets	168,864	160,276
Liabilities
Accounts payable and other	9,767	9,228
Other long-term liabilities	7,617	8,783
Deferred income taxes	11,689	10,332
Liabilities	105,496	95,913
Variable Interest Entity, Primary Beneficiary
Assets
Cash and cash equivalents	247	215
Restricted cash	4	1
Accounts receivable and other	99	65
Inventory	9	7
Current assets	359	288
Property, plant and equipment, net	3,052	3,201
Long-term investments	16	14
Restricted long-term investments	101	84
Deferred amounts and other assets	2	3
Intangible assets, net	108	115
Total assets	3,638	3,705
Liabilities
Accounts payable and other	84	52
Other long-term liabilities	182	175
Deferred income taxes	5	5
Liabilities	271	232
Net Assets	$ 3,367	$ 3,473

VARIABLE INTEREST ENTITIES - _2

VARIABLE INTEREST ENTITIES - Schedule of the Carrying Amount of Interest in VIEs (Details) - CAD ($) $ in Millions	Mar. 18, 2018	Dec. 31, 2021	Dec. 31, 2020
VARIABLE INTEREST ENTITY
Affiliate loan receivable		$ 954	$ 1,108
EIH S.a.r.l.
VARIABLE INTEREST ENTITY
Ownership interest in subsidiary (as a percent)	49.00%	49.00%
Variable Interest Entity, Not Primary Beneficiary
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		$ 1,054	1,351
Maximum Exposure to Loss		4,288	5,424
Variable Interest Entity, Not Primary Beneficiary | Aux Sable Liquid Products L.P.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		113	106
Maximum Exposure to Loss		195	187
Variable Interest Entity, Not Primary Beneficiary | Eolien Maritime France SAS
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		38	96
Maximum Exposure to Loss		664	949
Affiliate loan receivable		73	132
Variable Interest Entity, Not Primary Beneficiary | Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		54	100
Maximum Exposure to Loss		2,121	2,516
Affiliate loan receivable		807	904
Variable Interest Entity, Not Primary Beneficiary | PennEast Pipeline Company, LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE			116
Maximum Exposure to Loss			371
Variable Interest Entity, Not Primary Beneficiary | Rampion Offshore Wind Limited
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		450	599
Maximum Exposure to Loss		508	650
Variable Interest Entity, Not Primary Beneficiary | Vector Pipeline L.P.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		189	201
Maximum Exposure to Loss		374	390
Affiliate loan receivable		80	84
Credit facility provided		105	105
Variable Interest Entity, Not Primary Beneficiary | Other
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		210	133
Maximum Exposure to Loss		$ 426	$ 361

LONG-TERM INVESTMENTS - Schedul

LONG-TERM INVESTMENTS - Schedule of Long-Term Investments (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Oct. 31, 2021	Jun. 06, 2021	Mar. 18, 2021	Dec. 31, 2020
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)				25.50%
Total long-term investments	$ 13,324				$ 13,818
Noverco Preferred Shares
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)			38.90%
Noverco Preferred Shares | Preferred Shares | Gas Distribution and Storage
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	$ 0				567
MarEn Bakken Company LLC1 | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	75.00%
EQUITY INVESTMENTS	$ 1,728				1,795
MarEn Bakken Company LLC1 | Bakken Pipeline Investments, LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	49.00%
MarEn Bakken Company LLC1 | Bakken Pipeline System
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	27.60%
Gray Oak Holdings LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	65.00%
Gray Oak Holdings LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	35.00%
EQUITY INVESTMENTS	$ 469				502
Gray Oak Holdings LLC | Gray Oak Holdings LLC
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	22.80%
Seaway Crude Holdings LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	$ 2,634				2,668
Illinois Extension Pipeline Company, LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	65.00%
EQUITY INVESTMENTS	$ 593				623
Cactus II Pipeline, LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	20.00%	20.00%
EQUITY INVESTMENTS	$ 434				0
Other | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	33.30%
EQUITY INVESTMENTS	$ 2				4
Other | Liquids Pipelines
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	71				73
Other | Renewable Power Generation
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	93				74
Other | Eliminations and Other
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	$ 23				32
Other | Minimum | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	30.00%
Other | Minimum | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	12.00%
Other | Minimum | Eliminations and Other
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	42.70%
Other | Maximum | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	43.80%
Other | Maximum | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
Other | Maximum | Eliminations and Other
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
Other | Common Shares | Gas Distribution and Storage
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	$ 20				13
Other | Common Shares | Minimum | Gas Distribution and Storage
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	47.60%
Other | Common Shares | Maximum | Gas Distribution and Storage
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
Alliance Pipeline | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	$ 504				269
Aux Sable | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	$ 238				251
Aux Sable | Minimum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	42.70%
Aux Sable | Maximum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
DCP Midstream, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	$ 397				331
DCP Midstream, LLC | DCP Midstream, LP
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	56.50%
Gulfstream Natural Gas System, L.L.C. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	$ 1,180				1,175
Nexus Gas Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	$ 1,724				1,745
PennEast Pipeline Company, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	20.00%
EQUITY INVESTMENTS	$ 12				116
Sabal Trail Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	$ 1,464				1,510
Southeast Supply Header, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	$ 82				84
Steckman Ridge, LP | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	$ 88				90
Vector Pipeline Limited | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	60.00%
EQUITY INVESTMENTS	$ 189				201
Offshore - various joint ventures | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	$ 309				$ 338
Offshore - various joint ventures | Minimum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	22.00%
Offshore - various joint ventures | Maximum | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	74.30%
Noverco Preferred Shares | Common Shares | Gas Distribution and Storage
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	38.90%				38.90%
EQUITY INVESTMENTS	$ 0				$ 156
EIH S.a.r.l.
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)				49.00%
EIH S.a.r.l. | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	51.00%
EQUITY INVESTMENTS	$ 38				96
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII) | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	51.00%
EQUITY INVESTMENTS	$ 54				100
Rampion Offshore Wind Limited | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	24.90%
EQUITY INVESTMENTS	$ 450				599
NextBridge Infrastructure LP | Renewable Power Generation
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	25.00%
EQUITY INVESTMENTS	$ 186				122
Emerging Technologies and Other | Renewable Power Generation
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	32				32
Other long-term investments | Eliminations and Other
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	$ 310				$ 252
Bakken Pipeline Investments, LLC | Bakken Pipeline System
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	75.00%
Éolien Maritime France SAS
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)				50.00%
Saint-Nazaire
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)				25.50%
Fécamp
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)				17.90%
Calvados
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)				21.70%

LONG-TERM INVESTMENTS - Narrati

LONG-TERM INVESTMENTS - Narrative (Details) - CAD ($) $ in Millions	Dec. 30, 2021	Jun. 06, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Mar. 18, 2021
Schedule of Equity Method Investments [Line Items]
Goodwill of investee			$ 2,500	$ 2,400
Amortizable assets of investee			730	657
Dividends received from equity investments			2,200	2,100	$ 2,200
Ownership interest (as a percent)						25.50%
Impairment of equity investments			111	2,351	0
Loss from equity method investment			$ (1,711)	(1,136)	$ (1,503)
Noverco Preferred Shares
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)		38.90%
Equity method investment cash subject to purchase price adjustments		$ 1,100
Proceeds from sale of equity method investments	$ 1,100
Equity method investment, realized gain (loss) on disposal	$ 303
PennEast Pipeline Company, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)			20.00%
Impairment of equity investments			$ 111
Equity investment			12	$ 116
Steckman Ridge, LP
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)				50.00%
Impairment of equity investments				$ 221
Equity investment			88	$ 90
Southeast Supply Header L.L.C.
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)				50.00%
Impairment of equity investments				$ 394
Equity investment			$ 82	84
DCP Midstream, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)			50.00%
Impairment of equity investments				1,700
Equity investment			$ 397	$ 331
Loss from equity method investment			$ 324
Gas Distribution and Storage | Common Shares | Noverco Preferred Shares
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)			38.90%	38.90%
Equity investment			$ 0	$ 156

LONG-TERM INVESTMENTS - Summary

LONG-TERM INVESTMENTS - Summary of Combined Financial Information (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income statement information
Revenues	$ 12,470	$ 11,466	$ 10,948	$ 12,187	$ 10,008	$ 9,110	$ 7,956	$ 12,013	$ 47,071	$ 39,087	$ 50,069
Earnings									6,314	3,416	5,827
Earnings/(loss) attributable to controlling interests	1,933	$ 780	$ 1,484	$ 1,992	1,871	$ 1,084	$ 1,741	$ (1,333)	6,189	3,363	5,705
Balance sheet information
Current assets	8,959				7,350				8,959	7,350
Current liabilities	18,229				13,979				18,229	13,979
Noncontrolling interests	2,542				2,996				2,542	2,996
Unconsolidated equity method investments
Income statement information
Revenues									19,891	13,987	15,687
Operating expenses									16,514	12,223	13,153
Earnings									2,952	2,306	3,016
Earnings/(loss) attributable to controlling interests									1,711	1,136	$ 1,503
Balance sheet information
Current assets	3,581				3,136				3,581	3,136
Non-current assets	44,497				45,955				44,497	45,955
Current liabilities	3,678				3,539				3,678	3,539
Non-current liabilities	16,950				19,639				16,950	19,639
Noncontrolling interests	$ 3,786				$ 3,810				$ 3,786	$ 3,810

RESTRICTED LONG-TERM INVESTME_2

RESTRICTED LONG-TERM INVESTMENTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Assets Held-in-trust [Abstract]
Restricted long-term investments	$ 630	$ 553
Debt securities, available-for-sale, amortized cost	383	322
Future abandonment costs	$ 649	$ 578

INTANGIBLE ASSETS (Details)

INTANGIBLE ASSETS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
INTANGIBLE ASSETS
Cost	$ 5,535	$ 3,653
Accumulated Amortization	(1,527)	(1,573)
Net	4,008	2,080
Amortization expenses
Amortization expense for intangible assets	$ 348	$ 294	$ 296
Software
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	8.50%	10.50%
Cost	$ 2,532	$ 2,043
Accumulated Amortization	(215)	(1,299)
Net	$ 2,317	$ 744
Power purchase agreements
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.50%	4.50%
Cost	$ 63	$ 63
Accumulated Amortization	(21)	(18)
Net	$ 42	$ 45
Project agreement
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.00%	4.00%
Cost	$ 152	$ 153
Accumulated Amortization	(27)	(21)
Net	$ 125	$ 132
Customer relationships
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	12.00%	5.00%
Cost	$ 2,067	$ 724
Accumulated Amortization	(1,148)	(139)
Net	$ 919	$ 585
Other intangible assets
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	3.90%	2.70%
Cost	$ 475	$ 456
Accumulated Amortization	(116)	(96)
Net	$ 359	$ 360
Under development
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	0.00%	0.00%
Cost	$ 246	$ 214
Accumulated Amortization	0	0
Net	$ 246	$ 214

INTANGIBLE ASSETS - Narrative (

INTANGIBLE ASSETS - Narrative (Details) $ in Millions	Dec. 31, 2021CAD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2022	$ 492
2023	492
2024	492
2025	492
2026	$ 492

GOODWILL (Details)

GOODWILL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 32,688	$ 33,153
Foreign exchange and other	(200)	(487)
Acquisition	287	22
Goodwill, ending balance	32,775	32,688	$ 33,153
Goodwill [Abstract]
Goodwill, gross at end of period	34,400	34,300
Goodwill accumulated impairment	1,600	1,600
Goodwill related to acquisition	287	22
Goodwill on the acquisition	319	6	(254)
Moda Midstream Operating, LLC (Moda)
Goodwill [Roll Forward]
Acquisition	268
Goodwill [Abstract]
Goodwill related to acquisition	268
Liquids Pipelines
Goodwill [Roll Forward]
Goodwill, beginning balance	7,828	7,951
Foreign exchange and other	(55)	(123)
Acquisition	268	0
Goodwill, ending balance	8,041	7,828	7,951
Goodwill [Abstract]
Goodwill related to acquisition	268	0
Gas Transmission and Midstream
Goodwill [Roll Forward]
Goodwill, beginning balance	19,480	19,844
Foreign exchange and other	(145)	(364)
Acquisition	0	0
Goodwill, ending balance	19,335	19,480	19,844
Goodwill [Abstract]
Goodwill related to acquisition	0	0
Gas Distribution and Storage
Goodwill [Roll Forward]
Goodwill, beginning balance	5,378	5,356
Foreign exchange and other	0	0
Acquisition	19	22
Goodwill, ending balance	5,397	5,378	5,356
Goodwill [Abstract]
Goodwill related to acquisition	19	22
Energy Services
Goodwill [Roll Forward]
Goodwill, beginning balance	2	2
Foreign exchange and other	0	0
Acquisition	0	0
Goodwill, ending balance	2	2	$ 2
Goodwill [Abstract]
Goodwill related to acquisition	$ 0	$ 0

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Payables and Accruals [Abstract]
Trade payables and operating accrued liabilities	$ 4,470	$ 3,497
Dividends payable	1,773	1,728
Current deferred credits	853	978
Construction payables and contractor holdbacks	844	855
Current derivative liabilities	717	896
Taxes payable	478	622
Other	632	652
Accounts payable and other liabilities	$ 9,767	$ 9,228

DEBT - Schedule of Debt (Detail

DEBT - Schedule of Debt (Details) $ in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)
DEBT
Total debt	$ 75,640		$ 66,897
Fair value adjustment	667		750
Other	(363)		(344)
Current maturities	(6,164)		(2,957)
Short-term borrowings	(1,515)		(1,121)
Long-term debt	67,961		62,819
Long-term debt	$ 36,000	$ 31	$ 35,000	$ 24
Weighted average interest rate (as a percent)	0.50%	0.50%	0.30%	0.30%
US dollar senior notes | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	3.20%	3.20%
Total debt	$ 10,992		$ 8,536
Medium-term notes | Enbridge Gas Inc.
DEBT
Weighted average interest rate (percent)	3.80%	3.80%
Total debt	$ 9,010		8,485
Medium-term notes | Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (percent)	4.00%	4.00%
Total debt	$ 5,575		4,775
Carrying value	$ 100
Medium-term notes | Westcoast Energy Inc.
DEBT
Weighted average interest rate (percent)	4.50%	4.50%
Total debt	$ 1,475		1,625
Medium-term notes | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	3.90%	3.90%
Total debt	$ 8,123		8,323
Sustainability-Linked Bonds | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	1.10%	1.10%
Total debt	$ 2,363		0
Fixed-to-fixed subordinated term notes | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	5.80%	5.80%
Total debt	$ 1,263		1,274
Term of fixed rate	10 years
Fixed-to-floating rate subordinated term notes | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	5.80%	5.80%
Total debt	$ 6,442		6,477
Term of fixed rate	10 years
Floating rate notes | Enbridge Inc.
DEBT
Weighted average interest rate (percent)
Total debt	$ 1,579		956
Commercial paper and credit facility draws | Enbridge (U.S.) Inc.
DEBT
Weighted average interest rate (percent)	0.40%	0.40%
Total debt	$ 4,845		492
Commercial paper and credit facility draws | Enbridge Gas Inc.
DEBT
Weighted average interest rate (percent)	0.50%	0.50%
Total debt	$ 1,515		1,121
Commercial paper and credit facility draws | Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (percent)	0.70%	0.70%
Total debt	$ 667		1,278
Commercial paper and credit facility draws | Enbridge Inc.
DEBT
Weighted average interest rate (percent)	1.00%	1.00%
Total debt	$ 7,837		8,719
Other | Enbridge (U.S.) Inc.
DEBT
Total debt	7		7
Other | Enbridge Inc.
DEBT
Total debt	$ 5		5
Senior notes | Enbridge Energy Partners, L.P.
DEBT
Weighted average interest rate (percent)	6.50%	6.50%
Total debt	$ 3,095		3,886
Senior notes | Enbridge Pipelines (Southern Lights) L.L.C.
DEBT
Weighted average interest rate (percent)	4.00%	4.00%
Total debt	$ 949		1,038
Senior notes | Enbridge Southern Lights LP
DEBT
Weighted average interest rate (percent)	4.00%	4.00%
Total debt	$ 240		257
Senior notes | Spectra Energy Capital, LLC
DEBT
Weighted average interest rate (percent)	7.00%	7.00%
Total debt	$ 218		220
Senior notes | Spectra Energy Partners, LP
DEBT
Weighted average interest rate (percent)	3.90%	3.90%
Total debt	$ 8,451		8,332
Debentures | Enbridge Gas Inc.
DEBT
Weighted average interest rate (percent)	9.10%	9.10%
Total debt	$ 210		210
Debentures | Enbridge Pipelines Inc.
DEBT
Weighted average interest rate (percent)	8.20%	8.20%
Total debt	$ 200		200
Debentures | Westcoast Energy Inc.
DEBT
Weighted average interest rate (percent)	8.10%	8.10%
Total debt	$ 275		$ 275
LIBOR | Floating rate notes | Enbridge Inc.
DEBT
Basis spread on variable rate (as a percent)	0.50%
US Treasury Rate | Fixed-to-fixed subordinated term notes | Enbridge Inc. | From years 10 to 30
DEBT
Basis spread on variable rate (as a percent)	5.31%
US Treasury Rate | Fixed-to-fixed subordinated term notes | Enbridge Inc. | From years 30 to 60
DEBT
Basis spread on variable rate (as a percent)	6.06%
SOFR | Floating rate notes | Enbridge Inc.
DEBT
Basis spread on variable rate (as a percent)	0.40%

DEBT - Schedule of Committed Cr

DEBT - Schedule of Committed Credit Facilities (Details) $ in Millions	Dec. 31, 2021CAD ($)
Committed credit facilities
DEBT
Total Facilities	$ 21,085
Draws	14,864
Available	6,221
Enbridge (U.S.) Inc.
DEBT
Total Facilities	6,948
Draws	4,845
Available	2,103
Enbridge Pipelines Inc.
DEBT
Total Facilities	3,000
Draws	667
Available	2,333
Union Gas Limited
DEBT
Total Facilities	2,000
Draws	1,515
Available	485
Enbridge Inc.
DEBT
Total Facilities	9,137
Draws	7,837
Available	$ 1,300

DEBT - Credit Facilities (Narra

DEBT - Credit Facilities (Narrative) (Details) $ in Millions

Feb. 10, 2022CAD ($)

Jan. 19, 2022CAD ($)

Jul. 23, 2021CAD ($)

Feb. 25, 2021CAD ($)loan

Feb. 10, 2021CAD ($)

Dec. 31, 2021CAD ($)

Dec. 31, 2021USD ($)

Dec. 31, 2021USD ($)

Oct. 31, 2021

Sep. 30, 2021

Jun. 30, 2021

May 31, 2021

Mar. 31, 2021

Feb. 28, 2021

Dec. 31, 2020CAD ($)

Line of Credit Facility [Line Items]

Principal amount

$ 3,200,000,000

$ 3,900

Long-term debt

67,961,000,000

$ 62,819,000,000

Extinguishment of debt

1,100,000,000

$ 914

Term Loan

Line of Credit Facility [Line Items]

Extinguishment of debt

$ 500,000,000

Number of term loans repaid | loan

2

Commercial paper and credit facility draws

Line of Credit Facility [Line Items]

Long-term debt

11,300,000,000

9,900,000,000

Enbridge Gas Inc. | 2.35% medium-term notes due September 2031

Line of Credit Facility [Line Items]

Principal amount

475,000,000

Interest rate (percent)

2.35%

Enbridge Gas Inc. | 3.20% medium-term notes due September 2051

Line of Credit Facility [Line Items]

Principal amount

425,000,000

Interest rate (percent)

3.20%

Enbridge Gas Inc. | 2.76% medium-term notes

Line of Credit Facility [Line Items]

Interest rate (percent)

276.00%

Extinguishment of debt

$ 200,000,000

Enbridge Gas Inc. | 4.77% medium-term notes

Line of Credit Facility [Line Items]

Interest rate (percent)

477.00%

477.00%

Extinguishment of debt

$ 175,000,000

Enbridge Pipelines Inc.

Line of Credit Facility [Line Items]

Credit facility capacity

3,000,000,000

Unutilized credit facility

2,333,000,000

Enbridge Pipelines Inc. | 2.82% medium-term notes due May 2031

Line of Credit Facility [Line Items]

Principal amount

400,000,000

Interest rate (percent)

2.82%

Enbridge Pipelines Inc. | 4.20% medium-term notes due May 2051

Line of Credit Facility [Line Items]

Principal amount

$ 400,000,000

Interest rate (percent)

4.20%

Spectra Energy Partners, LP | 2.50% senior notes due September 2031

Line of Credit Facility [Line Items]

Principal amount

$ 400

Interest rate (percent)

2.50%

Spectra Energy Partners, LP | 4.60% senior notes

Line of Credit Facility [Line Items]

Extinguishment of debt

250

Enbridge Energy Partners, L.P. | 4.20% senior notes

Line of Credit Facility [Line Items]

Interest rate (percent)

420.00%

Extinguishment of debt

600

Enbridge Pipelines (Southern Lights) L.L.C. | 3.98% senior notes

Line of Credit Facility [Line Items]

Interest rate (percent)

398.00%

398.00%

398.00%

Extinguishment of debt

$ 64

Enbridge Southern Lights LP | 4.01% senior notes

Line of Credit Facility [Line Items]

Interest rate (percent)

401.00%

401.00%

401.00%

Extinguishment of debt

$ 16,000,000

Enbridge Inc.

Line of Credit Facility [Line Items]

Credit facility capacity

9,137,000,000

Unutilized credit facility

1,300,000,000

Enbridge Inc. | 2.50% Sustainability-linked senior notes due August 2033

Line of Credit Facility [Line Items]

Principal amount

$ 1,000

Interest rate (percent)

2.50%

Enbridge Inc. | 3.40% senior notes due August 2051

Line of Credit Facility [Line Items]

Principal amount

500

Interest rate (percent)

3.40%

Enbridge Inc. | 3.10% Sustainability-linked medium-term notes due September 2033

Line of Credit Facility [Line Items]

Principal amount

1,100,000,000

Interest rate (percent)

3.10%

Enbridge Inc. | 4.10% medium-term notes due September 2051

Line of Credit Facility [Line Items]

Principal amount

400,000,000

Interest rate (percent)

4.10%

Enbridge Inc. | 0.55% senior notes due October 2023

Line of Credit Facility [Line Items]

Principal amount

500

Interest rate (percent)

0.55%

Enbridge Inc. | 1.60% senior notes due October 2026

Line of Credit Facility [Line Items]

Principal amount

500

Interest rate (percent)

1.60%

Enbridge Inc. | 3.40% senior notes due August 2051

Line of Credit Facility [Line Items]

Principal amount

$ 500

Interest rate (percent)

3.40%

Enbridge Inc. | 4.26% medium-term notes

Line of Credit Facility [Line Items]

Interest rate (percent)

426.00%

Extinguishment of debt

200,000,000

Enbridge Inc. | 3.16% medium-term notes

Line of Credit Facility [Line Items]

Interest rate (percent)

316.00%

Extinguishment of debt

400,000,000

Spectra Energy Partners, LP | 4.60% senior notes

Line of Credit Facility [Line Items]

Interest rate (percent)

460.00%

Uncommitted credit facilities

Line of Credit Facility [Line Items]

Credit facility capacity

1,300,000,000

849,000,000

Unutilized credit facility

$ 854,000,000

$ 533,000,000

Weighted average standby fee (as a percent)

0.10%

0.10%

Revolving Credit Facility | Sustainability-linked Credit Facility

Line of Credit Facility [Line Items]

Credit facility capacity

$ 1,000,000,000

Term of credit facility

3 years

Revolving Credit Facility | Syndicated Credit Facility

Line of Credit Facility [Line Items]

Term of credit facility

1 year

Extinguishment of debt

$ 3,000,000,000

Revolving Credit Facility | Five-Year Credit Facilities

Line of Credit Facility [Line Items]

Credit facility capacity

$ 8,000,000,000

Term of credit facility

5 years

Revolving Credit Facility | 364-Day Extendible Credit Facilities

Line of Credit Facility [Line Items]

Credit facility capacity

$ 10,000,000,000

Term of credit facility

364 days

Maturity period

1 year

Subsequent Event

Line of Credit Facility [Line Items]

Credit facility capacity

$ 1,000,000,000

Subsequent Event | 10-year Fixed-To-Fixed Subordinated Notes | Subordinated Debt

Line of Credit Facility [Line Items]

Term of credit facility

10 years

Principal amount

$ 750,000,000

Subsequent Event | Revolving Credit Facility | Sustainability-linked Credit Facility

Line of Credit Facility [Line Items]

Credit facility capacity

$ 1,000,000,000

Term of credit facility

3 years

DEBT - Schedule of Long-term De

DEBT - Schedule of Long-term Debt Issuances (Details) - 12 months ended Dec. 31, 2021 $ in Millions, $ in Millions	CAD ($)	USD ($)
Debt Instrument [Line Items]
Principal amount	$ 3,200	$ 3,900
Enbridge Gas Inc. | 2.35% medium-term notes due September 2031
Debt Instrument [Line Items]
Principal amount	475
Enbridge Gas Inc. | 3.20% medium-term notes due September 2051
Debt Instrument [Line Items]
Principal amount	425
Enbridge Pipelines Inc. | 2.82% medium-term notes due May 2031
Debt Instrument [Line Items]
Principal amount	400
Enbridge Pipelines Inc. | 4.20% medium-term notes due May 2051
Debt Instrument [Line Items]
Principal amount	400
Spectra Energy Partners, LP | 2.50% senior notes due September 2031
Debt Instrument [Line Items]
Principal amount		400
Enbridge Inc. | Floating rate senior-notes due February 20231
Debt Instrument [Line Items]
Principal amount		500
Enbridge Inc. | 2.50% Sustainability-linked senior notes due August 2033
Debt Instrument [Line Items]
Principal amount		1,000
Enbridge Inc. | 3.40% senior notes due August 2051
Debt Instrument [Line Items]
Principal amount		500
Enbridge Inc. | 3.10% Sustainability-linked medium-term notes due September 2033
Debt Instrument [Line Items]
Principal amount	1,100
Enbridge Inc. | 4.10% medium-term notes due September 2051
Debt Instrument [Line Items]
Principal amount	$ 400
Enbridge Inc. | 0.55% senior notes due October 2023
Debt Instrument [Line Items]
Principal amount		500
Enbridge Inc. | 1.60% senior notes due October 2026
Debt Instrument [Line Items]
Principal amount		500
Enbridge Inc. | 3.40% senior notes due August 2051
Debt Instrument [Line Items]
Principal amount		$ 500
Enbridge Inc. | SOFR | Floating rate senior-notes due February 20231
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	0.40%

DEBT - Schedule of Long-Term _2

DEBT - Schedule of Long-Term Debt Repayments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Oct. 31, 2021	Jun. 30, 2021	May 31, 2021	Mar. 31, 2021	Feb. 28, 2021
Debt Instrument [Line Items]
Extinguishment of debt	$ 1,100	$ 914
Enbridge Energy Partners, L.P. | 4.20% senior notes
Debt Instrument [Line Items]
Extinguishment of debt		$ 600
Interest rate (percent)				420.00%
Enbridge Gas Inc. | 2.76% medium-term notes
Debt Instrument [Line Items]
Extinguishment of debt	200
Interest rate (percent)					276.00%
Enbridge Gas Inc. | 4.77% medium-term notes
Debt Instrument [Line Items]
Extinguishment of debt	$ 175
Interest rate (percent)	477.00%	477.00%
Enbridge Pipelines (Southern Lights) L.L.C. | 3.98% senior notes
Debt Instrument [Line Items]
Extinguishment of debt		$ 64
Interest rate (percent)	398.00%	398.00%		398.00%
Enbridge Southern Lights LP | 4.01% senior notes
Debt Instrument [Line Items]
Extinguishment of debt	$ 16
Interest rate (percent)	401.00%	401.00%		401.00%
Spectra Energy Partners, LP | 4.60% senior notes
Debt Instrument [Line Items]
Extinguishment of debt		$ 250
Westcoast Energy Inc. | 3.88% medium-term notes
Debt Instrument [Line Items]
Extinguishment of debt	$ 150
Interest rate (percent)			388.00%
Enbridge Inc. | 4.26% medium-term notes
Debt Instrument [Line Items]
Extinguishment of debt	200
Interest rate (percent)							426.00%
Enbridge Inc. | 3.16% medium-term notes
Debt Instrument [Line Items]
Extinguishment of debt	$ 400
Interest rate (percent)						316.00%
Spectra Energy Partners, LP | 4.60% senior notes
Debt Instrument [Line Items]
Interest rate (percent)						460.00%

DEBT - Schedule of Interest Exp

DEBT - Schedule of Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
DEBT
Capitalized interest	$ (215)	$ (192)	$ (326)
Total interest expense	2,655	2,790	2,663
Spectra Energy Capital, LLC
DEBT
Amortization of fair value adjustment	(50)	(54)	(67)
Debentures and term notes
DEBT
Interest expense on debt	2,850	2,913	2,783
Commercial paper and credit facility draws
DEBT
Interest expense on debt	$ 70	$ 123	$ 273

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of movements in the Company's ARO
Obligations at beginning of year	$ 496	$ 520
Liabilities disposed	0	0
Liabilities incurred	0	0
Liabilities settled	(67)	(30)
Change in estimate and other	70	0
Foreign currency translation adjustment	(3)	(6)
Accretion expense	6	12
Obligations at end of year	502	496
Accounts payable and other	160	56
Other long-term liabilities	342	440
Asset retirement obligations	$ 502	$ 496
Minimum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	0.90%	1.80%
Maximum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	9.00%	9.00%

NONCONTROLLING INTERESTS - NONC

NONCONTROLLING INTERESTS - NONCONTROLLING (Details) - CAD ($) shares in Millions, $ in Millions	Dec. 31, 2021	Dec. 31, 2020
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 2,542	$ 2,996
Algonquin Gas Transmission LLC
NONCONTROLLING INTERESTS
Noncontrolling interests	377	384
Maritimes and Northeast Pipeline
NONCONTROLLING INTERESTS
Noncontrolling interests	546	558
Renewable energy assets
NONCONTROLLING INTERESTS
Noncontrolling interests	1,503	1,646
Westcoast Energy Inc.
NONCONTROLLING INTERESTS
Noncontrolling interests	$ 116	$ 408
Westcoast Energy Inc. | Cumulative redeemable preferred stock | Preferred Shares
NONCONTROLLING INTERESTS
Number of redeemable preferred shares held by noncontrolling owners (in shares)	0	12

NONCONTROLLING INTERESTS - NO_2

NONCONTROLLING INTERESTS - NONCONTROLLING INFORMATION (Details) - CAD ($) $ / shares in Units, $ in Millions	Oct. 15, 2021	Jan. 15, 2021	Mar. 20, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
NONCONTROLLING INTERESTS
Proceeds from issuance of preferred stock			$ 300
Decrease in noncontrolling interests						$ 300
Par value of redeemable interest				$ 7,747	$ 7,747
Accounts payable and other				9,767	9,228
Redemption of preferred shares held by subsidiary				$ 415	0	$ 300
Preferred Shares
NONCONTROLLING INTERESTS
Dividend payment			$ 4
Preference Shares, Series 7 | Preferred Shares
NONCONTROLLING INTERESTS
Dividend rate (percent)			5.50%	4.45%
Redemption price (in dollars per shares)			$ 25	$ 25
Series 8 Preferred Stock | Preferred Shares
NONCONTROLLING INTERESTS
Dividend rate (percent)			5.60%
Redemption price (in dollars per shares)			$ 25
Series10 Preferred Stock | Westcoast Energy Inc. | Preferred Shares
NONCONTROLLING INTERESTS
Temporary equity, redemption, minimum term (in years)		5 years
Par value of redeemable interest		$ 115			$ 115
Series12 Preferred Stock | Westcoast Energy Inc. | Preferred Shares
NONCONTROLLING INTERESTS
Temporary equity, redemption, minimum term (in years)	5 years
Par value of redeemable interest	$ 300
Decrease in noncontrolling interest				$ 293

SHARE CAPITAL - COMMON SHARES (

SHARE CAPITAL - COMMON SHARES (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Common Shares
Balance at beginning of period (in shares)	2,026
Balance at end of period (in shares)	2,026	2,026
Common Shares
Common Shares
Balance at beginning of period (in shares)	2,026	2,025	2,022
Balance at beginning of period, Amount	$ 64,768	$ 64,746	$ 64,677
Shares issued on exercise of stock options (in shares)	0	1	3
Shares issued on exercise of stock options	$ 31	$ 22	$ 69
Balance at end of period (in shares)	2,026	2,026	2,025
Balance at end of period, Amount	$ 64,799	$ 64,768	$ 64,746

SHARE CAPITAL - PREFERRED SHARE

SHARE CAPITAL - PREFERRED SHARES (Details) $ / shares in Units, shares in Millions, $ in Millions	Dec. 01, 2021$ / shares	Sep. 01, 2021$ / shares	Jun. 01, 2021$ / shares	Mar. 01, 2021$ / shares	Feb. 28, 2021$ / shares	Mar. 20, 2019$ / shares	Dec. 31, 2021CAD ($)$ / sharesshares	Dec. 31, 2021CAD ($)$ / shares$ / sharesshares	Dec. 31, 2020CAD ($)shares	Dec. 31, 2019CAD ($)shares	Dec. 31, 2021$ / shares
Preferred Shares
Share Capital
Preferred stock, value, outstanding | $							$ 7,747	$ 7,747	$ 7,747	$ 7,747
Issuance costs | $							$ (155)		$ (155)	$ (155)
Recurring anniversary period following the redemption option date, at which the entity may redeem preferred shares							5 years
Stock split conversion ratio							1
Quarterly floating rate cumulative dividends per share calculation, base multiplier (in dollars per share) | (per share)							$ 25	$ 25
Preference Shares, Series A | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							5	5	5	5
Preferred stock, value, outstanding | $							$ 125	$ 125	$ 125	$ 125
Initial Yield (as a percent)							5.50%
Yearly dividend per share (in dollars per share)							$ 1.37500
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series B | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							18	18	18	18
Preferred stock, value, outstanding | $							$ 457	$ 457	$ 457	$ 457
Initial Yield (as a percent)							3.42%
Yearly dividend per share (in dollars per share)							$ 0.85360
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series C
Share Capital
Yearly dividend per share (in dollars per share)	$ 0.15719	$ 0.16081	$ 0.15753	$ 0.15501	$ 0.15349
Preference Shares, Series C | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							2	2	2	2
Preferred stock, value, outstanding | $							$ 43	$ 43	$ 43	$ 43
Yearly dividend per share (in dollars per share)							$ 0
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.40%
Preference Shares, Series C | US Treasury Rate | Preferred Shares
Share Capital
Initial yield, spread on variable rate (percent)							2.40%	2.40%
Preference Shares, Series D | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							18	18	18	18
Preferred stock, value, outstanding | $							$ 450	$ 450	$ 450	$ 450
Initial Yield (as a percent)							4.46%
Yearly dividend per share (in dollars per share)							$ 1.11500
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series F | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							20	20	20	20
Preferred stock, value, outstanding | $							$ 500	$ 500	$ 500	$ 500
Initial Yield (as a percent)							4.69%
Yearly dividend per share (in dollars per share)							$ 1.17224
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series H | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							14	14	14	14
Preferred stock, value, outstanding | $							$ 350	$ 350	$ 350	$ 350
Initial Yield (as a percent)							4.38%
Yearly dividend per share (in dollars per share)							$ 1.09400
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series J | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							8	8	8	8
Preferred stock, value, outstanding | $							$ 199	$ 199	$ 199	$ 199
Initial Yield (as a percent)							4.89%
Yearly dividend per share (in dollars per share)								$ 1.22160
Per Share Base Redemption Value (in dollars per shares)											$ 25
Preference Shares, Series L | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							16	16	16	16
Preferred stock, value, outstanding | $							$ 411	$ 411	$ 411	$ 411
Initial Yield (as a percent)							4.96%
Yearly dividend per share (in dollars per share)								$ 1.23972
Per Share Base Redemption Value (in dollars per shares)											25
Preference Shares, Series N | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							18	18	18	18
Preferred stock, value, outstanding | $							$ 450	$ 450	$ 450	$ 450
Initial Yield (as a percent)							5.09%
Yearly dividend per share (in dollars per share)							$ 1.27152
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series P | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							16	16	16	16
Preferred stock, value, outstanding | $							$ 400	$ 400	$ 400	$ 400
Initial Yield (as a percent)							4.38%
Yearly dividend per share (in dollars per share)							$ 1.09476
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series R | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							16	16	16	16
Preferred stock, value, outstanding | $							$ 400	$ 400	$ 400	$ 400
Initial Yield (as a percent)							4.07%
Yearly dividend per share (in dollars per share)							$ 1.01825
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series 1 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							16	16	16	16
Preferred stock, value, outstanding | $							$ 411	$ 411	$ 411	$ 411
Initial Yield (as a percent)							5.95%
Yearly dividend per share (in dollars per share)								$ 1.48728
Per Share Base Redemption Value (in dollars per shares)											25
Preference Shares, Series 3 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							24	24	24	24
Preferred stock, value, outstanding | $							$ 600	$ 600	$ 600	$ 600
Initial Yield (as a percent)							3.74%
Yearly dividend per share (in dollars per share)							$ 0.93425
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series 5 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							8	8	8	8
Preferred stock, value, outstanding | $							$ 206	$ 206	$ 206	$ 206
Initial Yield (as a percent)							5.38%
Yearly dividend per share (in dollars per share)								$ 1.34383
Per Share Base Redemption Value (in dollars per shares)											$ 25
Preference Shares, Series 7 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							10	10	10	10
Preferred stock, value, outstanding | $							$ 250	$ 250	$ 250	$ 250
Initial Yield (as a percent)						5.50%	4.45%
Yearly dividend per share (in dollars per share)							$ 1.11224
Per Share Base Redemption Value (in dollars per shares)						$ 25	$ 25	$ 25
Preference Shares, Series 9 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							11	11	11	11
Preferred stock, value, outstanding | $							$ 275	$ 275	$ 275	$ 275
Initial Yield (as a percent)							4.10%
Yearly dividend per share (in dollars per share)							$ 1.02424
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series 11 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							20	20	20	20
Preferred stock, value, outstanding | $							$ 500	$ 500	$ 500	$ 500
Initial Yield (as a percent)							3.94%
Yearly dividend per share (in dollars per share)							$ 0.98452
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series 13 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							14	14	14	14
Preferred stock, value, outstanding | $							$ 350	$ 350	$ 350	$ 350
Initial Yield (as a percent)							3.04%
Yearly dividend per share (in dollars per share)							$ 0.76076
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series 15 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							11	11	11	11
Preferred stock, value, outstanding | $							$ 275	$ 275	$ 275	$ 275
Initial Yield (as a percent)							2.98%
Yearly dividend per share (in dollars per share)							$ 0.74576
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Preference Shares, Series 17 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							30	30	30	30
Preferred stock, value, outstanding | $							$ 750	$ 750	$ 750	$ 750
Initial Yield (as a percent)							5.15%
Yearly dividend per share (in dollars per share)							$ 1.28750
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Minimum fixed dividend rate upon reset (as a percent)							5.15%
Preference Shares, Series 19 | Preferred Shares
Share Capital
Preferred stock, shares outstanding (in shares) | shares							20	20	20	20
Preferred stock, value, outstanding | $							$ 500	$ 500	$ 500	$ 500
Initial Yield (as a percent)							4.90%
Yearly dividend per share (in dollars per share)							$ 1.22500
Per Share Base Redemption Value (in dollars per shares)							$ 25	$ 25
Minimum fixed dividend rate upon reset (as a percent)							4.90%
Preferred Stock Excluding Series | Preferred Shares
Share Capital
Reset term of fixed dividend rate							5 years
Preference Shares, Series E | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.40%
Series G Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.50%
Series I Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.10%
Series O Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.70%
Series Q Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.50%
Series S Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.50%
Series 4 Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.40%
Series 8 Preferred Stock | Preferred Shares
Share Capital
Initial Yield (as a percent)						5.60%
Per Share Base Redemption Value (in dollars per shares)						$ 25
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.60%
Series10 Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.70%
Series12 Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.60%
Series14 Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.70%
Series16 Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							2.70%
Series18 Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							4.10%
Series 20 Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)							3.20%
Series K Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)							3.10%
Series M Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)							3.20%
Series 2 Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)							3.10%
Series 6 Preferred Stock | Preferred Shares
Share Capital
Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)							2.80%

SHARE CAPITAL - PLANS (Details)

SHARE CAPITAL - PLANS (Details)	Dec. 31, 2021
Equity [Abstract]
Minimum outstanding common shares required to be acquired to exercise the Shareholder Rights Plan (as a percent)	20.00%
Discount to the market price available to each rights holder, other than the acquiring person and related parties, under the Shareholder Rights Plan (as a percent)	50.00%

STOCK OPTION AND STOCK UNIT P_3

STOCK OPTION AND STOCK UNIT PLANS - STOCK OPTION ACTIVITY (Details) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)compensationPlan$ / sharesshares	Dec. 31, 2020CAD ($)$ / sharesshares	Dec. 31, 2019CAD ($)
STOCK OPTION AND STOCK UNIT PLANS
Number of long-term incentive compensation plans | compensationPlan	3
Compensation expense	$ 157	$ 145	$ 117
INCENTIVE STOCK OPTIONS
STOCK OPTION AND STOCK UNIT PLANS
Compensation expense	$ 16	$ 24	32
Vesting period	4 years
Expiration term	10 years
Number
Options outstanding at beginning of year (in shares) | shares	35,494
Options granted (in shares) | shares	4,072
Options exercised (in shares) | shares	(4,142)
Options cancelled or expired (in shares) | shares	(1,407)
Options outstanding at end of year (in shares) | shares	34,017	35,494
Options vested at end of year (in shares) | shares	22,029
Weighted Average Exercise Price
Options outstanding at beginning of year (in dollars per share) | $ / shares	$ 48.65
Options granted (in dollars per share) | $ / shares	43.86
Options exercised (in dollars per share) | $ / shares	41.85
Options cancelled or expired (in dollars per share) | $ / shares	50.74
Options outstanding at end of year (in dollars per share) | $ / shares	49.28	$ 48.65
Options vested at end of year (in dollars per share) | $ / shares	$ 49.84
Weighted Average Remaining Contractual Life (years)
Options outstanding at end of year	5 years 8 months 12 days
Options vested at end of year	4 years 6 months
Aggregate Intrinsic Value
Options outstanding at end of year	$ 128
Options vested at end of year	64
Stock options, additional disclosures
Total intrinsic value of awards exercised	24	$ 13	58
Cash received on exercise of awards	2	4	1
Total fair value of options vested	$ 25	$ 30	$ 32

STOCK OPTION AND STOCK UNIT P_4

STOCK OPTION AND STOCK UNIT PLANS - WEIGHTED AVERAGE ASSUMPTIONS (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)$ / shares	Dec. 31, 2020CAD ($)$ / shares	Dec. 31, 2019CAD ($)$ / shares	Dec. 31, 2021$ / shares	Dec. 31, 2020$ / shares	Dec. 31, 2019$ / shares
Weighted average assumptions used to determine the fair value of options
Compensation expense | $	$ 157	$ 145	$ 117
INCENTIVE STOCK OPTIONS
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares	$ 4.10	$ 4.01	$ 4.37
Expected option term (in years)	6 years	6 years	5 years
Expected volatility (as a percent)	25.50%	18.30%	19.90%
Expected dividend yield (as a percent)	7.60%	5.90%	6.10%
Risk-free interest rate (as a percent)	0.70%	1.30%	2.00%
Expected option term - historical exercise practice	6 years
Compensation expense | $	$ 16	$ 24	$ 32
Unrecognized compensation cost related to non-vested share-based compensation arrangements granted | $	$ 11
Weighted average period over which compensation cost is expected to be recognized	2 years
INCENTIVE STOCK OPTIONS | Canadian employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares	$ 3.91	$ 3.75	$ 4.04
INCENTIVE STOCK OPTIONS | United States employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares				$ 3.65	$ 3.62	$ 4.09
INCENTIVE STOCK OPTIONS | Retirement-eligible employees
Weighted average assumptions used to determine the fair value of options
Expected option term (in years)	5 years

STOCK OPTION AND STOCK UNIT P_5

STOCK OPTION AND STOCK UNIT PLANS - PSUs AND RSUs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)shares	Dec. 31, 2020CAD ($)shares	Dec. 31, 2019CAD ($)
Stock units, additional disclosures
Compensation expense | $	$ 157	$ 145	$ 117
Performance Stock Units (PSUs)
STOCK OPTION AND STOCK UNIT PLANS
Performance / maturity period	3 years
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards	20 days
Performance multiplier	0.5	0.5	1.3
Number
Units outstanding at beginning of year (in shares)	3,056,000
Units granted (in shares)	1,895,000
Units cancelled (in shares)	(76,000)
Units matured (in shares)	(1,664,000)
Dividend reinvestment (in shares)	218,000
Units outstanding at end of year (in shares)	3,429,000	3,056,000
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year 1 month 6 days
Aggregate Intrinsic Value
Units outstanding at end of year | $	$ 181
Stock units, additional disclosures
Total amount paid | $	70	$ 14	$ 19
Compensation expense | $	56	$ 76	40
Unrecognized compensation expense related to non-vested units granted | $	$ 31
Weighted average period over which compensation cost is expected to be recognized	2 years
Restricted Stock Units (RSU)
STOCK OPTION AND STOCK UNIT PLANS
Performance / maturity period	3 years
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards	20 days
Number
Units outstanding at beginning of year (in shares)	2,453,000
Units granted (in shares)	1,514,000
Units cancelled (in shares)	(75,000)
Units matured (in shares)	(1,433,000)
Dividend reinvestment (in shares)	246,000
Units outstanding at end of year (in shares)	2,705,000	2,453,000
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year 1 month 6 days
Aggregate Intrinsic Value
Units outstanding at end of year | $	$ 129
Stock units, additional disclosures
Total amount paid | $	72	$ 27	34
Compensation expense | $	85	$ 44	$ 41
Unrecognized compensation expense related to non-vested units granted | $	$ 62
Weighted average period over which compensation cost is expected to be recognized	2 years
Minimum | Performance Stock Units (PSUs)
STOCK OPTION AND STOCK UNIT PLANS
Performance multiplier	0
Maximum | Performance Stock Units (PSUs)
STOCK OPTION AND STOCK UNIT PLANS
Performance multiplier	2

COMPONENTS OF ACCUMULATED OTH_3

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Components of accumulated other comprehensive loss
Balance at beginning of year	$ 64,363	$ 69,407
Other comprehensive income/(loss) retained in AOCI	298	(1,522)	$ (3,296)
Changes in AOCI
Other	0		48
Other comprehensive (income)/loss reclassified to earnings	564	(1,249)	(3,121)
Income tax on amounts retained in AOCI	(187)	182	164
Income tax on amounts reclassified to earnings	(72)	(62)	(35)
Tax impact	(259)	120	129
Balance at end of year	63,368	64,363	69,407
Interest rate contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	296	253	157
Commodity contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	1		(1)
Forward exchange contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	5	5	5
Other contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	2	(2)	(3)
Equity investment disposal
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	0
Cash Flow Hedges
Components of accumulated other comprehensive loss
Balance at beginning of year	(1,326)	(1,073)	(770)
Other comprehensive income/(loss) retained in AOCI	238	(591)	(599)
Changes in AOCI
Other	17		0
Other comprehensive (income)/loss reclassified to earnings	559	(335)	(441)
Income tax on amounts retained in AOCI	(61)	140	169
Income tax on amounts reclassified to earnings	(69)	(58)	(31)
Tax impact	(130)	82	138
Balance at end of year	(897)	(1,326)	(1,073)
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	296	253	157
Cash Flow Hedges | Commodity contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	1		(1)
Cash Flow Hedges | Forward exchange contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	5	5	5
Cash Flow Hedges | Other contracts
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	2	(2)	(3)
Excluded Components of Fair Value Hedges
Components of accumulated other comprehensive loss
Balance at beginning of year	5	0
Other comprehensive income/(loss) retained in AOCI	(5)	5
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(5)	5
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0	0
Tax impact	0	0
Balance at end of year	0	5	0
Net Investment Hedges
Components of accumulated other comprehensive loss
Balance at beginning of year	(215)	(317)	(598)
Other comprehensive income/(loss) retained in AOCI	49	115	320
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	49	115	320
Income tax on amounts retained in AOCI	0	(13)	(39)
Income tax on amounts reclassified to earnings	0	0
Tax impact	0	(13)	(39)
Balance at end of year	(166)	(215)	(317)
Cumulative Translation Adjustment
Components of accumulated other comprehensive loss
Balance at beginning of year	568	1,396	4,323
Other comprehensive income/(loss) retained in AOCI	(492)	(828)	(2,927)
Changes in AOCI
Other	(20)		0
Other comprehensive (income)/loss reclassified to earnings	(512)	(828)	(2,927)
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0	0
Tax impact	0	0
Balance at end of year	56	568	1,396
Equity Investees
Components of accumulated other comprehensive loss
Balance at beginning of year	66	67	34
Other comprehensive income/(loss) retained in AOCI	(12)	(2)	34
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	66
Other	3		(7)
Other comprehensive (income)/loss reclassified to earnings	(75)	(2)	34
Income tax on amounts retained in AOCI	0	1	6
Income tax on amounts reclassified to earnings	4	0
Tax impact	4	1	6
Balance at end of year	(5)	66	67
Pension and OPEB Adjustment
Components of accumulated other comprehensive loss
Balance at beginning of year	(499)	(345)	(317)
Other comprehensive income/(loss) retained in AOCI	520	(221)	(124)
Changes in AOCI
Amortization of pension and OPEB actuarial loss and prior service costs	28	17	17
Other			55
Other comprehensive (income)/loss reclassified to earnings	548	(204)	(107)
Income tax on amounts retained in AOCI	(126)	54	28
Income tax on amounts reclassified to earnings	(7)	(4)	(4)
Tax impact	(133)	50	24
Balance at end of year	(84)	(499)	(345)
Total
Components of accumulated other comprehensive loss
Balance at beginning of year	(1,401)	(272)	2,672
Changes in AOCI
Balance at end of year	$ (1,096)	$ (1,401)	$ (272)

RISK MANAGEMENT AND FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - TOTAL DERIVATIVE INSTRUMENTS (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	$ (359)	$ (1,069)
Total Net Derivative Instruments	(359)	(1,069)
Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(202)	(373)
Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(45)	(580)
Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(112)	(116)
Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	529	323
Derivative assets, Amounts Available for Offset	(170)	(109)
Derivative assets, Total Net Derivative Instruments	359	214
Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	465	323
Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	64	0
Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Accounts receivable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	360	561
Derivative assets, Amounts Available for Offset	(75)	(252)
Derivative assets, Total Net Derivative Instruments	285	309
Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	272	491
Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	88	70
Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Deferred amounts and other assets | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(717)	(894)
Derivative liabilities, Amounts Available for Offset	170	109
Derivative liabilities, Total Net Derivative Instruments	(547)	(785)
Accounts payable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(426)	(434)
Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(179)	(431)
Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Accounts payable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(112)	(29)
Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(531)	(1,059)
Derivative liabilities, Amounts Available for Offset	75	252
Derivative liabilities, Total Net Derivative Instruments	(456)	(807)
Other long-term liabilities | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(513)	(753)
Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(18)	(219)
Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Other long-term liabilities | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(87)
Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(227)	(299)
Total Net Derivative Instruments	(227)	(299)
Foreign exchange contracts | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(100)	(192)
Foreign exchange contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(15)	9
Foreign exchange contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Foreign exchange contracts | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(112)	(116)
Foreign exchange contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	259	180
Derivative assets, Amounts Available for Offset	(41)	(28)
Derivative assets, Total Net Derivative Instruments	218	152
Foreign exchange contracts | Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	259	180
Foreign exchange contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Accounts receivable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	240	466
Derivative assets, Amounts Available for Offset	(61)	(218)
Derivative assets, Total Net Derivative Instruments	179	248
Foreign exchange contracts | Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	240	452
Foreign exchange contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	14
Foreign exchange contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Deferred amounts and other assets | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(303)	(185)
Derivative liabilities, Amounts Available for Offset	41	28
Derivative liabilities, Total Net Derivative Instruments	(262)	(157)
Foreign exchange contracts | Accounts payable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(176)	(151)
Foreign exchange contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(15)	(5)
Foreign exchange contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Accounts payable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(112)	(29)
Foreign exchange contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(423)	(760)
Derivative liabilities, Amounts Available for Offset	61	218
Derivative liabilities, Total Net Derivative Instruments	(362)	(542)
Foreign exchange contracts | Other long-term liabilities | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(423)	(673)
Foreign exchange contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Foreign exchange contracts | Other long-term liabilities | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(87)
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(22)	(610)
Total Net Derivative Instruments	(22)	(610)
Interest rate contracts | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(23)	(25)
Interest rate contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	1	(585)
Interest rate contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Interest rate contracts | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Interest rate contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	64	0
Derivative assets, Amounts Available for Offset	0	0
Derivative assets, Total Net Derivative Instruments	64	0
Interest rate contracts | Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	64	0
Interest rate contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Accounts receivable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	88	56
Derivative assets, Amounts Available for Offset	(1)	(25)
Derivative assets, Total Net Derivative Instruments	87	31
Interest rate contracts | Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	88	56
Interest rate contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Deferred amounts and other assets | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(150)	(425)
Derivative liabilities, Amounts Available for Offset	0	0
Derivative liabilities, Total Net Derivative Instruments	(150)	(425)
Interest rate contracts | Accounts payable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(2)
Interest rate contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(150)	(423)
Interest rate contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Accounts payable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(24)	(241)
Derivative liabilities, Amounts Available for Offset	1	25
Derivative liabilities, Total Net Derivative Instruments	(23)	(216)
Interest rate contracts | Other long-term liabilities | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(23)	(23)
Interest rate contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1)	(218)
Interest rate contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Other long-term liabilities | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(115)	(156)
Total Net Derivative Instruments	(115)	(156)
Commodity contracts | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(84)	(153)
Commodity contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(31)	(3)
Commodity contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Commodity contracts | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Commodity contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	204	143
Derivative assets, Amounts Available for Offset	(129)	(81)
Derivative assets, Total Net Derivative Instruments	75	62
Commodity contracts | Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	204	143
Commodity contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Accounts receivable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	29	39
Derivative assets, Amounts Available for Offset	(13)	(9)
Derivative assets, Total Net Derivative Instruments	16	30
Commodity contracts | Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	29	39
Commodity contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Deferred amounts and other assets | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(264)	(280)
Derivative liabilities, Amounts Available for Offset	129	81
Derivative liabilities, Total Net Derivative Instruments	(135)	(199)
Commodity contracts | Accounts payable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(250)	(278)
Commodity contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(14)	(2)
Commodity contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Accounts payable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(84)	(58)
Derivative liabilities, Amounts Available for Offset	13	9
Derivative liabilities, Total Net Derivative Instruments	(71)	(49)
Commodity contracts | Other long-term liabilities | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(67)	(57)
Commodity contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(17)	(1)
Commodity contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Commodity contracts | Other long-term liabilities | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	5	(4)
Total Net Derivative Instruments	5	(4)
Other contracts | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	5	(3)
Other contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	(1)
Other contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Other contracts | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Other contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	2	0
Derivative assets, Amounts Available for Offset	0	0
Derivative assets, Total Net Derivative Instruments	2	0
Other contracts | Accounts receivable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	2	0
Other contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Accounts receivable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	3	0
Derivative assets, Amounts Available for Offset	0	0
Derivative assets, Total Net Derivative Instruments	3	0
Other contracts | Deferred amounts and other assets | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	3	0
Other contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Deferred amounts and other assets | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(4)
Derivative liabilities, Amounts Available for Offset	0	0
Derivative liabilities, Total Net Derivative Instruments	0	(4)
Other contracts | Accounts payable and other | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(3)
Other contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(1)
Other contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Accounts payable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Derivative liabilities, Amounts Available for Offset	0	0
Derivative liabilities, Total Net Derivative Instruments	0	0
Other contracts | Other long-term liabilities | Non- Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	0
Other contracts | Other long-term liabilities | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - NOTIONAL PRINCIPAL OR QUANTITY INFORMATION (Details) € in Millions, ¥ in Millions, £ in Millions, MWh in Millions, MMBbls in Millions, Bcf in Millions, $ in Millions, $ in Millions	Dec. 31, 2021USD ($)MWhMMBblsBcf	Dec. 31, 2021GBP (£)MWhMMBblsBcf	Dec. 31, 2021EUR (€)MWhMMBblsBcf	Dec. 31, 2021JPY (¥)MWhMMBblsBcf	Dec. 31, 2021CAD ($)MWhMMBblsBcf	Dec. 31, 2020USD ($)MWhMMBblsBcf	Dec. 31, 2020GBP (£)MWhMMBblsBcf	Dec. 31, 2020EUR (€)MWhMMBblsBcf	Dec. 31, 2020JPY (¥)MWhMMBblsBcf	Dec. 31, 2020CAD ($)MWhMMBblsBcf
Foreign exchange contracts - United States dollar or GBP or Japanese yen forwards - purchase
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2021 notional principal	$ 2,508			¥ 72,500
2022 notional principal	0			0
2023 notional principal	0			0
2024 notional principal	0			0
2025 notional principal	0			0
Thereafter notional principal	0			0
Total notional principal	2,508			¥ 72,500		$ 3,522			¥ 72,500
Foreign exchange contracts - United States dollar or GBP forwards - sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2021 notional principal	9,245	£ 28	€ 104
2022 notional principal	5,596	29	92
2023 notional principal	4,346	30	91
2024 notional principal	3,174	30	86
2025 notional principal	2,574	28	85
Thereafter notional principal	492	32	343
Total notional principal	$ 25,427	£ 177	€ 801			$ 17,859	£ 265	€ 885
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2021 notional principal					$ 395
2022 notional principal					47
2023 notional principal					35
2024 notional principal					30
2025 notional principal					26
Thereafter notional principal					64
Total notional principal					597					$ 4,635
Interest rate contract - long term debt - Pay Fixed Rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2021 notional principal					2,363
2022 notional principal					1,784
2023 notional principal					1,132
2024 notional principal					0
2025 notional principal					0
Thereafter notional principal					0
Total notional principal					5,279					5,396
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2021 notional principal					20
2022 notional principal					26
2023 notional principal					21
2024 notional principal					0
2025 notional principal					0
Thereafter notional principal					0
Total notional principal					$ 67					$ 62
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2021 notional quantity (in bcf, bbl or mbbl) | Bcf	165	165	165	165	165
2022 notional quantity (in bcf, bbl or mbbl) | Bcf	18	18	18	18	18
2023 notional quantity (in bcf, bbl or mbbl) | Bcf	5	5	5	5	5
2024 notional quantity (in bcf, bbl or mbbl) | Bcf	11	11	11	11	11
2025 notional quantity (in bcf, bbl or mbbl) | Bcf	0	0	0	0	0
Thereafter notional quantity (in bcf, bbl or mbbl) | Bcf	0	0	0	0	0
Total notional quantity (in bcf, bbl or mbbl) | Bcf	199	199	199	199	199	173	173	173	173	173
Commodity contracts | Crude
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2021 notional quantity (in bcf, bbl or mbbl) | MMBbls	12	12	12	12	12
2022 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2023 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2024 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
2025 notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
Thereafter notional quantity (in bcf, bbl or mbbl) | MMBbls	0	0	0	0	0
Total notional quantity (in bcf, bbl or mbbl) | MMBbls	12	12	12	12	12	15	15	15	15	15
Commodity contracts | Power | Net sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2021 notional quantity (MW/H) | MWh	(43)	(43)	(43)	(43)	(43)
2022 notional quantity (MW/H) | MWh	(43)	(43)	(43)	(43)	(43)
2023 notional quantity (MW/H) | MWh	(43)	(43)	(43)	(43)	(43)
2024 notional quantity (MW/H) | MWh	(43)	(43)	(43)	(43)	(43)
2025 notional quantity (MW/H) | MWh	0	0	0	0	0
Thereafter notional quantity (MW/H) | MWh	0	0	0	0	0
Total notional quantity (MW/H) | MWh	(43)	(43)	(43)	(43)	(43)	(35)	(35)	(35)	(35)	(35)

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - EFFECTS ON EARNINGS AND COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	$ 191	$ (579)	$ (591)
Amount (gain)/loss reclassified from AOCI to earnings	$ 304	256	158
Period to hedge exposures to the variability of cash flows for all forecasted transactions	36 months
Realized loss on derivative	$ 59	265	346
Unrealized gain/(loss) on derivative	173	756	1,751
Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Estimated loss of AOCI related to cash flow hedges reclassified to earnings in the next 12 months	47
Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	5	5	5
Foreign exchange contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(29)	(1)	(19)
Foreign exchange contracts | Fair Value Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(5)	5	0
Foreign exchange contracts | Net Investment Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	0	13	2
Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	296	253	157
Interest rate contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	252	(595)	(559)
Interest rate contracts | Fair Value Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	8	(116)
Unrealized gain/(loss) on hedged item	(15)	133
Realized loss on derivative	(41)	(12)
Realized gain on hedged item	45	0
Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	1	0	(1)
Commodity contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(28)	2	(25)
Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount (gain)/loss reclassified from AOCI to earnings	2	(2)	(3)
Other contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	1	(3)	10
Non- Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	173	756	1,751
Non- Qualifying Derivative Instruments | Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	92	902	1,626
Non- Qualifying Derivative Instruments | Foreign exchange contracts | Transportation and other services
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	98	533	930
Non- Qualifying Derivative Instruments | Foreign exchange contracts | Other income/(expense)
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	(6)	369	696
Non- Qualifying Derivative Instruments | Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	2	(25)	178
Non- Qualifying Derivative Instruments | Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	71	(114)	(62)
Non- Qualifying Derivative Instruments | Commodity contracts | Transportation and other services
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	9	(2)	(26)
Non- Qualifying Derivative Instruments | Commodity contracts | Commodity sales
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	160	(321)	(544)
Non- Qualifying Derivative Instruments | Commodity contracts | Commodity costs
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	(105)	207	459
Non- Qualifying Derivative Instruments | Commodity contracts | Operating and administrative expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	7	2	49
Non- Qualifying Derivative Instruments | Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain/(loss) on derivative	$ 8	$ (7)	$ 9

RISK MANAGEMENT AND FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LIQUIDITY AND CREDIT RISK (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
LIQUIDITY RISK AND CREDIT RISK
Rolling time period over which the Company forecasts cash requirements	12 months
Period of anticipated requirements for which the Company maintains sufficient liquidity through committed credit facilities	1 year
Letters of credit provided in lieu of providing cash collateral to counterparties	$ 0
Cash collateral	$ 0	$ 0
Period after which receivables are classified as past due	30 days
Interest Rate Swaption
LIQUIDITY RISK AND CREDIT RISK
Average swap rate (as a percent)	3.90%
Interest rate contracts - long-term borrowings
LIQUIDITY RISK AND CREDIT RISK
Average swap rate (as a percent)	2.00%
Maximum
LIQUIDITY RISK AND CREDIT RISK
Policy limit increase (percent)	30.00%
Derivative instruments
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 887,000,000	872,000,000
Derivative instruments | Canadian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	424,000,000	481,000,000
Derivative instruments | United States financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	130,000,000	99,000,000
Derivative instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	181,000,000	28,000,000
Derivative instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	30,000,000	167,000,000
Derivative instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 122,000,000	$ 97,000,000

RISK MANAGEMENT AND FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - FAIR VALUE OF DERIVATIVES (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value of Derivatives
Current derivative assets	$ 529	$ 323
Current derivative liabilities	(717)	(896)
Total net derivative asset/(liability)	(359)	(1,069)
Foreign exchange contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(227)	(299)
Interest rate contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(22)	(610)
Commodity contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(115)	(156)
Other contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	5	(4)
Fair Value
Fair Value of Derivatives
Current derivative assets	529	323
Long-term derivative assets	360	561
Current derivative liabilities	(717)	(894)
Long-term derivative liabilities	(531)	(1,059)
Total net derivative asset/(liability)		(1,069)
Fair Value | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	259	180
Long-term derivative assets	240	466
Current derivative liabilities	(303)	(185)
Long-term derivative liabilities	(423)	(760)
Total net derivative asset/(liability)	(227)	(299)
Fair Value | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	64	0
Long-term derivative assets	88	56
Current derivative liabilities	(150)	(425)
Long-term derivative liabilities	(24)	(241)
Total net derivative asset/(liability)	(22)	(610)
Fair Value | Commodity contracts
Fair Value of Derivatives
Current derivative assets	204	143
Long-term derivative assets	29	39
Current derivative liabilities	(264)	(280)
Long-term derivative liabilities	(84)	(58)
Total net derivative asset/(liability)	(115)	(156)
Fair Value | Other contracts
Fair Value of Derivatives
Current derivative assets	2	0
Long-term derivative assets	3	0
Current derivative liabilities	0	(4)
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)		(4)
Level 1 | Fair Value
Fair Value of Derivatives
Current derivative assets	38	43
Long-term derivative assets	0	1
Current derivative liabilities	(52)	(39)
Long-term derivative liabilities	0	(1)
Total net derivative asset/(liability)	(14)	4
Level 1 | Fair Value | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 1 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 1 | Fair Value | Commodity contracts
Fair Value of Derivatives
Current derivative assets	38	43
Long-term derivative assets	0	1
Current derivative liabilities	(52)	(39)
Long-term derivative liabilities	0	(1)
Total net derivative asset/(liability)	(14)	4
Level 1 | Fair Value | Other contracts
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 2 | Fair Value
Fair Value of Derivatives
Current derivative assets	396	213
Long-term derivative assets	352	546
Current derivative liabilities	(519)	(632)
Long-term derivative liabilities	(466)	(1,009)
Total net derivative asset/(liability)	(237)	(882)
Level 2 | Fair Value | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	259	180
Long-term derivative assets	240	466
Current derivative liabilities	(303)	(185)
Long-term derivative liabilities	(423)	(760)
Total net derivative asset/(liability)	(227)	(299)
Level 2 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	64	0
Long-term derivative assets	88	56
Current derivative liabilities	(150)	(425)
Long-term derivative liabilities	(24)	(241)
Total net derivative asset/(liability)	(22)	(610)
Level 2 | Fair Value | Commodity contracts
Fair Value of Derivatives
Current derivative assets	71	33
Long-term derivative assets	21	24
Current derivative liabilities	(66)	(18)
Long-term derivative liabilities	(19)	(8)
Total net derivative asset/(liability)	7	31
Level 2 | Fair Value | Other contracts
Fair Value of Derivatives
Current derivative assets	2	0
Long-term derivative assets	3	0
Current derivative liabilities	0	(4)
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	5	(4)
Level 3 | Fair Value
Fair Value of Derivatives
Current derivative assets	95	67
Long-term derivative assets	8	14
Current derivative liabilities	(146)	(223)
Long-term derivative liabilities	(65)	(49)
Total net derivative asset/(liability)	(108)	(191)
Level 3 | Fair Value | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 3 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 3 | Fair Value | Commodity contracts
Fair Value of Derivatives
Current derivative assets	95	67
Long-term derivative assets	8	14
Current derivative liabilities	(146)	(223)
Long-term derivative liabilities	(65)	(49)
Total net derivative asset/(liability)	(108)	(191)
Level 3 | Fair Value | Other contracts
Fair Value of Derivatives
Current derivative assets	0	0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	$ 0	$ 0

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LEVEL 3 INPUTS (Details) $ in Millions	Dec. 31, 2021CAD ($)$ / MillionsofBTU-MMBTU$ / bbl$ / MWh	Dec. 31, 2020CAD ($)
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (359)	$ (1,069)
Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value		(1,069)
Level 3 | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (108)	$ (191)
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Natural gas | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	3.12
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Natural gas | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	9.05
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Natural gas | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	4.49
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Crude | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	76.02
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Crude | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	98.99
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Crude | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	91.73
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Power | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MWh	31
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Power | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MWh	125.13
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Power | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MWh	76.23
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	2.65
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	9.25
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	4.63
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	68.66
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	97
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	87.97
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Natural gas
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (19)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Crude
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	3
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Power
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(60)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | Natural gas
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(56)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | Crude
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ 24

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - CHANGES IN LEVEL 3 (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative liability at beginning of period	$ (191)	$ (69)
Total gain/(loss)
Included in earnings	(39)	(123)
Included in OCI	(29)	2
Settlements	151	(1)
Level 3 net derivative liability at end of period	$ (108)	$ (191)

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - OTHER FINANCIAL INSTRUMENTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Fair Value of Other Financial Instruments
Realized gain (loss) associated with the settlement of United Stated dollar denominated debt that matured	$ 0	$ 0
Equity investments at carrying value	52	52
Restricted long-term investments	630	553
Long-term debt	82,000	75,100
Long-term loans receivable from affiliates	1,000	1,100
Net Investment Hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	49	117
Unrealized gain (loss) on change in fair value of outstanding forward exchange forward contracts	0	13
Realized loss associated with the settlement of foreign exchange forward contracts	0	15
Carrying value
Fair Value of Other Financial Instruments
Long-term debt	$ 74,400	$ 66,100

INCOME TAXES - RATE RECONCILIAT

INCOME TAXES - RATE RECONCILIATION (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
INCOME TAX RATE RECONCILIATION
Earnings before income taxes	$ 7,729	$ 4,190	$ 7,535
Canadian federal statutory income tax rate	15.00%	15.00%	15.00%
Expected federal taxes at statutory rate	$ 1,159	$ 629	$ 1,130
Increase/(decrease) resulting from:
Provincial and state income taxes	228	288	415
Foreign and other statutory rate differentials	134	(53)	129
Effects of rate-regulated accounting	(139)	(145)	(63)
Foreign allowable interest deductions	0	(4)	(29)
Part VI.1 tax, net of federal Part I deduction	73	76	78
US Minimum Tax	0	44	67
Non-taxable portion of gain on sale of investment	(23)	0	0
Valuation allowance	5	(6)	26
Intercorporate investments	0	0	(14)
Noncontrolling interests	(17)	(8)	(13)
Other	(5)	(47)	(18)
Income tax expense	$ 1,415	$ 774	$ 1,708
Effective income tax rate (as a percent)	1830.00%	1850.00%	2270.00%

INCOME TAXES - COMPONENTS (Deta

INCOME TAXES - COMPONENTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings/(loss) before income taxes and discontinued operations
Earnings before income taxes	$ 7,729	$ 4,190	$ 7,535
Current income taxes
Total current income taxes	324	327	552
Deferred income taxes
Total deferred income taxes	1,091	447	1,156
Income tax expense	1,415	774	1,708
Canada
Earnings/(loss) before income taxes and discontinued operations
Domestic	3,399	2,789	3,560
Current income taxes
Domestic	162	165	347
Deferred income taxes
Domestic	344	378	490
US
Earnings/(loss) before income taxes and discontinued operations
Foreign	3,336	407	3,115
Current income taxes
Foreign	80	64	107
Deferred income taxes
Foreign	741	66	672
Other
Earnings/(loss) before income taxes and discontinued operations
Foreign	994	994	860
Current income taxes
Foreign	82	98	98
Deferred income taxes
Foreign	$ 6	$ 3	$ (6)

INCOME TAXES - DEFERRED INCOME

INCOME TAXES - DEFERRED INCOME TAXES (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred income tax liabilities
Property, plant and equipment	$ (8,721)	$ (7,786)
Investments	(6,097)	(4,649)
Regulatory assets	(1,245)	(1,156)
Other	(208)	(127)
Total deferred income tax liabilities	(16,271)	(13,718)
Deferred income tax assets
Financial instruments	315	518
Pension and OPEB plans	110	251
Loss carryforwards	3,081	2,005
Other	1,648	1,461
Total deferred income tax assets	5,154	4,235
Less valuation allowance	(84)	(79)
Total deferred income tax assets, net	5,070	4,156
Net deferred income tax liabilities	(11,201)	(9,562)
Deferred income taxes	488	770
Total deferred income tax liabilities	(11,689)	(10,332)
Operating loss carryforwards that do not expire	7,500	3,400
Foreign subsidiaries' undistributed earnings on which deferred income taxes has not been provided	4,300	5,500
Canada
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	1,900	2,600
US
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	11,000	5,800
Operating loss carryforwards that expire	$ 3,500	$ 2,400

INCOME TAXES - UNRECOGNIZED TAX

INCOME TAXES - UNRECOGNIZED TAX BENEFITS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
UNRECOGNIZED TAX BENEFITS
Unrecognized tax benefits at beginning of year	$ 121	$ 129
Gross increases for tax positions of current year	1	1
Gross decreases for tax positions of prior year	(26)	(1)
Change in translation of foreign currency	(1)	(3)
Lapses of statute of limitations	(19)	(5)
Unrecognized tax benefits at end of year	76	121
Interest and penalties expense (recovery) related to unrecognized tax benefits	(5)	3
Accrued interest and penalties related to unrecognized tax benefits	$ 12	$ 17

PENSION AND OTHER POSTRETIREM_3

PENSION AND OTHER POSTRETIREMENT BENEFITS - BENEFIT OBLIGATION, PLAN ASSETS AND FUNDED STATUS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Presented as follows:
Accumulated benefit obligation		$ 1,200
Canada | Pension
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	$ 4,855	4,446
Service cost	139	148	$ 149
Interest cost	101	128	139
Participant contributions	28	31
Actuarial (gain)/loss	(329)	292
Benefits paid	(194)	(190)
Foreign currency exchange rate changes	0	0
Other	0	0
Accumulated postretirement benefit obligation at end of year	4,600	4,855	4,446
Change in plan assets
Fair value of plan assets at beginning of year	4,077	3,827
Actual return on plan assets	505	288
Employer contributions	120	121
Participant contributions	28	31
Benefits paid	(194)	(190)
Foreign currency exchange rate changes	0	0
Other	0	0
Fair value of plan assets at end of year	4,536	4,077	3,827
Overfunded/(underfunded) status at end of year	(64)	(778)
Presented as follows:
Deferred amounts and other assets	250	35
Accounts payable and other	(9)	(9)
Other long-term liabilities	(305)	(804)
Amount recognized in balance sheet	(64)	(778)
Accumulated benefit obligation	4,300	4,500
Canada | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	13	11
Canada | OPEB
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	321	293
Service cost	6	5	5
Interest cost	7	8	10
Participant contributions	0	0
Actuarial (gain)/loss	(51)	21
Benefits paid	(9)	(6)
Plan amendments	0	0
Foreign currency exchange rate changes	0	0
Other	0	0
Accumulated postretirement benefit obligation at end of year	274	321	293
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	9	6
Participant contributions	0	0
Benefits paid	(9)	(6)
Foreign currency exchange rate changes	0	0
Other	0	0
Fair value of plan assets at end of year	0	0	0
Overfunded/(underfunded) status at end of year	(274)	(321)
Presented as follows:
Deferred amounts and other assets	0	0
Accounts payable and other	(12)	(13)
Other long-term liabilities	(262)	(308)
Amount recognized in balance sheet	(274)	(321)
United States
Change in plan assets
Employer contributions	27	27	27
United States | Pension
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	1,243	1,230
Service cost	44	44	45
Interest cost	17	31	41
Participant contributions	0	0
Actuarial (gain)/loss	(21)	95
Benefits paid	(84)	(128)
Foreign currency exchange rate changes	(11)	(23)
Other	(4)	(6)
Accumulated postretirement benefit obligation at end of year	1,184	1,243	1,230
Change in plan assets
Fair value of plan assets at beginning of year	1,062	1,104
Actual return on plan assets	151	83
Employer contributions	43	27
Participant contributions	0	0
Benefits paid	(84)	(128)
Foreign currency exchange rate changes	(8)	(18)
Other	(4)	(6)
Fair value of plan assets at end of year	1,160	1,062	1,104
Overfunded/(underfunded) status at end of year	(24)	(181)
Presented as follows:
Deferred amounts and other assets	98	0
Accounts payable and other	(4)	(3)
Other long-term liabilities	(118)	(178)
Amount recognized in balance sheet	(24)	(181)
Accumulated benefit obligation	1,100
United States | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	84	59
United States | OPEB
Change in projected benefit obligation
Accumulated postretirement benefit obligation at beginning of year	254	288
Service cost	1	2	2
Interest cost	3	7	10
Participant contributions	8	4
Actuarial (gain)/loss	(69)	17
Benefits paid	(22)	(28)
Plan amendments	0	(33)
Foreign currency exchange rate changes	(3)	(4)
Other	1	1
Accumulated postretirement benefit obligation at end of year	173	254	288
Change in plan assets
Fair value of plan assets at beginning of year	188	188
Actual return on plan assets	22	14
Employer contributions	6	12
Participant contributions	8	4
Benefits paid	(22)	(28)
Foreign currency exchange rate changes	(3)	(3)
Other	2	1
Fair value of plan assets at end of year	201	188	$ 188
Overfunded/(underfunded) status at end of year	28	(66)
Presented as follows:
Deferred amounts and other assets	71	19
Accounts payable and other	0	(6)
Other long-term liabilities	(43)	(79)
Amount recognized in balance sheet	$ 28	$ (66)

PENSION AND OTHER POSTRETIREM_4

PENSION AND OTHER POSTRETIREMENT BENEFITS - AMOUNT RECOGNIZED IN EXCESS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Canada
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	$ 440	$ 4,094
Fair value of plan assets	247	3,621
Canada | OPEB
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	274	321
Fair value of plan assets	0	0
Projected benefit obligation	1,272	4,434
Fair value of plan assets	1,020	3,621
United States
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	115	1,207
Fair value of plan assets	0	1,062
United States | OPEB
Pension and Other Postretirement Benefit Disclosures
Accumulated benefit obligation	94	191
Fair value of plan assets	51	106
Projected benefit obligation	121	1,243
Fair value of plan assets	$ 0	$ 1,062

PENSION AND OTHER POSTRETIREM_5

PENSION AND OTHER POSTRETIREMENT BENEFITS - AMOUNT RECOGNIZED IN ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Canada | OPEB
Amount included in AOCI
Net actuarial loss	$ (35)	$ 15
Prior service credit	(1)	(1)
Total amount recognized in AOCI	(36)	14
Canada | Pension
Amount included in AOCI
Net actuarial loss	226	542
Prior service credit	0	0
Total amount recognized in AOCI	226	542
United States | OPEB
Amount included in AOCI
Net actuarial loss	(104)	(7)
Prior service credit	(37)	(44)
Total amount recognized in AOCI	(141)	(51)
United States | Pension
Amount included in AOCI
Net actuarial loss	92	233
Prior service credit	(1)	(1)
Total amount recognized in AOCI	$ 91	$ 232

PENSION AND OTHER POSTRETIREM_6

PENSION AND OTHER POSTRETIREMENT BENEFITS - NET BENEFIT COSTS RECOGNIZED (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 139	$ 148	$ 149
Interest cost	101	128	139
Expected return on plan assets	(252)	(260)	(245)
Amortization/settlement of net actuarial loss	54	42	41
Amortization/curtailment of prior service credit	0	0	0
Net periodic benefit (credit)/cost	42	58	84
Defined contribution benefit cost	7	6	8
Net pension (credit)/cost recognized in Earnings	49	64	92
Amount recognized in OCI:
Effect of plan combination	0	0	0
Amortization/settlement of net actuarial loss	(25)	(21)	(26)
Amortization/curtailment of prior service credit	0	0	0
Net actuarial (gain)/loss arising during the year	(291)	118	115
Total amount recognized in OCI	(316)	97	89
Total amount recognized in Comprehensive income	(267)	161	181
Pension | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	44	44	45
Interest cost	17	31	41
Expected return on plan assets	(73)	(88)	(78)
Amortization/settlement of net actuarial loss	11	1	2
Amortization/curtailment of prior service credit	0	(1)	(1)
Net periodic benefit (credit)/cost	(1)	(13)	9
Defined contribution benefit cost	0	0	0
Net pension (credit)/cost recognized in Earnings	(1)	(13)	9
Amount recognized in OCI:
Effect of plan combination	0	0	(6)
Amortization/settlement of net actuarial loss	(11)	(1)	(2)
Amortization/curtailment of prior service credit	0	1	1
Net actuarial (gain)/loss arising during the year	(99)	100	8
Total amount recognized in OCI	(110)	100	1
Total amount recognized in Comprehensive income	(111)	87	10
OPEB | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	6	5	5
Interest cost	7	8	10
Expected return on plan assets	0	0	0
Amortization/settlement of net actuarial loss	0	(1)	(7)
Amortization/curtailment of prior service credit	0	0	(1)
Net pension (credit)/cost recognized in Earnings	13	12	7
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	0	1	7
Amortization/curtailment of prior service credit	0	0	1
Net actuarial (gain)/loss arising during the year	(50)	21	15
Prior service credit	0	0	0
Total amount recognized in OCI	(50)	22	23
Total amount recognized in Comprehensive income	(37)	34	30
OPEB | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	1	2	2
Interest cost	3	7	10
Expected return on plan assets	(10)	(12)	(12)
Amortization/settlement of net actuarial loss	(1)	(1)	0
Amortization/curtailment of prior service credit	(7)	(2)	(2)
Net pension (credit)/cost recognized in Earnings	(14)	(6)	(2)
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	1	1	0
Amortization/curtailment of prior service credit	7	2	2
Net actuarial (gain)/loss arising during the year	(80)	15	(8)
Prior service credit	0	(33)	0
Total amount recognized in OCI	(72)	(15)	(6)
Total amount recognized in Comprehensive income	$ (86)	$ (21)	$ (8)

PENSION AND OTHER POSTRETIREM_7

PENSION AND OTHER POSTRETIREMENT BENEFITS - ACTUARIAL ASSUMPTIONS (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension | Canada
Projected benefit obligation
Discount rate	3.20%	2.60%	3.00%
Rate of salary increase	2.90%	2.30%	3.20%
Net periodic benefit cost
Discount rate	2.60%	3.00%	3.80%
Rate of return on plan assets	6.20%	6.80%	7.00%
Rate of salary increase	2.30%	3.20%	3.20%
Pension | United States
Projected benefit obligation
Discount rate	2.60%	2.20%	3.00%
Rate of salary increase	2.80%	2.70%	2.90%
Cash balance interest credit rate	4.30%	4.30%	4.50%
Net periodic benefit cost
Discount rate	2.20%	3.00%	3.90%
Rate of return on plan assets	7.30%	7.90%	8.00%
Rate of salary increase	2.70%	2.90%	2.90%
Cash balance interest credit rate	4.30%	4.50%	4.50%
OPEB | Canada
Projected benefit obligation
Discount rate	3.20%	2.60%	3.10%
Net periodic benefit cost
Discount rate	2.60%	3.10%	3.80%
OPEB | United States
Projected benefit obligation
Discount rate	2.40%	2.00%	2.80%
Net periodic benefit cost
Discount rate	2.00%	2.80%	4.00%
Rate of return on plan assets	6.00%	6.70%	6.70%

PENSION AND OTHER POSTRETIREM_8

PENSION AND OTHER POSTRETIREMENT BENEFITS - ASSUMED HEALTH CARE COST TREND RATES (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Canada
MEDICAL COST TRENDS (as percent)
Health care cost trend rate assumed for next year	4.00%	4.00%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	4.00%	4.00%
United States
MEDICAL COST TRENDS (as percent)
Health care cost trend rate assumed for next year	7.00%	6.80%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	4.50%	4.50%
Year that the rate reaches the ultimate trend rate	2037	2037

PENSION AND OTHER POSTRETIREM_9

PENSION AND OTHER POSTRETIREMENT BENEFITS - PLAN ASSETS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Canada | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	43.80%
Plan asset allocations	46.70%	47.20%
Canada | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	28.90%
Plan asset allocations	29.80%	29.60%
Canada | Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	27.30%
Plan asset allocations	23.50%	23.20%
Canada | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 4,077	$ 3,827
Fair value of plan assets at end of year	4,536	4,077
Canada | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	600
Fair value of plan assets at end of year	637	600
Canada | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	2,565
Fair value of plan assets at end of year	2,835	2,565
Canada | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	912	852
Unrealized and realized gains/(losses)	77	(27)
Purchases and settlements, net	75	87
Fair value of plan assets at end of year	1,064	912
Canada | Pension | Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	213
Fair value of plan assets at end of year	180	213
Canada | Pension | Cash and Cash Equivalents | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	213
Fair value of plan assets at end of year	180	213
Canada | Pension | Cash and Cash Equivalents | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Cash and Cash Equivalents | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, Non-US
Change in plan assets
Fair value of plan assets at beginning of year	366
Fair value of plan assets at end of year	426	366
Canada | Pension | Equity Securities, Non-US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	178
Fair value of plan assets at end of year	198	178
Canada | Pension | Equity Securities, Non-US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	188
Fair value of plan assets at end of year	228	188
Canada | Pension | Equity Securities, Non-US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	1	2
Canada | Pension | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	1	2
Canada | Pension | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	1,556
Fair value of plan assets at end of year	1,693	1,556
Canada | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	1,556
Fair value of plan assets at end of year	1,693	1,556
Canada | Pension | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Government
Change in plan assets
Fair value of plan assets at beginning of year	585
Fair value of plan assets at end of year	717	585
Canada | Pension | Government | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	207
Fair value of plan assets at end of year	258	207
Canada | Pension | Government | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	378
Fair value of plan assets at end of year	459	378
Canada | Pension | Government | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Corporate
Change in plan assets
Fair value of plan assets at beginning of year	410
Fair value of plan assets at end of year	453	410
Canada | Pension | Corporate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Corporate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	410
Fair value of plan assets at end of year	453	410
Canada | Pension | Corporate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Infrastructure and real estate
Change in plan assets
Fair value of plan assets at beginning of year	912
Fair value of plan assets at end of year	1,064	912
Canada | Pension | Infrastructure and real estate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Infrastructure and real estate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Infrastructure and real estate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	912
Fair value of plan assets at end of year	1,064	912
Canada | Pension | Foreign exchange contracts
Change in plan assets
Fair value of plan assets at beginning of year	33
Fair value of plan assets at end of year	2	33
Canada | Pension | Foreign exchange contracts | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Foreign exchange contracts | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	33
Fair value of plan assets at end of year	2	33
Canada | Pension | Foreign exchange contracts | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Fair value of plan assets at end of year	$ 0	$ 0
United States | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	45.00%
Plan asset allocations	52.50%	55.60%
United States | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	20.10%
Plan asset allocations	18.40%	17.20%
United States | Alternatives
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	34.90%
Plan asset allocations	29.10%	27.20%
United States | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 1,062	$ 1,104
Fair value of plan assets at end of year	1,160	1,062
United States | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	5
Fair value of plan assets at end of year	10	5
United States | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	768
Fair value of plan assets at end of year	813	768
United States | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	289	276
Unrealized and realized gains/(losses)	38	7
Purchases and settlements, net	10	6
Fair value of plan assets at end of year	337	289
United States | Pension | Cash and Cash Equivalents
Change in plan assets
Fair value of plan assets at beginning of year	5
Fair value of plan assets at end of year	10	5
United States | Pension | Cash and Cash Equivalents | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	5
Fair value of plan assets at end of year	10	5
United States | Pension | Cash and Cash Equivalents | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Cash and Cash Equivalents | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Non-US
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Non-US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Non-US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Non-US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	590
Fair value of plan assets at end of year	609	590
United States | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	590
Fair value of plan assets at end of year	609	590
United States | Pension | Equity Securities, Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Government
Change in plan assets
Fair value of plan assets at beginning of year	75
Fair value of plan assets at end of year	86	75
United States | Pension | Government | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Government | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	75
Fair value of plan assets at end of year	86	75
United States | Pension | Government | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Corporate
Change in plan assets
Fair value of plan assets at beginning of year	103
Fair value of plan assets at end of year	118	103
United States | Pension | Corporate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Corporate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	103
Fair value of plan assets at end of year	118	103
United States | Pension | Corporate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Infrastructure and real estate
Change in plan assets
Fair value of plan assets at beginning of year	289
Fair value of plan assets at end of year	337	289
United States | Pension | Infrastructure and real estate | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Infrastructure and real estate | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Infrastructure and real estate | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	289
Fair value of plan assets at end of year	337	289
United States | Pension | Foreign exchange contracts
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Foreign exchange contracts | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Foreign exchange contracts | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Foreign exchange contracts | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB
Change in plan assets
Fair value of plan assets at beginning of year	188	188
Fair value of plan assets at end of year	201	188
United States | OPEB | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	188
Fair value of plan assets at end of year	201	188
United States | OPEB | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	38
Fair value of plan assets at end of year	51	38
United States | OPEB | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	128
Fair value of plan assets at end of year	128	128
United States | OPEB | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	22	18
Unrealized and realized gains/(losses)	2	1
Purchases and settlements, net	(2)	3
Fair value of plan assets at end of year	22	22
United States | OPEB | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	22
Fair value of plan assets at end of year	22	22
United States | OPEB | Cash and Cash Equivalents | Fair Value
Change in plan assets
Fair value of plan assets at end of year	4
United States | OPEB | Cash and Cash Equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	4
United States | OPEB | Cash and Cash Equivalents | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
United States | OPEB | Cash and Cash Equivalents | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
United States | OPEB | Equity Securities, Non-US
Change in plan assets
Fair value of plan assets at beginning of year	79
Fair value of plan assets at end of year	75	79
United States | OPEB | Equity Securities, Non-US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, Non-US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	79
Fair value of plan assets at end of year	75	79
United States | OPEB | Equity Securities, Non-US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	35
Fair value of plan assets at end of year	39	35
United States | OPEB | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity Securities, US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	35
Fair value of plan assets at end of year	39	35
United States | OPEB | Equity Securities, US | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	44
Fair value of plan assets at end of year	53	44
United States | OPEB | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	38
Fair value of plan assets at end of year	47	38
United States | OPEB | Government | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	6
Fair value of plan assets at end of year	6	6
United States | OPEB | Government | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Corporate | Fair Value
Change in plan assets
Fair value of plan assets at end of year	8
United States | OPEB | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Corporate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	8
Fair value of plan assets at end of year	8	8
United States | OPEB | Corporate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Infrastructure and real estate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	22
Fair value of plan assets at end of year	22	22
United States | OPEB | Infrastructure and real estate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Infrastructure and real estate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Infrastructure and real estate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	22
Fair value of plan assets at end of year	$ 22	$ 22

PENSION AND OTHER POSTRETIRE_10

PENSION AND OTHER POSTRETIREMENT BENEFITS - EXPECTED BENEFIT PAYMENTS AND EMPLOYER CONTRIBUTIONS (Details) $ in Millions	Dec. 31, 2021CAD ($)
Canada | Pension
Benefits Expected to be Paid by the Company
2022	$ 197
2023	203
2024	208
2025	212
2026	217
2027-2031	1,163
Contributions expected to be paid in next fiscal year	110
Canada | OPEB
Benefits Expected to be Paid by the Company
2022	12
2023	12
2024	12
2025	13
2026	13
2027-2031	67
Contributions expected to be paid in next fiscal year	12
United States | Pension
Benefits Expected to be Paid by the Company
2022	80
2023	78
2024	78
2025	76
2026	77
2027-2031	374
Contributions expected to be paid in next fiscal year	4
United States | OPEB
Benefits Expected to be Paid by the Company
2022	17
2023	15
2024	14
2025	13
2026	12
2027-2031	51
Contributions expected to be paid in next fiscal year	$ 6

PENSION AND OTHER POSTRETIRE_11

PENSION AND OTHER POSTRETIREMENT BENEFITS - RETIREMENT SAVINGS PLAN (Details) - United States - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension and Other Postretirement Benefit Disclosures
Percent of match (percent)	6.00%
Total contributions by the Company	$ 27	$ 27	$ 27

LEASES - NARRATIVE (Details)

LEASES - NARRATIVE (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Operating lease, expense	$ 95	$ 107
Operating lease, payments	$ 118	$ 133
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	5 months
Lessor, operating lease, remaining lease term	1 month
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	25 years
Lessor, operating lease, remaining lease term	30 years

LEASES - SUPPLEMENTAL STATEMENT

LEASES - SUPPLEMENTAL STATEMENTS OF FINANCIAL POSITION (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Supplemental Statements Of Financial Position
Operating lease right-of-use assets, net	$ 645	$ 708
Operating lease liabilities - current	92	80
Operating lease liabilities - long-term	612	681
Total	704	761
Finance lease right-of-use assets, net	49	57
Finance lease liabilities - current	13	11
Finance lease liabilities - long-term	33	42
Total finance lease liabilities	$ 46	$ 53
Operating leases - Weighted average remaining lease term	12 years	13 years
Finance leases - Weighted average remaining lease term	7 years	7 years
Operating leases - Weighted average discount rate	4.10%	4.10%
Finance leases - Weighted average discount rate	3.80%	3.80%
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Deferred amounts and other assets	Deferred amounts and other assets
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts payable and other (Note 17)	Accounts payable and other (Note 17)
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Property, plant and equipment, net (Note 11)	Property, plant and equipment, net (Note 11)
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Current portion of long-term debt (Note 18)	Current portion of long-term debt (Note 18)
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Operating lease right-of-use assets	$ 645	$ 708
Affiliated Entity
Supplemental Statements Of Financial Position
Operating lease right-of-use assets, net	51	65
Operating lease liabilities - current	5	5
Operating lease liabilities - long-term	47	52
Operating lease right-of-use assets	$ 51	$ 65

LEASES - LEASE COMMITMENTS (Det

LEASES - LEASE COMMITMENTS (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Operating leases
2022	$ 117
2023	98
2024	91
2025	84
2026	72
Thereafter	455
Total undiscounted lease payments	917
Less imputed interest	(213)
Total	704	$ 761
Finance leases
2022	15
2023	13
2024	9
2025	2
2026	1
Thereafter	11
Total undiscounted lease payments	51
Less imputed interest	(5)
Total finance lease liabilities	$ 46	$ 53

LEASES - LESSOR LEASE INCOME (D

LEASES - LESSOR LEASE INCOME (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease income	$ 263	$ 265
Variable lease income	333	361
Total lease income	$ 596	$ 626

LEASES - LESSOR FUTURE EXPECTED

LEASES - LESSOR FUTURE EXPECTED LEASE RECEIPTS (Details) $ in Millions	Dec. 31, 2021CAD ($)
Leases [Abstract]
2022	$ 235
2023	215
2024	205
2025	196
2026	191
Thereafter	1,938
Future lease payments	$ 2,980

CHANGES IN OPERATING ASSETS A_3

CHANGES IN OPERATING ASSETS AND LIABILITIES (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
CHANGES IN OPERATING ASSETS AND LIABILITIES
Accounts receivable and other	$ (1,228)	$ 1,546	$ (547)
Accounts receivable from affiliates	(38)	8	6
Inventory	(118)	(254)	(24)
Deferred amounts and other assets	(195)	(586)	133
Accounts payable and other	(63)	(770)	63
Accounts payable to affiliates	52	1	(24)
Interest payable	43	31	(41)
Other long-term liabilities	(69)	117	175
Changes in operating assets and liabilities	$ (1,616)	$ 93	$ (259)

RELATED PARTY TRANSACTIONS - Tr

RELATED PARTY TRANSACTIONS - Transactions With Significantly Influenced Investees (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Significantly Influenced Investees
RELATED PARTY TRANSACTIONS
Transportation and other services	$ 149	$ 133	$ 140
Commodity sales	20	21	107
Operating and administrative	292	252	241
Recoveries recorded on expenses	104	94	86
Commodity costs	790	518	773
Gas distribution costs	131	135	133
Seaway Crude Pipeline System
RELATED PARTY TRANSACTIONS
Operating and administrative	389	342	327
Aux Sable Canada LP
RELATED PARTY TRANSACTIONS
Commodity costs	$ 447	$ 91	$ 272

RELATED PARTY TRANSACTIONS - Na

RELATED PARTY TRANSACTIONS - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
RELATED PARTY TRANSACTIONS
Affiliate loan receivable	$ 954	$ 1,108
Interest income	$ 39	$ 44	$ 40
Minimum
RELATED PARTY TRANSACTIONS
Annual interest rate on the loans (as a percent)	3.00%
Maximum
RELATED PARTY TRANSACTIONS
Annual interest rate on the loans (as a percent)	8.00%

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - COMMITMENTS (Details) $ in Millions	Dec. 31, 2021CAD ($)
Annual debt maturities
Total	$ 73,809
Less than 1 year	6,164
2 years	7,910
3 years	4,559
4 years	4,357
5 years	11,007
Thereafter	39,812
Interest obligations
Total	36,044
Less than 1 year	2,531
2 years	2,389
3 years	2,229
4 years	2,073
5 years	1,925
Thereafter	24,897
Purchase of services, pipe and other materials, including transportation
Total	7,876
Less than 1 year	2,945
2 years	1,010
3 years	736
4 years	561
5 years	607
Thereafter	2,017
Maintenance agreements
Total	346
Less than 1 year	41
2 years	20
3 years	20
4 years	21
5 years	21
Thereafter	223
Right-of-ways commitments
Total	1,249
Less than 1 year	35
2 years	35
3 years	35
4 years	36
5 years	37
Thereafter	1,071
Total
Total	119,324
Less than 1 year	11,716
2 years	11,364
3 years	7,579
4 years	7,048
5 years	13,597
Thereafter	$ 68,020

QUARTERLY FINANCIAL DATA (UNA_3

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - CAD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 12,470	$ 11,466	$ 10,948	$ 12,187	$ 10,008	$ 9,110	$ 7,956	$ 12,013	$ 47,071	$ 39,087	$ 50,069
Operating income	2,053	1,388	1,816	2,548	2,251	2,095	2,098	1,513	7,805	7,957	8,260
Earnings/(loss)	1,965	814	1,521	2,014	1,899	1,104	1,777	(1,364)	6,314	3,416	5,827
Earnings/(loss) attributable to controlling interests	1,933	780	1,484	1,992	1,871	1,084	1,741	(1,333)	6,189	3,363	5,705
Earnings/(loss) attributable to common shareholders	$ 1,840	$ 682	$ 1,394	$ 1,900	$ 1,775	$ 990	$ 1,647	$ (1,429)	$ 5,816	$ 2,983	$ 5,322
Earnings/(loss) per common share
Earnings/(loss) per common share attributable to common shareholders (in CAD per share)	$ 0.91	$ 0.34	$ 0.69	$ 0.94	$ 0.88	$ 0.49	$ 0.82	$ (0.71)	$ 2.87	$ 1.48	$ 2.64
Diluted earnings/(loss) per common share attributable to common shareholders (in CAD per share)	$ 0.91	$ 0.34	$ 0.69	$ 0.94	$ 0.88	$ 0.49	$ 0.82	$ (0.71)	$ 2.87	$ 1.48	$ 2.63