AltaGas (ATGFF) 40-F 26 Feb 21 2020 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2020shares
Document Information [Line Items]
Document Type	40-F
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2020
Entity File Number	333-225606
Entity Registrant Name	ALTAGAS LTD.
Entity Incorporation, State or Country Code	Z4
Entity Address, Address Line One	1700, 355-4th Avenue SW
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Postal Zip Code	T2P 0J1
City Area Code	403
Local Phone Number	691-7575
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	279,494,299
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Amendment Flag	false
Entity Central Index Key	0001695519
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Document Registration Statement	false
Entity Primary SIC Number	1311
Business Contact
Document Information [Line Items]
Entity Address, Address Line One	1000 Maine Ave.
Entity Address, City or Town	Washington
Entity Address, State or Province	DC
Entity Address, Postal Zip Code	20024
City Area Code	703
Local Phone Number	750-4400
Contact Personnel Name	AltaGas Services (U.S.) Inc.

Consolidated Balance Sheets

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents (note 31)	$ 32	$ 57
Accounts receivable (net of credit losses of $41 million) (notes 10 and 23)	1,444	1,222
Inventory (note 7)	636	506
Restricted cash holdings from customers (note 31)	3	4
Regulatory assets (note 21)	46	13
Risk management assets (note 23)	98	87
Prepaid expenses and other current assets (notes 28 and 31)	234	280
Assets held for sale (note 5)	4	27
Total current assets	2,497	2,196
Property, plant and equipment (note 8)	10,888	10,125
Intangible assets (note 9)	539	586
Operating right-of-use assets (note 10)	372	170
Goodwill (note 11)	5,039	3,942
Regulatory assets (note 21)	444	487
Risk management assets (note 23)	47	39
Restricted cash holdings from customers (note 31)	2	4
Prepaid post-retirement benefits (note 28)	572	487
Long-term investments and other assets (net of credit losses of $3 million) (notes 12, 28, and 31)	245	297
Investments accounted for by the equity method (note 14)	887	1,462
Total assets	21,532	19,795
Current liabilities
Accounts payable and accrued liabilities (notes 17, 18, 23, and 28)	1,561	1,325
Dividends payable (note 23)	22	22
Short-term debt (notes 15 and 23)	256	460
Current portion of long-term debt (notes 16 and 23)	360	923
Customer deposits	73	76
Regulatory liabilities (note 21)	90	146
Risk management liabilities (note 23)	111	125
Operating lease liabilities (note 10)	95	27
Other current liabilities (note 23)	38	17
Liabilities associated with assets held for sale (note 5)	1	4
Total current liabilities	2,607	3,125
Long-term debt (notes 16 and 23)	7,626	5,928
Asset retirement obligations (note 17)	379	362
Unamortized investment tax credits (note 20)	3	4
Deferred income taxes (note 20)	1,118	959
Regulatory liabilities (note 21)	1,381	1,383
Risk management liabilities (note 23)	145	167
Operating lease liabilities (note 10)	304	153
Other long-term liabilities (notes 19 and 23)	153	102
Future employee obligations (note 28)	155	243
Total liabilities	13,871	12,426
Shareholders' equity
Common shares, no par values, unlimited shares authorized;    2020 - 279.5 million and 2019 - 279.1 million issued and outstanding (note 25)	6,723	6,719
Preferred shares (note 25)	1,077	1,277
Contributed surplus	383	377
Accumulated deficit	(1,192)	(1,403)
Accumulated other comprehensive income (AOCI) (note 22)	50	245
Total shareholders' equity	7,041	7,215
Non-controlling interests	620	154
Total equity	7,661	7,369
Total liabilities and shareholders' equity	$ 21,532	$ 19,795

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Accounts receivable, allowance for credit loss, current	$ 41	$ 41
Long-term investments and other assets, credit losses	$ 3	$ 3
Common shares (note 25)
Common shares outstanding (shares)	279,500,000	279,074,685
Common shares issued (shares)	279,500,000	279,100,000

Consolidated Statements of Inco

Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
REVENUE (note 24)	$ 5,587	$ 5,495
EXPENSES
Cost of sales, exclusive of items shown separately	3,178	3,227
Operating and administrative	1,267	1,299
Accretion expenses (note 17)	5	5
Depreciation and amortization (notes 8 and 9)	414	438
Provisions on assets (note 6)	109	416
Total expenses	4,973	5,385
Income from equity investments (note 14)	49	141
Other income (note 27)	306	908
Foreign exchange gains (losses)	4	(1)
Interest expense	(274)	(346)
Income before income taxes	699	812
Income tax expense (recovery) (note 20)
Current	1	63
Deferred	126	(91)
Net income after taxes	572	840
Net income applicable to non-controlling interests	20	7
Net income applicable to controlling interests	552	833
Preferred share dividends	(66)	(68)
Gain on redemption of preferred shares (note 25)	0
Net income applicable to common shares	$ 486	$ 769
Net income per common share (note 26)
Basic (per share)	$ 1.74	$ 2.78
Diluted (per share)	$ 1.74	$ 2.77
Weighted average number of common shares    outstanding (millions) (note 26)
Basic (shares)	279.4	276.9
Diluted (shares)	279.7	277.4

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net income after taxes	$ 572	$ 840
Other comprehensive income (loss), net of taxes
Loss on foreign currency translation	(175)	(406)
Unrealized gain (loss) on net investment hedge (note 23)	(9)	60
Actuarial gain (loss) on pension plans and post-retirement benefit (PRB) plans (note 28)	(8)	12
Reclassification of actuarial gains and prior service credits on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 28)	2	1
Other comprehensive loss from equity investees	(5)	(1)
Total other comprehensive loss (OCI), net of taxes (note 22)	(195)	(334)
Comprehensive income attributable to controlling interests and non-controlling interests, net of taxes	377	506
Comprehensive income attributable to:
Non-controlling interests	20	7
Controlling interests	$ 357	$ 499

Consolidated Statements of Equi

Consolidated Statements of Equity - CAD ($) $ in Millions		Total	Total shareholders' equity	Common shares (note 25)	Preferred shares (note 25)	Contributed surplus	Accumulated deficit	Accumulated deficitCumulative Effect, Period of Adoption, Adjustment	AOCI (note 22)	Non-controlling interests
Balance, beginning of year at Dec. 31, 2018				$ 6,654	$ 1,319	$ 373	$ (1,905)		$ 579	$ 620
Increase (Decrease) in Stockholders' Equity
Exercise of share options				1
Shares issued under DRIP	[1]			68
Deferred taxes on share issuance costs				(4)	(1)
Redemption of preferred shares					(41)
Share options expense						4
Net income applicable to controlling interests		$ 833					833
Common share dividends							(267)
Preferred share dividends							(68)
Gain on redemption of preferred shares							4
Accounting Standards Update [Extensible List]		us-gaap:AccountingStandardsUpdate201613Member
Other comprehensive loss		$ (334)							(334)
Net income applicable to non-controlling interests		7								7
Adjustment on disposition of assets										(508)
Contributions from non-controlling interests to subsidiaries										48
Distributions by subsidiaries to non-controlling interests										(13)
Balance, end of year at Dec. 31, 2019		7,369	$ 7,215	6,719	1,277	377	(1,403)	$ (7)	245	154
Increase (Decrease) in Stockholders' Equity
Exercise of share options				1
Shares issued under DRIP	[1]			6
Deferred taxes on share issuance costs				(3)
Redemption of preferred shares					(200)
Share options expense						6
Net income applicable to controlling interests		552					552
Common share dividends							(268)
Preferred share dividends							(66)
Gain on redemption of preferred shares		0
Other comprehensive loss		(195)							(195)
Net income applicable to non-controlling interests		20								20
Contributions from non-controlling interests to subsidiaries										7
Distributions by subsidiaries to non-controlling interests										(28)
Acquisition of non-controlling interests through Petrogas Acquisition (note 3)										467
Balance, end of year at Dec. 31, 2020		$ 7,661	$ 7,041	$ 6,723	$ 1,077	$ 383	$ (1,192)		$ 50	$ 620
[1]	Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP). The plan was suspended in December 2019, with the December dividend (paid January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash from (used by) operations
Net income after taxes	$ 572	$ 840
Items not involving cash:
Depreciation and amortization (notes 8 and 9)	414	438
Provisions on assets (note 6)	109	416
Accretion expenses (note 17)	5	5
Share-based compensation (note 25)	6	4
Deferred income tax expense (recovery) (note 20)	126	(91)
Gains on sale of assets (notes 4 and 27)	(223)	(876)
Gain on remeasurement of previously held interest in AIJVLP (note 3)	(22)	0
Income from equity investments (note 14)	(49)	(141)
Unrealized losses (gains) on risk management contracts (note 23)	(21)	85
Losses on investments (note 27)	0	4
Amortization of deferred financing costs	8	12
Provision for doubtful accounts	25	27
Change in pension and other post-retirement benefits (note 28)	(11)	8
Other	15	9
Asset retirement obligations settled (note 17)	(4)	(2)
Distributions from equity investments	26	110
Changes in operating assets and liabilities (note 31)	(203)	(232)
Net cash provided (required) by operating activities	773	616
Investing activities
Business acquisitions, net of cash acquired (note 3)	(675)	0
Capital expenditures - property, plant and equipment	(825)	(1,296)
Capital expenditures - intangible assets	(18)	(38)
Contributions to equity investments	(72)	(179)
Change in loan to affiliate	(75)	0
Proceeds from disposition of equity investments (note 14)	376	0
Proceeds from sale of investments in publicly-traded entities	4	0
Proceeds from disposition of assets, net of transaction costs (note 4)	74	3,624
Proceeds from disposition of financing receivable	0	73
Net cash provided (required) by investing activities	(1,211)	2,184
Financing activities
Net repayment of short-term debt	(157)	(701)
Issuance of long-term debt, net of debt issuance costs	1,962	889
Repayment of long-term debt	(1,056)	(873)
Net borrowing (repayment) under credit facilities	191	(1,921)
Dividends - common shares	(268)	(266)
Dividends - preferred shares	(66)	(68)
Distributions to non-controlling interest	(28)	(13)
Contributions from non-controlling interests	7	48
Net proceeds from shares issued on exercise of options	1	1
Net proceeds from issuance of common shares	6	68
Redemption of preferred shares (note 25)	(200)	(38)
Net cash provided (required) by financing activities	392	(2,874)
Change in cash, cash equivalents, and restricted cash	(46)	(74)
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	(2)	(9)
Net change in cash classified within assets held for sale	0	4
Cash, cash equivalents, and restricted cash beginning of year	122	201
Cash, cash equivalents, and restricted cash end of year (note 31)	$ 74	$ 122

Organization and Overview of th

Organization and Overview of the Business	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Overview of the Business	Organization and Overview of the Business The businesses of AltaGas are operated by the Company and a number of its subsidiaries including, without limitation, AltaGas Services (U.S.) Inc., AltaGas Utility Holdings (U.S.) Inc., WGL Holdings, Inc. (WGL), Wrangler 1 LLC, Wrangler SPE LLC, Washington Gas Resources Corporation, WGL Energy Services, Inc. (WGL Energy Services), and SEMCO Holding Corporation; in regard to the Utilities business, Washington Gas Light Company (Washington Gas), Hampshire Gas Company, and SEMCO Energy, Inc. (SEMCO); in regard to the Midstream business, AltaGas Extraction and Transmission Limited Partnership, AltaGas Pipeline Partnership, AltaGas Processing Partnership, AltaGas Northwest Processing Limited Partnership, Harmattan Gas Processing Limited Partnership, Ridley Island LPG Export Limited Partnership, and WGL Midstream Inc. (WGL Midstream); and, in regard to remaining assets in the Corporate/Other segment, AltaGas Power Holdings (U.S.) Inc., WGL Energy Systems, Inc. (WGL Energy Systems), and Blythe Energy Inc. (Blythe). SEMCO conducts its Michigan natural gas distribution business under the name SEMCO Energy Gas Company (SEMCO Gas), its Alaska natural gas distribution business under the name ENSTAR Natural Gas Company (ENSTAR) and its 65 percent interest in an Alaska regulated gas storage utility under the name Cook Inlet Natural Gas Storage Alaska LLC (CINGSA). Petrogas Energy Corporation (Petrogas) was also added as a subsidiary of AltaGas upon the close of the acquisition on December 15, 2020. AltaGas, a Canadian corporation, is a leading North American energy infrastructure company that connects natural gas liquids (NGLs) and natural gas to domestic and global markets. The Corporation’s long-term strategy is to grow in attractive areas across its Utilities and Midstream business segments seeking optimal capital deployment. In the Midstream business, the Corporation is focused on optimizing the full value chain of energy exports by providing producers with solutions, including global market access off the West Coast of North America via the Corporation’s footprint in the Montney region. In the Utilities business, the Corporation seeks to grow through rate base investment and the use of accelerated rate recovery programs, while providing effective and cost-efficient service for customers. In 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales completed as part of its 2019 asset monetization program. As a result of these changes, AltaGas has refocused on its core Utilities and Midstream segments. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, AltaGas has two operating segments: Utilities (which now includes the WGL retail marketing business) and Midstream. These operating segments have not been aggregated in the determination of AltaGas' reportable segments. All other assets are included in the Corporate/Other segment. AltaGas' operating segments include the following: § Utilities, which serves approximately 1.7 million customers with a rate base of approximately US$4.3 billion through ownership of regulated natural gas distribution utilities across five jurisdictions in the United States and two regulated natural gas storage utilities in the United States, delivering affordable natural gas to homes and businesses. The Utilities business also includes storage facilities and contracts for interstate natural gas transportation and storage services, as well as the affiliated retail energy marketing business, which serves approximately 0.5 million customers; and § Midstream, which includes a 70 percent interest in the Ridley Island Propane Export Terminal (RIPET) and an approximate 74 percent interest in the Ferndale terminal, allowing AltaGas to leverage its assets along the energy value chain in Western Canada and the Western United States including natural gas gathering and processing, NGL extraction and fractionation, and natural gas and NGL marketing. The Midstream segment also includes transmission, storage, and an interest in a regulated pipeline in the Marcellus/Utica gas formation in the northeastern United States. Upon close of the acquisition of Petrogas, the Midstream business also includes a 74 percent interest in Petrogas' other operations, which include LPG exports and distribution, domestic terminals, wellsite fluids and fuels, and trucking and liquids handling.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies BASIS OF PRESENTATION These Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). Pursuant to National Instrument 52‑107, "Acceptable Accounting Principles and Auditing Standards" (NI 52‑107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On January 21, 2020, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP. PRINCIPLES OF CONSOLIDATION These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence, but not control, over are accounted for using the equity method. Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain equity method investments as well as consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage. The majority of AltaGas' HLBV investments were sold during 2019. All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non‑controlling interest in a subsidiary that AltaGas controls, that non‑controlling interest is reflected as “non‑controlling interests” in the Consolidated Financial Statements. The non‑controlling interests in net income of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in "net income applicable to non-controlling interests". USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates; determination as to whether a contract is or contains a lease; determination of the classification, term, and discount rate for leases; fair value of asset retirement obligations; fair value of property, plant and equipment and goodwill for impairment assessments; fair value of financial instruments; measurement of credit losses; provisions for income taxes; assumptions used to measure employee future benefits; provisions for contingencies; purchase price allocations; and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas' subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. By their nature, these estimates are subject to measurement uncertainty and may impact the Consolidated Financial Statements of future periods. SIGNIFICANT ACCOUNTING POLICIES Rate-Regulated Operations SEMCO Gas, ENSTAR, Washington Gas, and Hampshire Gas (collectively the Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas and ENSTAR are regulated by the Michigan Public Service Commission (MPSC) and Regulatory Commission of Alaska (RCA), respectively. Washington Gas operates in the District of Columbia, Maryland, and Virginia, and is regulated in those jurisdictions by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD), and the Commonwealth of Virginia State Corporation Commission (SCC of VA), respectively. Hampshire is regulated under a cost-of-service tariff by the Federal Energy Regulatory Commission (FERC). The MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting, and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA, the timing of recognition of certain assets, liabilities, revenues, and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation. Regulatory assets represent future revenues associated with certain costs incurred in the current period or in prior periods that are expected to be recovered from customers in future periods through the rate setting process. Regulatory liabilities represent future reductions or limitations of increases in revenue associated with amounts that are expected to be refunded to customers through the rate setting process. Cash and Cash Equivalents Cash and cash equivalents consist of cash on hand, balances with banks, and investments in money market instruments with original maturities of less than three months. Restricted Cash Holdings from Customers Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets. Pursuant to the acquisition of WGL Holdings, Inc. (the WGL Acquisition), rabbi trust funds were funded to satisfy certain Washington Gas executive and outside director retirement benefit plan obligations. The rabbi trust funds are invested in money market funds which are considered cash equivalents. These balances are included in "prepaid expenses and other current assets" and "long-term investments and other assets" in the Consolidated Balance Sheets. Additionally, cash deposited in an escrow fund related to a cost sharing agreement with a third party has been recorded as restricted cash in “accounts receivable" in the Consolidated Balance Sheets. Please refer to Note 29 for more information. Accounts Receivable Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely. Inventory Inventory consists of materials, supplies, natural gas, natural gas liquids, crude oil and condensates, processed finished products, renewable energy credits, and emission compliance instruments which are valued at the lower of cost or net realizable value. Cost of inventory is assigned using a weighted average cost formula. In general, commodity costs and variable transportation costs are capitalized as gas in underground storage. Fixed costs, primarily pipeline demand charges and storage charges, are expensed as incurred through the cost of gas. Property, Plant, and Equipment (PP&E), Depreciation and Amortization Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight-line basis over the estimated useful life of the assets, with the exception of rate-regulated utilities assets, for which depreciation is calculated on a straight-line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities, and a small number of assets acquired as part of the acquisition of Petrogas for which depreciation is calculated using the declining balance method. The Utilities charge maintenance and repairs directly to operating expense and capitalize betterments and renewal costs. In accordance with regulatory requirements, depreciation expense includes an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs. Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas' prior quarter actual borrowing long-term interest rate. The Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate-regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses, and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators. The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 4 to 69 years Midstream assets 3 to 55 years Corporate/Other assets 3 to 46 years As required by the regulatory authority, net additions to SEMCO's utility assets are amortized for one half-year in the year in which they are brought into active service. Net additions to WGL’s assets are amortized in the month after they are brought into active service. Generally, when a regulated asset is retired or disposed of, there is no gain or loss recorded in the Consolidated Statements of Income. Any difference between the cost and accumulated depreciation of the asset, net of salvage proceeds, is charged to accumulated depreciation or another regulatory asset or liability account. It is expected that any gain or loss that is charged to accumulated depreciation or another regulatory account will be reflected in future depreciation expense when it is refunded or collected in rates. When a non-regulated asset is retired or disposed of from PP&E, the original cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in the Consolidated Statements of Income. Intangible Assets Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight-line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 years Software 3 to 20 years Land rights 5 to 43 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 to 20 years Assets Held for Sale The Corporation classifies assets as held for sale when the carrying amount will be principally recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized. Business Acquisitions Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition-related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired. Management applies its best estimates and assumptions to determine the fair value of net assets acquired; however, the estimates are subject to further refinement of assumptions over a measurement period, which may be up to one year from the acquisition date. During the measurement period, adjustments to assets acquired and liabilities assumed may be recorded, with a corresponding impact to goodwill. Provisions on Assets If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized. Goodwill is not subject to amortization, but assessed at least annually for impairment, or more often when events or changes in circumstances indicate that goodwill may be impaired. The annual assessment of goodwill is performed at the reporting unit level, which is an operating segment or one level below. The Corporation has the option to first assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill may be impaired. If a quantitative impairment test is performed, the fair value of the reporting unit will be compared to its carrying value (including goodwill). If the carrying value of the reporting unit exceeds the fair value, goodwill is reduced to its fair value and an impairment loss would be recorded in the Consolidated Statements of Income. Investments Accounted for by the Equity Method The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period. The HLBV methodology is used to allocate earnings or losses for certain WGL equity method investments when WGL’s ownership interest percentage is different than distribution percentages. When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity's book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period. An equity method investment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. When such condition is deemed other than temporary, the carrying value of the investment is written down to its fair value, and an impairment charge is recorded in the Consolidated Statements of Income. Financial Instruments Non-Utility Operations All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as "held-for-trading", "held-to-maturity", or "loans and receivables". Financial liabilities are classified as "held-for-trading" or other financial liabilities. Subsequent measurement is determined by classification. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Held-for-trading instruments include non-derivative financial assets and financial assets and liabilities that may consist of swaps, options, forwards, and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method unless they are held-for-sale and recognized at the lower of cost or fair value less transaction fees. Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statements of Income under "other income". Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative, and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings. The fair values recorded on the Consolidated Balance Sheets reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Transaction costs related to the acquisition of held-for-trading financial assets and liabilities are expensed as incurred. Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheets. Transaction costs related to line-of-credit arrangements are capitalized and included under "long-term investments and other assets" on the Consolidated Balance Sheets. Premiums and discounts are netted against long-term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “interest expense” on the Consolidated Statements of Income. Regulated Utility Operations All physical and financial derivative contracts are initially recorded at fair value. Changes in the fair value of derivative instruments that are recoverable or refunded to customers when they settle are recorded as regulatory assets or liabilities. Changes in the fair value of derivatives not affected by rate regulation are reflected in net income. Transaction costs for obtaining debt financing and reacquired debt costs are recorded as regulatory assets or liabilities, or as a reduction of the debt liability on the Consolidated Balance Sheets. Weather-Related Instruments WGL purchases certain weather-related instruments, such as heating degree day (HDD) derivatives and cooling degree day (CDD) derivatives to manage weather and price risks related to its natural gas and electricity sales. These derivatives are accounted for in accordance with ASC 815-45, Derivatives and Hedging – Weather Derivatives. For HDD derivatives, gains or losses are recognized when the actual HDD’s falls above or below the contractual HDD’s for each instrument. For CDD derivatives, gains or losses are recognized when the average temperature exceeds or is below a contractually stated level during the contract period. Refer to Note 23 for further discussion on weather-related instruments. Hedges As part of its risk management strategy, AltaGas may use derivatives to reduce its exposure to commodity price, interest rate, and foreign exchange risk. AltaGas may designate certain U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. No other derivatives have been designated as hedges under ASC Topic 815. Non-Utility Operations The change in fair value of cash flow hedges is recognized in OCI. Gains or losses from cash flow hedges are reclassified to net income when the hedged transaction affects earnings, such as when the hedged forecasted transaction occurs. Regulated Utility Operations During planned issuances of debt securities, Washington Gas may utilize derivative instruments to manage the risk of interest-rate volatility. Gains and losses associated with these types of derivatives are recorded as regulatory liabilities or assets, and amortized in accordance with regulatory requirements, typically over the life of the related debt. Credit Losses The following are the Corporation's significant accounting policies upon adoption of ASC 326: Accounts receivable, contract assets, a loan to an affiliate, and other long-term receivables within the scope of ASC 326 are recorded net of the allowance for credit losses in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for credit losses is adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely. See below for a description of how expected credit loss estimates are developed. Utilities Customer Receivables and Contract Assets AltaGas is exposed to risk through the non-payment of utility bills by customers. To manage this customer credit risk, AltaGas' regulated utilities customers are offered budget billing options or high risk customers may be required to provide a cash deposit until the requirement for deposit refunds are met. AltaGas can recover a portion of non-payments from customers in future periods through the rate-setting process. For accounts receivable generated by the Utilities business, an allowance for credit losses is recorded against revenue and is recognized using a historical loss-rate based on historical payment and collection experience. This rate may be adjusted based on Management’s expectations of unusual macroeconomic conditions and other factors. AltaGas regularly evaluates the reasonableness of the allowance based on a combination of factors, such as: the length of time receivables are past due, historical expected payment, collection experience, financial condition of customers, and other circumstances that could impact customers' ability or desire to make payments. For retail energy marketing customer receivables where AltaGas has enrolled in a regulatory utility purchase of receivable program, the associated utility discount rate is used to determine credit losses. Midstream Customer Receivables and Contract Assets AltaGas operates under an existing credit policy that is designed to mitigate credit risk. Credit limits are established for each counterparty and credit enhancements such as letters of credit, parent guarantees, and cash collateral may be required. The creditworthiness of all counterparties is continuously monitored. A credit loss reserve is recorded for receivables with customers and trading counterparties AltaGas considers to be below investment grade by applying an estimated loss rate. The estimated loss rate is based on the historical default rates published by external rating agencies. For accounts receivable, a one-year rate is used. For contract assets, historical loss rates associated with the estimated time frame that the contract asset will be billed to the customer is used. In the event a customer or trading counterparty no longer exhibits similar risk characteristics, the associated receivable is evaluated individually. Other For other long-term receivables, associated counterparties are evaluated and assigned internal credit ratings based on AltaGas' credit policy. An allowance for credit losses is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivables are expected to be collected. Debt AltaGas uses short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Short-term obligations are excluded from current liabilities if AltaGas has the ability and the intent to refinance these obligations on a long-term basis. The ability to refinance is primarily demonstrated through the availability of long-term revolving committed credit facilities in an amount equal to or greater than the expected maximum short-term obligation. Asset Retirement Obligations AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations. There are timing differences between accretion and depreciation amounts being recorded pursuant to GAAP and the recognition of depreciation expense for legal asset removal costs that are recovered in rates, as allowed by the regulators. These timing differences are recorded as a reduction to “regulatory liabilities” in accordance with ASC 980. Certain midstream and utility assets will have future legal obligations on retirement, but an asset retirement obligation has not been recorded due to its indeterminate life and corresponding indeterminable timing and scope of these asset retirement obligations. The Utilities recognize asset retirement obligations for some interim retirements, as expected by their regulators. Revenue Recognition AltaGas has revenue from various sources, including rate-regulated revenue, commodity sales, midstream service contracts, gas sales and transportation services, and storage services. For a detailed description of the Corporation’s revenue recognition policy by major source of revenue, please refer to Note 24. Foreign Currency Translation Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statements of Income. Non-monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date. For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI. AltaGas may designate some of its U.S. dollar denominated long-term debt as a foreign currency hedge of its investment in foreign operations. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of the U.S. dollar denominated long-term debt are included in OCI. Share Options and Other Compensation Plans Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity. AltaGas has a phantom unit plan (Phantom Plan, formerly the medium-term incentive plan) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). A portion of AltaGas’ RUs and PUs are valued based on the dividends declared during the vesting period and the weighted average share price of AltaGas' common shares multiplied by the units outstanding at the end of the vesting period. Upon vesting, the RUs and PUs are paid in cash. The other portion of RUs and PUs are valued at US$1 per unit. Upon vesting, the RUs and PUs are paid in cash. All PUs are also subject to a performance multiplier ranging from 0 to 2.4 dependent on the Corporation's performance relative to performance targets as approved by the Board of Directors. Compensation expense is recognized using the liability method and is recorded as operating and administrative expense over the vesting period. A change in value of the RUs or PUs is recognized in the period the change occurs. In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers, and employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers, and employees, AltaGas currently only grants deferred share units (DSUs) under the DSUP as a form of director compensation. The DSUs granted are fully vested upon being credited to a participant’s account, the participant is entitled to payment upon retirement, and payment is not subject to satisfaction of any requirements as to any minimum period of membership or employment or other conditions. DSUs are accounted for at fair value. Compensation expense is determined based on the fair value of the DSUs on the date of the grant and fluctuations in fair value are recognized in the period the change occurs. Pension Plans and Post-Retirement Benefits AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs. The cost of defined benefit pension plans and post-retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees, expected health care costs, and other actuarial factors including discount rates and mortality. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets or the market-related value of assets along with any unamortized past service costs and credits are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post-retirement benefit plans is 10.2 years and 13.0 years, respectively. AltaGas recognizes the overfunded or underfunded status of its pension and post-retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheets. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI or a regulatory asset or liability. For certain regulated utilities, the Corporation expects to recover pension expense in future rates and therefore records unrecognized balances as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees. In 2020, AltaGas made a voluntary change in accounting principle for calculating the market-related value of assets (MRVA) used in the determination of Washington Gas' net periodic pension and other post-retirement benefit plan costs. The change uses the fair value approach for the fixed income

Acquisition of Petrogas Energy

Acquisition of Petrogas Energy Corporation	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Acquisition of Petrogas Energy Corporation	Acquisition of Petrogas Energy Corporation On December 15, 2020, following the receipt of all required approvals, AltaGas acquired an additional 37 percent of Petrogas Energy Corp. (the Petrogas Acquisition) for total cash consideration upon close of approximately $715 million. Additional post-acquisition contingent payments of up to $16 million may be paid no later than 2022 based on certain criteria, including earnings targets being met (Note 29). AltaGas funded the transaction through draws on its existing credit facilities. As a result of the transaction, AltaGas' ownership in Petrogas has increased to approximately 74 percent with Idemitsu Kosan Co., Ltd. (Idemitsu) owning the remaining approximately 26 percent. Subsequent to the transaction, AltaGas controls Petrogas and as such, Petrogas results have been consolidated for the period subsequent to close. This acquisition is consistent with AltaGas' global export strategy, growing Midstream operations, and corporate focus on building a diversified, low-risk, high-growth Utilities and Midstream business. The transaction provides AltaGas with operational responsibility of strategic assets that, along with the Ridley Island Propane Export Terminal and existing Midstream assets, position the Company to capture efficiencies that are expected to accrue to shareholders and customers. AltaGas accounted for the acquisition as a business combination achieved in stages and re-measured it's previously held 37 percent equity investment in Petrogas at an acquisition date fair value of $631 million, resulting in a gain of $22 million. The fair value of assets and liabilities acquired were determined using a combination of income and cost approach. The fair value of the previously held interest and non-controlling interests were derived from the valuation of the assets and liabilities including considerations for expected synergies. Prior to the acquisition, AltaGas' indirect non-controlling interest in Petrogas was accounted for as an investment accounted for by the equity method (Note 14). The following table summarizes the preliminary purchase price allocation representing the consideration paid and the estimated fair value of the net assets acquired as at December 15, 2020. The purchase price allocation is preliminary and reflects Management’s current best estimate of the fair value of Petrogas' assets and liabilities based on the analysis of information obtained to date. Management is continuing to obtain specific information to support the valuation of property, plant and equipment, intangibles, investments accounted for by the equity method, non-controlling interest, contingencies, income taxes, environmental matters and asset retirement obligations. As additional information becomes available, the purchase price allocation may differ materially from the preliminary purchase price allocation below. The offset to any adjustments made to the aforementioned financial statement captions during the measurement period are expected to be recorded in goodwill. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition. Fair value of previously held interest in AltaGas Idemitsu Joint Venture LP (AIJVLP) on the acquisition date $ 631 Less: Carrying value of previously held interest in AIJVLP (609) Gain on re-measurement of previously held interest $ 22 Purchase consideration for an additional 37 percent of Petrogas $ 715 Deemed settlement of intercompany debt 120 Fair value of previously held interest on the acquisition date 631 Less: Fair value assigned to net assets Current assets 536 Property, plant and equipment 523 Intangible assets 10 Operating right-of-use assets 192 Long-term investments and other assets 4 Investments accounted for by the equity method 125 Current liabilities (363) Long-term debt (53) Asset retirement obligations (13) Deferred income taxes (21) Operating lease liabilities (152) Other long-term liabilities (26) Fair value of net assets acquired $ 762 Fair value of AIJVLP's non-controlling interest in Petrogas on the acquisition date 467 Goodwill $ 1,171 The fair value of AIJVLP's non-controlling interest in Petrogas at the acquisition date was $467 million, which was determined in the same manner described for the previously held investments. Included in the fair value calculation are synergies that AltaGas expects to achieve as part of the acquisition. The synergies are broken down into items that will accrue to Petrogas versus other AltaGas businesses. AltaGas operates businesses that are similar in nature to Petrogas and expects some of the synergies to impact assets such as RIPET and other processing facilities. The allocation of synergies to the various businesses is currently based on the expectations that existed as of the acquisition date. Further refinement of the synergies will occur as the businesses are integrated and assessed by AltaGas’ management. New allocations of synergies will be carefully assessed to determine their impact on the purchase price allocation. The fair value of property, plant and equipment was estimated using the valuation methodologies described in ASC 820, Fair Value Measurements and Disclosures, to value the property, plant and equipment purchased. The preliminary fair value of Petrogas' property, plant and equipment was determined using both the income and cost approaches. The acquired intangible assets consist primarily of the fair value of contractual arrangements for the purchase and sale of commodities. These intangibles have been valued using the income approach. Investments accounted for by the equity method include Petrogas' 50 percent equity interest in Petrogas Terminals Penn LLC, and 40 percent equity interest in Strathcona Storage LP. The preliminary fair value of these investments was determined using an income approach. The fair value of current assets and current liabilities approximate their carrying values due to their short-term nature, with the exception of inventory. Inventory of $164 million has been recorded at it's fair value using the expected selling prices and reasonable adjustments for the current location of the products. A contingent liability related to a property tax dispute has been recorded as part of the purchase price allocation. This preliminary amount represents management’s best estimate of the fair value of the contingent liability and has been included in current liabilities. This item is included in the preliminary purchase price allocation as the hearings on the matter will occur over the next 12 months and the outcome will be settled. Right of use assets and lease liabilities have been recorded for operating leases. The right of use assets have been adjusted to reflect the market lease rates at the acquisition date and resulted in a reduction of the acquired right of use assets. Deferred income tax assets and liabilities have been applied on the cumulative amount of tax applicable to temporary differences between the accounting and tax values of assets and liabilities and are considered preliminary. The preliminary purchase price allocation includes goodwill of approximately $1.2 billion. The goodwill is primarily related to the opportunities to grow the LPG export business, expanded access to capital and greater financial flexibility as a result of increased scale, and earnings diversification. The goodwill recognized as part of this transaction is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to this goodwill. Pre-tax acquisition expenses for the year ended December 31, 2020 of approximately $6 million were incurred and included in the Consolidated Statements of Income. Upon completion of the Petrogas Acquisition, AltaGas began consolidating Petrogas. For the period from close of the transaction through December 31, 2020, Petrogas has generated approximately $143 million in revenues and $3 million in net income after taxes. The following supplemental unaudited, pro forma consolidated financial information for the years ended December 31, 2020 and 2019 gives effect to the Petrogas Acquisition as if it had closed on January 1, 2019. This pro forma information is presented for information purposes only and does not purport to be indicative of the results that would have occurred had the Petrogas Acquisition taken place at the beginning of 2019, nor is it indicative of the results that may be expected in future periods. Year Ended December 31 2020 2019 Pro forma revenue $ 7,917 $ 9,217 Pro forma net income after tax $ 537 $ 1,004 Pro forma net income after taxes excludes all non-recurring acquisition-related expenses incurred by AltaGas and Petrogas. Pro forma net income after taxes was also adjusted to exclude AltaGas' equity earnings from Petrogas prior to the acquisition, finance costs associated with credit facilities used to fund the Petrogas Acquisition, as well as the associated tax impacts. For the year ended December 31, 2020, the total after-tax pro forma adjustments decreased net income after taxes by $31 million (2019 – $75 million).

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2020
Discontinued Operations and Disposal Groups [Abstract]
Dispositions	Dispositions AltaGas Canada Inc. (ACI) On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of ACI for $33.50 per share. AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately $369 million upon close. For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $206 million in the Consolidated Statements of Income under the line item "other income". Following a name change in connection with the arrangement, ACI changed its name to TriSummit Utilities Inc. Distributed Generation Assets In 2019, AltaGas closed the disposition of its portfolio of U.S. distributed generation assets. The majority of assets were transferred in 2019, except for one project for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities relating to this project remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2020 (Note 5). For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $9 million in the Consolidated Statements of Income under the line item "other income" related to projects transferred in 2020. In addition, AltaGas recorded a pre-tax provision of $3 million related to the remaining U.S. distributed generation project which has not yet transferred to the purchaser (Note 6). The purchaser was entitled to after-tax earnings from the distributed generation projects, including the project awaiting consent, beginning September 1, 2019. Harmattan Land Parcels In the second quarter of 2020, AltaGas completed the sale of land parcels located near the Harmattan gas processing plant for gross cash proceeds of approximately $3 million. There was no gain or loss resulting from this disposition. Pomona Energy Storage Facility and Ripon Gas-fired Facility In the third quarter of 2020, AltaGas completed the sales of AltaGas Pomona Energy Storage Inc. and land related to a gas-fired power generation facility in the U.S., as well as a gas fired facility in Ripon, California, for aggregate gross cash proceeds, before working capital and other adjustments, of approximately $67 million. AltaGas recognized a pre-tax gain on these dispositions of approximately $8 million in the Consolidated Statements of Income under the line item "other income". As at December 31, 2020 December 31, 2019 Assets held for sale Property, plant and equipment $ 4 $ 22 Operating right-of-use assets — 1 Goodwill — 1 Other long-term assets — 3 $ 4 $ 27 Liabilities associated with assets held for sale Unamortized investment tax credits $ 1 $ 3 Operating lease liabilities - long-term — 1 $ 1 $ 4 Distributed Generation Assets In 2019, AltaGas announced that it entered into a definitive agreement for the sale of its portfolio of U.S. distributed generation assets (Note 4). The transaction closed in September 2019; however, there is one project for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities related to this project remains classified as held for sale at December 31, 2020, which resulted in the reclassification of $4 million of assets to assets held for sale and $1 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. The portion of the purchase price relating to this project is approximately $4 million (US$3

Assets Held For Sale

Assets Held For Sale	12 Months Ended
	Dec. 31, 2020
Discontinued Operations and Disposal Groups [Abstract]
Assets Held For Sale	Dispositions AltaGas Canada Inc. (ACI) On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of ACI for $33.50 per share. AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately $369 million upon close. For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $206 million in the Consolidated Statements of Income under the line item "other income". Following a name change in connection with the arrangement, ACI changed its name to TriSummit Utilities Inc. Distributed Generation Assets In 2019, AltaGas closed the disposition of its portfolio of U.S. distributed generation assets. The majority of assets were transferred in 2019, except for one project for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities relating to this project remain classified as held for sale on the Consolidated Balance Sheets as at December 31, 2020 (Note 5). For the year ended December 31, 2020, AltaGas recognized a pre-tax gain on disposition of approximately $9 million in the Consolidated Statements of Income under the line item "other income" related to projects transferred in 2020. In addition, AltaGas recorded a pre-tax provision of $3 million related to the remaining U.S. distributed generation project which has not yet transferred to the purchaser (Note 6). The purchaser was entitled to after-tax earnings from the distributed generation projects, including the project awaiting consent, beginning September 1, 2019. Harmattan Land Parcels In the second quarter of 2020, AltaGas completed the sale of land parcels located near the Harmattan gas processing plant for gross cash proceeds of approximately $3 million. There was no gain or loss resulting from this disposition. Pomona Energy Storage Facility and Ripon Gas-fired Facility In the third quarter of 2020, AltaGas completed the sales of AltaGas Pomona Energy Storage Inc. and land related to a gas-fired power generation facility in the U.S., as well as a gas fired facility in Ripon, California, for aggregate gross cash proceeds, before working capital and other adjustments, of approximately $67 million. AltaGas recognized a pre-tax gain on these dispositions of approximately $8 million in the Consolidated Statements of Income under the line item "other income". As at December 31, 2020 December 31, 2019 Assets held for sale Property, plant and equipment $ 4 $ 22 Operating right-of-use assets — 1 Goodwill — 1 Other long-term assets — 3 $ 4 $ 27 Liabilities associated with assets held for sale Unamortized investment tax credits $ 1 $ 3 Operating lease liabilities - long-term — 1 $ 1 $ 4 Distributed Generation Assets In 2019, AltaGas announced that it entered into a definitive agreement for the sale of its portfolio of U.S. distributed generation assets (Note 4). The transaction closed in September 2019; however, there is one project for which ownership will not legally transfer to the purchaser until various consents and approvals are obtained. As such, the carrying value of the assets and liabilities related to this project remains classified as held for sale at December 31, 2020, which resulted in the reclassification of $4 million of assets to assets held for sale and $1 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. The portion of the purchase price relating to this project is approximately $4 million (US$3

Provisions on Assets

Provisions on Assets	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Provisions on Assets	Provisions on Assets Year Ended December 31 2020 2019 Midstream $ 106 $ 34 Corporate/Other 3 382 $ 109 $ 416 Midstream In 2020, AltaGas recorded pre-tax provisions of $106 million. Of this, approximately $104 million related to the Alton Natural Gas Storage Project, which was impaired as AltaGas does not believe that the future expected cash generation from the project aligns with the current carrying value. The remaining $2 million pre-tax provision related to land parcels located near the Harmattan gas processing plant which were sold in the second quarter of 2020 (Note 4). The pre-tax provisions were recorded against property, plant and equipment. In 2019, AltaGas recorded pre-tax provisions of $34 million related to a sour gas treatment facility in Alberta. Corporate/Other In 2020, AltaGas recorded pre-tax provisions totaling $3 million related to the remaining U.S. distributed generation projects which have not yet transferred to the purchaser and are classified as held for sale as at December 31, 2020. The pre-tax provisions were recorded against property, plant and equipment. In 2019, AltaGas recorded pre-tax provisions of $382 million related to various assets in the Corporate/Other segment.

Inventory

Inventory	12 Months Ended
	Dec. 31, 2020
Inventory Disclosure [Abstract]
Inventory	Inventory As at December 31 2020 2019 Natural gas held in storage (a) $ 309 $ 359 Natural gas liquids 116 26 Materials and supplies 84 57 Renewable energy credits and emission compliance instruments 80 64 Crude oil and condensate 43 — Processed finished products 4 — $ 636 $ 506 (a) As at December 31, 2020, $193 million of the natural gas held in storage was held by rate-regulated utilities (2019 - $214 million).

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment As at December 31, 2020 December 31, 2019 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value Utilities $ 7,791 $ (286) $ 7,505 $ 7,316 $ (155) $ 7,161 Midstream 4,094 (951) 3,143 3,182 (585) 2,597 Corporate/Other 842 (598) 244 1,025 (636) 389 Reclassified to assets held for sale (4) — (4) (24) 2 (22) $ 12,723 $ (1,835) $ 10,888 $ 11,499 $ (1,374) $ 10,125 Interest capitalized on long-term capital construction projects for the year ended December 31, 2020 was $6 million (2019 - $15 million). As at December 31, 2020, the Corporation had approximately $457 million (December 31, 2019 - $725 million) of capital projects under construction that were not yet subject to amortization.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible Assets As at December 31, 2020 December 31, 2019 Cost Accumulated Net book Cost Accumulated Net book E&T contracts $ 26 $ (16) $ 10 $ 27 $ (15) $ 12 Electricity service agreements — — — 9 (8) 1 Energy services relationships 90 (45) 45 91 (27) 64 Software 304 (133) 171 304 (102) 202 Land rights 1 — 1 1 — 1 Commodity contracts 332 (20) 312 327 (21) 306 $ 753 $ (214) $ 539 $ 759 $ (173) $ 586 Amortization expense related to intangible assets for the year ended December 31, 2020 was $68 million (2019 - $80 million). As at December 31, 2020, the Corporation excluded $176 million (December 31, 2019 - $185 million) from the asset base subject to amortization. Items excluded relate to gas transportation capacity contracts, software assets under development, and assets with an indefinite life. The following table sets forth the estimated amortization expense of intangible assets, excluding any amortization of assets not yet subject to amortization as well as assets with an indefinite life, for the years ended December 31: 2021 $ 75 2022 $ 72 2023 $ 60 2024 $ 39 2025 $ 15 Thereafter $ 102

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Leases	Leases Lessee AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land. The components of lease expense were as follows: Year Ended Year Ended Operating lease cost (includes variable lease payments) $ 43 $ 29 Finance lease cost Amortization of right-of-use assets $ 4 $ 4 Total finance lease cost $ 4 $ 4 Total lease cost $ 47 $ 33 Supplemental cash flow information related to leases was as follows: Year Ended December 31 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ (36) $ (21) Financing cash flows from finance leases (a) $ (4) $ (4) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 227 $ 50 Finance leases $ 6 $ 5 (a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows. Supplemental balance sheet information related to leases was as follows: As at December 31 2020 2019 Operating Leases Operating lease right-of-use assets Long-term $ 372 $ 170 Total operating lease right-of-use assets $ 372 $ 170 Operating lease liabilities Current $ (95) $ (27) Long-term (304) (153) Total operating lease liabilities $ (399) $ (180) Finance Leases Property and equipment, gross $ 19 $ 13 Accumulated depreciation (7) (3) Property and equipment, net $ 12 $ 10 Current portion of long-term debt $ (4) $ (4) Long-term debt (8) (6) Total finance lease liabilities $ (12) $ (10) As at December 31, December 31, Weighted average remaining lease term (years) Operating leases 7.4 10.9 Finance leases 4.8 5.2 Weighted average discount rate (%) Operating leases 2.42 3.51 Finance leases 2.89 3.68 Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2021 $ 96 $ 4 2022 81 4 2023 58 2 2024 50 1 2025 40 1 Thereafter 125 2 Total lease payments 450 14 Less: imputed interest (51) (2) Total $ 399 $ 12 Lessor Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. Maturity analysis of lease receivables was as follows: Operating 2021 $ 127 2022 117 2023 108 2024 41 2025 41 Thereafter 404 Total $ 838 The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2020.
Leases	Leases Lessee AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land. The components of lease expense were as follows: Year Ended Year Ended Operating lease cost (includes variable lease payments) $ 43 $ 29 Finance lease cost Amortization of right-of-use assets $ 4 $ 4 Total finance lease cost $ 4 $ 4 Total lease cost $ 47 $ 33 Supplemental cash flow information related to leases was as follows: Year Ended December 31 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ (36) $ (21) Financing cash flows from finance leases (a) $ (4) $ (4) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 227 $ 50 Finance leases $ 6 $ 5 (a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows. Supplemental balance sheet information related to leases was as follows: As at December 31 2020 2019 Operating Leases Operating lease right-of-use assets Long-term $ 372 $ 170 Total operating lease right-of-use assets $ 372 $ 170 Operating lease liabilities Current $ (95) $ (27) Long-term (304) (153) Total operating lease liabilities $ (399) $ (180) Finance Leases Property and equipment, gross $ 19 $ 13 Accumulated depreciation (7) (3) Property and equipment, net $ 12 $ 10 Current portion of long-term debt $ (4) $ (4) Long-term debt (8) (6) Total finance lease liabilities $ (12) $ (10) As at December 31, December 31, Weighted average remaining lease term (years) Operating leases 7.4 10.9 Finance leases 4.8 5.2 Weighted average discount rate (%) Operating leases 2.42 3.51 Finance leases 2.89 3.68 Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2021 $ 96 $ 4 2022 81 4 2023 58 2 2024 50 1 2025 40 1 Thereafter 125 2 Total lease payments 450 14 Less: imputed interest (51) (2) Total $ 399 $ 12 Lessor Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. Maturity analysis of lease receivables was as follows: Operating 2021 $ 127 2022 117 2023 108 2024 41 2025 41 Thereafter 404 Total $ 838 The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2020.
Leases	Leases Lessee AltaGas has operating and finance leases for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land. The components of lease expense were as follows: Year Ended Year Ended Operating lease cost (includes variable lease payments) $ 43 $ 29 Finance lease cost Amortization of right-of-use assets $ 4 $ 4 Total finance lease cost $ 4 $ 4 Total lease cost $ 47 $ 33 Supplemental cash flow information related to leases was as follows: Year Ended December 31 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ (36) $ (21) Financing cash flows from finance leases (a) $ (4) $ (4) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 227 $ 50 Finance leases $ 6 $ 5 (a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows. Supplemental balance sheet information related to leases was as follows: As at December 31 2020 2019 Operating Leases Operating lease right-of-use assets Long-term $ 372 $ 170 Total operating lease right-of-use assets $ 372 $ 170 Operating lease liabilities Current $ (95) $ (27) Long-term (304) (153) Total operating lease liabilities $ (399) $ (180) Finance Leases Property and equipment, gross $ 19 $ 13 Accumulated depreciation (7) (3) Property and equipment, net $ 12 $ 10 Current portion of long-term debt $ (4) $ (4) Long-term debt (8) (6) Total finance lease liabilities $ (12) $ (10) As at December 31, December 31, Weighted average remaining lease term (years) Operating leases 7.4 10.9 Finance leases 4.8 5.2 Weighted average discount rate (%) Operating leases 2.42 3.51 Finance leases 2.89 3.68 Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2021 $ 96 $ 4 2022 81 4 2023 58 2 2024 50 1 2025 40 1 Thereafter 125 2 Total lease payments 450 14 Less: imputed interest (51) (2) Total $ 399 $ 12 Lessor Certain of AltaGas’ revenues are obtained through power purchase agreements or take-or-pay contracts whereby AltaGas is the lessor in these operating lease arrangements. Minimum lease payments received are amortized over the term of the lease. Contingent rentals are recorded when the condition that created the present obligation to make such payments occurs such as when actual electricity is generated and delivered. Maturity analysis of lease receivables was as follows: Operating 2021 $ 127 2022 117 2023 108 2024 41 2025 41 Thereafter 404 Total $ 838 The carrying value of property, plant, and equipment associated with these leases was approximately $0.5 billion as at December 31, 2020.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill As at December 31, December 31, Balance, beginning of year $ 3,942 $ 4,068 Business acquisition (note 3) 1,171 — Adjustment to goodwill on business acquisition — 92 Goodwill included in dispositions — (29) Reclassified to assets held for sale — (1) Foreign exchange translation (74) (188) Balance, end of year $ 5,039 $ 3,942

Long-Term Investments and Other

Long-Term Investments and Other Assets	12 Months Ended
	Dec. 31, 2020
Investments, All Other Investments [Abstract]
Long-Term Investments and Other Assets	Long-Term Investments and Other Assets As at December 31, December 31, Investments in publicly-traded entities $ — $ 4 Loan to affiliate (notes 23 and 30) — 45 Deferred lease receivable 12 17 Debt issuance costs associated with credit facilities 3 6 Refundable deposits 9 9 Prepayment on long-term service agreements 70 81 Deferred information technology costs 4 — Cash calls from joint venture partners 26 10 Contract asset (net of credit losses of $1 million) (notes 23 and 24) 50 30 Rabbi trust and other restricted cash (notes 28, 29 and 31) 19 32 Other long-term receivables (net of credit losses of $2 million) (notes 23 and 29) 18 33 Capitalized contract costs 5 — Financial transmission rights 12 12 Other 17 18 $ 245 $ 297

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2020
VARIABLE INTEREST ENTITIES [Abstract]
Variable Interest Entities	Variable Interest Entities Consolidated VIEs AltaGas consolidates VIEs where the Corporation is deemed the primary beneficiary. The primary beneficiary of a VIE has the power to direct the activities of the entity that most significantly impact its economic performance such as being the provider of construction, operating and marketing services to the entity. In addition, the primary beneficiary of a VIE also has the obligation to absorb losses of the entity or the right to receive benefits that could potentially be significant to the VIE. AltaGas determined that it is the primary beneficiary of the following VIEs: Ridley Island LPG Export Limited Partnership On May 5, 2017, AltaGas LPG Limited Partnership (AltaGas LPG), a wholly-owned subsidiary of AltaGas, and Vopak Development Canada Inc. (Vopak), a wholly-owned subsidiary of Koninklijke Vopak N.V. (Royal Vopak), a public company incorporated under the laws of the Netherlands, formed the Ridley Island LPG Export Limited Partnership (RILE LP) to develop, own and operate the Ridley Island Propane Export Terminal (RIPET). AltaGas’ subsidiaries hold a 70 percent interest while Vopak holds a 30 percent interest in RILE LP. The construction cost of RIPET was funded by AltaGas LPG and Vopak in proportion to their respective interests in RILE LP. As part of the arrangements, AltaGas entered into a long-term agreement for the capacity of RIPET with RILE LP, and AltaGas and certain of its subsidiaries provide operating services to RILE LP. AltaGas has determined that RILE LP is a VIE in which it holds variable interests and is the primary beneficiary. In the determination that AltaGas is the primary beneficiary of the VIE, AltaGas noted that it has the power to direct the activities that most significantly impact the VIE’s economic performance through the operating and marketing services provided to RILE LP. In addition, AltaGas has the obligation to absorb the losses and the right to receive the benefits that could potentially be significant to RILE LP through the long-term agreement for the capacity of RIPET. As such, AltaGas has consolidated RILE LP. The assets of RILE LP are the property of RILE LP and are not available to AltaGas for any other purpose. RILE LP’s asset balances can only be used to settle its own obligations. The liabilities of RILE LP do not represent additional claims against AltaGas’ general assets. AltaGas’ exposure to loss as a result of its interest as a limited partner is its net investment. AltaGas and Royal Vopak have provided limited guarantees for the obligations of their respective subsidiaries for the construction cost of RIPET. With the commencement of commercial operations at RIPET, the terms of the long-term capacity agreement between AltaGas LPG and RILE LP provide for a return on and of capital and reimbursement of RIPET's operating costs by AltaGas LPG in accordance with the terms set out in the agreement. The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIE: As at December 31, 2020 December 31, 2019 Current assets $ 7 $ 6 Property, plant and equipment 358 371 Long-term investments and other assets 50 53 Current liabilities (2) (3) Asset retirement obligations (2) (3) Net assets $ 411 $ 424 Unconsolidated VIE Strathcona Storage Limited Partnership (SSLP) Upon the acquisition of Petrogas on December 15, 2020, AltaGas acquired an indirect interest in SSLP, a partnership formed with ATCO Energy Solutions Ltd. to construct, operate, and maintain underground NGL storage caverns at Fort Saskatchewan,

Investments Accounted for by th

Investments Accounted for by the Equity Method	12 Months Ended
	Dec. 31, 2020
Equity Method Investments and Joint Ventures [Abstract]
Investments Accounted for by the Equity Method	Investments Accounted for by the Equity Method Carrying value as at December 31 Equity income (loss) for the year ended December 31 Description Location Ownership Percentage 2020 2019 2020 2019 AltaGas Canada Inc. (ACI) (a) Canada — $ — $ 164 $ 3 $ 17 AltaGas Idemitsu Joint Venture LP (b) Canada — — 431 (25) 63 Constitution Pipeline, LLC (Constitution) (c) United States — — — (7) — Eaton Rapids Gas Storage System United States 50 26 27 2 1 Meade Pipeline Co. LLC (d) United States — — — — (4) Mountain Valley Pipeline, LLC (Mountain Valley) (e) United States 10 718 672 62 43 Sarnia Airport Storage Pool LP Canada 50 18 18 1 1 Petrogas Preferred Shares (f) Canada n/a — 150 13 13 Petrogas Terminals Penn LLC (g) United States 37 1 — — — Stonewall Gas Gathering Systems LLC (d) United States — — — — 7 Strathcona Storage LP (g) Canada 30 124 — — — $ 887 $ 1,462 $ 49 $ 141 (a) ACI was acquired by the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board on March 31, 2020 (Note 4). (b) Upon acquisition of Petrogas on December 15, 2020 (Note 3), AltaGas no longer has an equity investment in AIJVLP. (c) The equity method is considered appropriate because Constitution is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. In February 2020, the partners of Constitution elected not to proceed with the pipeline project and Constitution was dissolved. The loss recorded in 2020 relates to a provision recorded against the equity investment (see below for further discussion). (d) Disposed of in 2019. (e) The equity method is considered appropriate because Mountain Valley is an LLC with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. (f) Petrogas' preferred shares ceased to be an investment accounted for by the equity method after AltaGas acquired a controlling interest in Petrogas on December 15, 2020 (Note 3). (g) Acquired on December 15, 2020 as part of the Petrogas Acquisition (Note 3). The carrying amount of certain equity investments differs from the amount of the underlying equity in net assets. These basis differences include amounts related to purchase accounting adjustments, capitalized interest, and a contractual cap on contributions to Mountain Valley. Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows: Year Ended December 31 (a) 2020 2019 Revenues $ 828 $ 1,109 Expenses (181) (355) $ 647 $ 754 As at December 31 (a) 2020 2019 Current assets $ 351 $ 411 Property, plant and equipment $ 7,598 $ 8,034 Intangible assets $ — $ 22 Long-term investments and other assets $ 5 $ 1,459 Current liabilities $ (281) $ (394) Other long-term liabilities $ (2) $ (992) (a) For equity investments that were disposed of in the periods presented, revenues and expenses reflect the period prior to disposition and balance sheet amounts are $nil. For equity investments that were acquired in the year (Note 3), revenues and expenses reflect the period subsequent to acquisition and balance sheet amounts are included as at December 31, 2020. Equity Method Investments Acquired In connection with the acquisition of Petrogas (Note 3), AltaGas acquired the following investments accounted for by the equity method: Petrogas Terminals Penn LLC Petrogas owns a 50 percent equity interest in Petrogas Terminals Penn LLC, a partnership with a regional propane retailer engaged in rail offloading of propane for distribution by truck to customers in Pennsylvania and other nearby states. Strathcona Storage LP Petrogas owns a 40 percent equity interest in Strathcona Storage Limited Partnership, a partnership with ATCO Energy Solutions Ltd., which is engaged in the development of underground NGL storage caverns at Fort Saskatchewan, Alberta. SSLP is considered a VIE (Note 13) and is accounted for using the equity method. AltaGas Canada Inc. On March 31, 2020, the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board acquired all the issued and outstanding common shares of ACI for $33.50 per share (Note 4). AltaGas owned 11,025,000 (approximately 37 percent) of ACI's common shares and received cash proceeds of approximately $369 million upon close. AltaGas recognized a pre-tax gain on disposition of approximately $206 million in the Consolidated Statements of Income under the line item "other income" (Note 27). Following a name change in connection with the arrangement, ACI changed its name to TriSummit Utilities Inc. Petrogas/AIJVLP At the beginning of 2020, AltaGas held an indirect approximate one-third interest in Petrogas through its equity investment in AIJVLP. In the first quarter of 2020, one of Petrogas' shareholders has converted their preferred shares of Petrogas to common shares resulting in the dilution of AltaGas' indirect ownership in Petrogas common shares from approximately 33.3 percent to approximately 29.2 percent. In addition, prior to the close of the Petrogas Acquisition in the fourth quarter of 2020, AltaGas converted their preferred shares of Petrogas to common shares. As a result of these transactions, in 2020, AltaGas recognized pre-tax dilution losses totaling approximately $30 million in the Consolidated Statements of Income under the line item "income from equity investments". There were additional expenses of $12 million recorded to "income from equity investments" related to various adjustments to pre-acquisition balances of Petrogas. This primarily included amounts relating to severance, transaction costs and impairment losses related to the acquisition of Petrogas. Upon close of the Petrogas Acquisition on December 15, 2020, AltaGas recognized a pre-tax gain of $22 million in the Consolidated Statements of Income under the line item "other income" on the re-measurement of it's previously held equity investment in AIJVLP. Subsequent to the acquisition, AltaGas no longer has an equity investment in AIJVLP. Provisions on investments accounted for by the equity method In the year ended December 31, 2020, AltaGas recorded a pre-tax provision on equity investments of approximately $7 million in the Consolidated Statements of Income under the line item "income from equity investments" for costs associated with AltaGas' equity investment in the Constitution pipeline project which was canceled in February 2020. In the year ended December 31, 2019, AltaGas recorded a pre-tax provision of $44 million against its investment in Meade as a result of the sale of WGL Midstream's interest in the Central Penn Pipeline. The disposition of the investment in this entity was completed in the fourth quarter of 2019. In addition, AltaGas recorded a pre-tax provision of $2 million against its investment in Craven County Wood Energy LP as a result of a pending sale. The disposition of the investment in this entity was completed in the third quarter of 2019.

Short-term Debt

Short-term Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Short-term Debt	Short-term Debt As at December 31, December 31, Commercial paper (a) $ 236 $ 389 Project financing 20 71 $ 256 $ 460 (a) Washington Gas use short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. Project Financing WGL and certain of its subsidiaries previously obtained third-party project financing on behalf of the United States federal government to provide funds for the construction of certain energy management services projects entered into under Washington Gas' area-wide contract. When these projects are formally accepted by the government and deemed complete, the ownership of the receivable is assigned to the third-party lender in satisfaction of the obligation, removing both the receivable and the obligation related to the financing from the Consolidated Financial Statements. As at December 31, 2020, draws related to project financing were $20 million (December 31, 2019 - $71 million). Other Credit Facilities As at December 31, 2020, the AltaGas held a $70 million (December 31, 2019 - $70 million) unsecured demand revolving operating credit facility with a Canadian chartered bank. Draws on the facility bear interest at the lender's prime rate or at the bankers' acceptance rate plus a stamping fee. Letters of credit outstanding under this facility as at December 31, 2020 were $nil (December 31, 2019 - $nil). As at December 31, 2020, AltaGas held a $150 million (December 31, 2019 - $150 million) unsecured four bankers’ acceptances, or letters of credit. Letters of credit outstanding under this facility as at December 31, 2020 were $nil (December 31, 2019 - $26 million). As at December 31, 2020, AltaGas held a US$200 million (December 31, 2019 - US$200 million) unsecured bilateral letter of credit demand facility with a Canadian chartered bank. Borrowings on the facility incur fees and interest at rates relevant to the nature of the draws made. Letters of credit outstanding under this facility as at December 31, 2020 were $190 million (December 31, 2019 - $156 million). As at December 31, 2020, AltaGas held a US$1.2 billion (December 31, 2019 - US$1.2 billion) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2020 or December 31, 2019. During the year ended December 31, 2020, AltaGas cancelled a US$300 million unsecured extendible revolving letter of credit facility. WGL and Washington Gas use short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. As at December 31, 2020, commercial paper outstanding classified as short-term debt totaled $236 million (December 31, 2019 - $389 million). Credit Facilities Acquired in Petrogas Acquisition As at December 31, 2020, Petrogas held a $30 million revolving letter of credit facility. Letters of credit outstanding under this facility as at December 31, 2020 were $22 million. As at December 31, 2020, Petrogas held an operating facility of US$15 million. There were no letters of credit outstanding under this facility as at December 31, 2020. As at December 31, 2020, Petrogas held a US$40 million seasonal bulge facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2020.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt As at Maturity date December 31, December 31, Credit facilities $1,400 million unsecured extendible revolving facility (a) 15-May-2023 $ 802 $ 90 US$300 million unsecured extendible revolving facility 27-Feb-2021 — 390 US$150 million unsecured extendible revolving facility 20-Dec-2023 81 163 Commercial paper (b) Various 260 367 $175 million secured extendible revolving facility 18-Jun-2022 51 — AltaGas Ltd. medium-term notes (MTNs) $200 million Senior unsecured - 4.07 percent 1-Jun-2020 — 200 $350 million Senior unsecured - 3.72 percent 28-Sep-2021 350 350 $500 million Senior unsecured - 2.61 percent 16-Dec-2022 500 500 $300 million Senior unsecured - 3.57 percent 12-Jun-2023 300 300 $200 million Senior unsecured - 4.40 percent 15-Mar-2024 200 200 $300 million Senior unsecured - 3.84 percent 15-Jan-2025 300 300 $500 million Senior unsecured - 2.16 percent 10-Jun-2025 500 — $350 million Senior unsecured - 4.12 percent 7-Apr-2026 350 350 $200 million Senior unsecured - 3.98 percent 4-Oct-2027 200 200 $500 million Senior unsecured - 2.08 percent 30-May-2028 500 — $200 million Senior unsecured - 2.48 percent 30-Nov-2030 200 — $100 million Senior unsecured - 5.16 percent 13-Jan-2044 100 100 $300 million Senior unsecured - 4.50 percent 15-Aug-2044 300 300 $250 million Senior unsecured - 4.99 percent 4-Oct-2047 250 250 WGL and Washington Gas MTNs US$250 million Senior unsecured - 2.44 percent (c) 12-Mar-2020 — 325 US$20 million Senior unsecured - 6.65 percent 20-Mar-2023 25 26 US$41 million Senior unsecured - 5.44 percent 11-Aug-2025 52 53 US$53 million Senior unsecured - 6.62 to 6.82 percent Oct 2026 67 69 US$72 million Senior unsecured - 6.40 to 6.57 percent Feb - Sep 2027 92 93 US$52 million Senior unsecured - 6.57 to 6.85 percent Jan - Mar 2028 66 67 US$9 million Senior unsecured - 7.50 percent 1-Apr-2030 11 11 US$50 million Senior unsecured - 5.70 to 5.78 percent Jan - Mar 2036 64 65 US$75 million Senior unsecured - 5.21 percent 3-Dec-2040 95 97 US$75 million Senior unsecured - 5.00 percent 15-Dec-2043 95 97 US$300 million Senior unsecured - 4.22 to 4.60 percent Sep - Nov 2044 382 390 US$450 million Senior unsecured - 3.80 percent 15-Sep-2046 573 584 US$400 million Senior unsecured - 3.65 percent (d) 15-Sep-2049 530 390 SEMCO long-term debt US$300 million SEMCO Senior Secured - 5.15 percent (e) 21-Apr-2020 — 390 US$82 million SEMCO Senior Secured - 4.48 percent (f) 2-Mar-2032 69 76 US$225 million First Mortgage Bonds - 3.15 percent 21-Apr-2030 286 — US$225 million First Mortgage Bonds - 2.45 percent 21-Apr-2050 286 — Fair value adjustment on WGL Acquisition 80 84 Finance lease liabilities (note 10) 12 10 $ 8,029 $ 6,887 Less debt issuance costs (43) (36) $ 7,986 $ 6,851 Less current portion (360) (923) $ 7,626 $ 5,928 (a) Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers' acceptances, or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made. (b) Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024. Commercial paper intended to be repaid within the next year is recorded as short-term debt (Note 15). (c) Floating rate per annum reset quarterly based on terms set forth in the prospectus filed by WGL pursuant to Securities Act Rule 424 on March 13, 2018. (d) On December 10, 2020, Washington Gas issued MTNs with an aggregate principal amount of $100 million. This offering constituted the reopening of it's $300 million MTNs originally issued in 2019. The total includes a US$17 million premium which will be amortized as a reduction to interest expense over the term of the note. (e) Collateral for the U.S. dollar MTNs is certain SEMCO assets. (f) Collateral for the CINGSA Senior secured loan is certain CINGSA assets. Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan. Other Credit Facilities As at December 31, 2020, AltaGas held a US$300 million (December 31, 2019 - US$300 million) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2020 or December 31, 2019. As at December 31, 2020, WGL held a US$250 million (December 31, 2019 - US$250 million) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2020 or December 31, 2019. As at December 31, 2020, Washington Gas held a US$450 million (December 31, 2019 - US$450 million) unsecured revolving credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2020 or December 31, 2019. WGL and Washington Gas use short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Revolving committed credit facilities are maintained in an amount equal to or greater than the expected maximum commercial paper position. As at December 31, 2020, outstanding commercial paper classified as long-term debt totaled $260 million (December 31, 2019 - $367 million). Credit Facilities Acquired in Petrogas Acquisition As at December 31, 2020, Petrogas held a $175 million secured extendible revolving letter of credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances, or letters of credit. Loans and letters of credit outstanding under this facility as at December 31, 2020 were $57 million. As at December 31, 2020, Petrogas held a US$10 million operating revolving letter of credit facility. Letters of credit outstanding under this facility as at December 31, 2020 were $nil. As at December 31, 2020, Petrogas held a $25 million revolving letter of credit facility. Draws on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers’ acceptances, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2020.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations As at December 31 2020 2019 Balance, beginning of year $ 362 $ 500 Obligations acquired (note 3) 13 — New obligations 14 7 Obligations settled (4) (2) Disposals (1) (6) Revision in estimated cash flow (10) (129) Accretion expense (a) 17 19 Foreign exchange translation (6) (21) Total $ 385 $ 368 Less: current portion (included in accounts payable and accrued liabilities) (6) (6) Balance, end of year $ 379 $ 362 (a) Certain amounts relating to Utility asset retirement obligations are recorded through regulatory assets or liabilities on the Consolidated Balance Sheets due to regulatory treatment. The remaining portion is recorded through the Consolidated Statements of Income. The majority of the asset retirement obligations are associated with distribution and transmission systems in the Utilities segment. AltaGas estimates the undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation, at December 31, 2020 was $816 million (December 31, 2019 - $727 million).

Environmental Matters

Environmental Matters	12 Months Ended
	Dec. 31, 2020
Environmental Remediation Obligations [Abstract]
Environmental Matters	Environmental Matters AltaGas is subject to federal, provincial, state and local laws and regulations related to environmental matters. These laws and regulations may require expenditures over a long time frame to control environmental effects. Almost all of the environmental liabilities AltaGas has recorded are for costs expected to be incurred to remediate sites where AltaGas or a predecessor affiliate operated manufactured gas plants (MGPs). Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to, the following: ▪ the complexity of the site; ▪ changes in environmental laws and regulations at the federal, state, and local levels; ▪ the number of regulatory agencies or other parties involved; ▪ new technology that renders previous technology obsolete or experience with existing technology that proves ineffective; ▪ the level of remediation required; and ▪ variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site. AltaGas has identified up to twelve sites where it or its predecessors may have operated MGPs. In connection with these operations, AltaGas is aware that coal tar and certain other by-products of the gas manufacturing process are present at or near some former sites and may be present at others. As at December 31, 2020, a liability of $13 million has been recorded on an undiscounted basis related to future environmental response costs (December 31, 2019 - $14 million) in the Consolidated Balance Sheets under the line items “accounts payable and accrued liabilities and other long-term liabilities”. These estimates principally include the minimum liabilities associated with a range of environmental response costs expected to be incurred. As at December 31, 2020, AltaGas estimated the maximum liability associated with all of its sites to be approximately $39 million (December 31, 2019 - $40 million). The estimates were determined by AltaGas’ environmental experts, based on experience in remediating MGP sites and advice from legal counsel and environmental consultants. The variation between the recorded and estimated maximum liability primarily results from differences in the number of years that will be required to perform environmental response processes and the extent of remediation that may be required. As at December 31, 2020, AltaGas reported a regulatory asset of $15 million (December 31, 2019 - $18 million) for the portion of environmental response costs that are expected to be recoverable in future rates (Note 21).

Other Long-term Liabilities

Other Long-term Liabilities	12 Months Ended
	Dec. 31, 2020
Other Liabilities Disclosure [Abstract]
Other Long-term Liabilities	Other Long-term Liabilities As at December 31, December 31, Deferred revenue $ 8 $ 4 Customer advances for construction 60 64 Merger commitments 10 14 Other employee benefits 6 6 Deferred payroll taxes (a) 6 — Petrogas equalization reserve (b) 5 — Uncertain tax positions (note 20) 21 2 Non-pension retirement benefits 16 — Other 21 12 $ 153 $ 102 (a) Represents U.S. federal payroll tax deferrals from the Coronavirus Aid, Relief, and Economic Security (CARES) Act. (b) Reserve is held by a wholly owned subsidiary of Petrogas.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Year Ended December 31 2020 2019 Income before income taxes - consolidated $ 699 $ 812 Statutory income tax rate (%) 24.0 26.5 Expected taxes at statutory rates $ 168 $ 215 Add (deduct) the tax effect of: Permanent differences $ 2 $ 11 Statutory and other rate differences 9 (52) Rate adjustment for change in tax rates — (11) Deferred income tax recovery on regulated assets (15) (25) Tax differences on divestitures and transactions (33) (159) Change in valuation allowance (2) (11) Other (2) 4 $ 127 $ (28) Income tax provision Current $ 1 $ 63 Deferred 126 (91) $ 127 $ (28) Effective income tax rate (%) 18.2 (3.4) Net deferred income tax liabilities were composed of the following: As at December 31, December 31, PP&E and intangible assets $ 1,645 $ 1,450 Regulatory assets (229) (204) Tax pools, deferred financing, and compensation (208) (138) Other (94) (161) Valuation allowance 4 12 $ 1,118 $ 959 The amount shown on the Consolidated Balance Sheets as deferred income tax liabilities represents the net differences between the tax basis and book carrying values on the Corporation's balance sheets at enacted tax rates. The Alberta government passed the Job Creation Tax Cut in 2019 which reduced Alberta's corporate tax rate from 12 percent to 11 percent on July 1, 2019. The tax rate was further reduced from 11 percent to 8 percent on July 1, 2020. As at December 31, 2020, the Corporation had tax-effected non-capital losses of approximately $293 million, which will be available to offset future taxable income. If not used, these losses will expire between 2023 and 2040. Uncertain Tax Positions The Corporation recognizes the benefit of an uncertain tax position only when it is more likely than not that such a position will be sustained by the taxing authorities based on the technical merits of the position. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that has greater than 50 percent likelihood of being realized upon settlement with the taxing authorities. On an annual basis, the Corporation and its subsidiaries file tax returns in Canada and various foreign jurisdictions. In Canada, AltaGas' federal and provincial tax returns for the years 2013 to 2019 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns for the years 2016 to 2019 remain subject to examination by the taxation authorities. Management determined that the following provision was required for uncertainty on income taxes during the year: Year ended December 31 2020 2019 Balance, beginning of year $ 2 $ 2 Gross increases for tax positions of prior year 21 — Lapses of statute of limitations (2) — Balance, end of year $ 21 $ 2

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities AltaGas accounts for certain transactions in accordance with ASC 980, Regulated Operations. AltaGas refers to this accounting guidance for regulated entities as “regulatory accounting”. Under regulatory accounting, utilities are permitted to defer expenses and income as regulatory assets and liabilities, respectively, in the Consolidated Balance Sheets when it is probable that those expenses and income will be allowed in the rate-setting process in a period different from the period in which they would have been reflected in the Consolidated Statements of Income by a non-rate-regulated entity. These deferred regulatory assets and liabilities are included in the Consolidated Statements of Income in future periods when the amounts are reflected in customer rates. If an application is filed to modify customer rates with certain regulatory commissions, AltaGas is permitted to charge customers new rates, subject to refund, until the regulatory commission renders a final decision. During this interim period, a provision is recorded for a rate refund regulatory liability based on the difference between the amount collected in rates and the amount expected to be recovered from a final regulatory decision. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory agency orders, rules, and rate-making conventions. The relevant regulatory bodies are the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA. If, for any reason, the Corporation ceases to meet the criteria for application of regulatory accounting for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be de-recognized from the Consolidated Balance Sheets and included in the Consolidated Statements of Income for the period in which the discontinuance of regulatory accounting occurs. Criteria that give rise to the discontinuance of regulatory accounting include: (i) increasing competition that restricts the ability of the Corporation to charge prices sufficient to recover specific costs, and (ii) a significant change in the manner in which rates are set by regulatory agencies from cost-based regulation to another form of regulation. The Corporation’s review of these criteria currently supports the continued application of regulatory accounting for all its utilities. The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as at December 31, 2020 and 2019, over which the Corporation expects to realize or settle the assets or liabilities: As at December 31 2020 2019 Recovery Regulatory assets - current Deferred cost of gas (a) $ 18 $ 8 Less than one year Accelerated replacement recovery mechanisms (b) 6 2 Less than one year Interruptible sharing (a) 2 3 Less than one year Energy optimization costs 1 — Less than one year Virginia and Maryland revenue normalization (a) 19 — Less than one year $ 46 $ 13 Regulatory assets - non-current Deferred regulatory costs (a) (c) $ 158 $ 150 2 - 55 years Future recovery of pension and other retirement benefits (a) 68 128 Various Future recovery of non-retirement employee benefits (a) (d) 22 19 Various Deferred environmental costs (a) (e) 15 18 Various Deferred loss on debt transactions and derivative instruments (a) (f) 93 99 Various Deferred future income taxes (a) (g) 46 43 Various Energy efficiency program - Maryland (h) 18 12 Various COVID-19 costs (i) 10 — Various Other 14 18 Various $ 444 $ 487 Regulatory liabilities - current Deferred cost of gas (a) $ 56 $ 61 Less than one year Refundable tax credit (j) 2 2 Less than one year Federal income tax rate change (k) 20 33 Less than one year Virginia rate refund (l) — 41 Less than one year Interruptible sharing (a) 1 — Less than one year Virginia Coronavirus Relief Fund (m) 10 — Less than one year Other 1 9 Less than one year $ 90 $ 146 Regulatory liabilities - non-current Refundable tax credit (j) 2 4 2 years Future expense of pension and other retirement benefits (a) 335 261 Various Future removal and site restoration costs (n) 462 484 Various Deferred gain on debt transactions and derivative instruments (a) (f) 1 2 Various Federal income tax rate change (k) 578 628 Various Other 3 4 Various $ 1,381 $ 1,383 (a) Washington Gas is not entitled to a rate of return on these assets. Washington Gas is allowed to recover and required to pay, using short-term interest rates, the carrying costs related to billed gas costs due from and to its customers in the District of Columbia and Virginia jurisdictions. (b) Represents amounts for deferred over or under collections of surcharges associated with Washington Gas' accelerated pipeline recovery programs in the District of Columbia, Maryland, and Virginia. (c) Includes deferred gas costs and fair value of derivatives, which are not included in customer bills until settled. (d) Represents the timing difference between the recognition of workers compensation and short-term disability costs in accordance with generally accepted accounting principles and the way these costs are recovered through rates. Certain utilities have recovered pension costs related to regulated operations in rates, and as such, the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility, the recovery period can be either the expected service life of the employees, the benefit period for employees, or a specific recovery period as approved by the respective regulator. (e) This balance represents allowed environmental remediation expenditures at SEMCO and Washington Gas sites to be recovered through rates. (f) The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior years. These transactions create gains and losses that are amortized over the remaining life of the debt as prescribed by regulatory accounting requirements. As at December 31, 2020, this also includes a fair value adjustment of $76 million (December 31, 2019 - $80 million) recorded on the WGL Acquisition in 2018. (g) This balance represents amounts due from customers for deferred tax assets and liabilities related to tax benefits/expenses on deductions flowed directly to customers prior to the adoption of income tax normalizations for ratemaking purposes and to tax rate changes. (h) Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland. (i) Regulatory assets established to capture and track incremental COVID-19 related costs. (j) On September 18, 2013, CINGSA received a US$15 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA's customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology. (k) The Tax Cuts and Jobs Act (TCJA) was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities in 2018 to the lower federal corporate tax rate of 21 percent, resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas and Washington Gas are required to refund to ratepayers. (l) Represents estimated refunds related to customers billed at a higher rate during the interim period as part of the 2019 Virginia rate case. (m) The Virginia Coronavirus Relief Fund was received by WGL to provide direct assistance to Virginia customers with balances over 30 days in arrears. (n) This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income	Accumulated Other Comprehensive Income ($ millions) Defined benefit pension and PRB plans Hedge net investments Translation foreign operations Equity investee Total Opening balance, January 1, 2020 $ (6) $ (149) $ 395 $ 5 $ 245 OCI before reclassification (11) (10) (175) (5) (201) Amounts reclassified from OCI 3 — — — 3 Current period OCI (pre-tax) (8) (10) (175) (5) (198) Income tax on amounts retained in AOCI 3 1 — — 4 Income tax on amounts reclassified to earnings (1) — — — (1) Net current period OCI (6) (9) (175) (5) (195) Ending balance, December 31, 2020 $ (12) $ (158) $ 220 $ — $ 50 Opening balance, January 1, 2019 $ (19) $ (209) $ 801 $ 6 $ 579 OCI before reclassification 15 68 (406) (1) (324) Amounts reclassified from OCI 1 — — — 1 Current period OCI (pre-tax) 16 68 (406) (1) (323) Income tax on amounts retained in AOCI (3) (8) — — (11) Net current period OCI 13 60 (406) (1) (334) Ending balance, December 31, 2019 $ (6) $ (149) $ 395 $ 5 $ 245 Reclassification From Accumulated Other Comprehensive Income AOCI components reclassified Income statement line item Year Ended December 31, 2020 Year Ended Defined benefit pension and PRB plans Other income $ 3 $ 1 Deferred income taxes Income tax expense – deferred (1) — $ 2 $ 1

Financial Instruments and Finan

Financial Instruments and Financial Risk Management	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Financial Instruments and Financial Risk Management	Financial Instruments and Financial Risk Management The Corporation’s financial instruments consist of cash and cash equivalents, accounts receivable, risk management contracts, certain long-term investments and other assets, accounts payable and accrued liabilities, dividends payable, short-term and long-term debt and certain other current and long-term liabilities. Fair Value Hierarchy AltaGas categorizes its financial assets and financial liabilities into one of three levels based on fair value measurements and inputs used to determine the fair value. Level 1 - fair values are based on unadjusted quoted prices in active markets for identical assets or liabilities. Fair values are based on direct observations of transactions involving the same assets or liabilities and no assumptions are used. Included in this category are publicly traded shares valued at the closing price as at the balance sheet date. Level 2 - fair values are determined based on valuation models and techniques where inputs other than quoted prices included within Level 1 are observable for the asset or liability either directly or indirectly. AltaGas enters into derivative instruments in the futures, over-the-counter and retail markets to manage fluctuations in commodity prices and foreign exchange rates. The fair values of power, natural gas, NGL, LPG, ocean freight, and oil derivative contracts were calculated using forward prices based on published sources for the relevant period, adjusted for factors specific to the asset or liability, including basis and location differentials, discount rates, and currency exchange. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of foreign exchange option contracts were calculated using a variation of the Black-Scholes pricing model. Level 3 - fair values are based on inputs for the asset or liability that are not based on observable market data. AltaGas uses valuation techniques when observable market data is not available. Level 3 derivatives include physical contracts at illiquid market locations with no observable market data, long-dated positions where observable pricing is not available over the life of the contract, contracts valued using historical spot price volatility assumptions, and valuations using indicative broker quotes for inactive market locations. A significant change to any one of these inputs in isolation could result in a significant upward or downward fluctuation in the fair value measurement. The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments: Other current liabilities - the carrying amounts approximate fair value because of the short maturity of these instruments. Current portion of long-term debt, Long-term debt and Other long-term liabilities - the fair value of these liabilities was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms. Risk management assets and liabilities - the fair values of power, natural gas and NGL, LPG, ocean freight, and oil derivative contracts were calculated using forward prices from published sources for the relevant period. The fair value of foreign exchange derivative contracts was calculated using quoted market rates. The fair value of Level 3 derivative contracts was calculated using internally developed valuation inputs and pricing models. Equity securities – the fair value of equity securities was calculated using quoted market prices. Loans and receivables – the fair value of these assets was estimated based on discounted future interest and principal payments using the current market interest rates of instruments with similar terms. As at December 31, 2020 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income (a) Risk management assets - current $ 94 $ — $ 73 $ 21 $ 94 Risk management assets - non-current 38 — 2 36 38 Fair value through regulatory assets (a) Risk management assets - current 4 — 1 3 4 Risk management assets - non-current 9 — — 9 9 $ 145 $ — $ 76 $ 69 $ 145 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 102 $ — $ 78 $ 24 $ 102 Risk management liabilities - non-current 66 — 15 51 66 Fair value through regulatory liabilities (a) Risk management liabilities - current 9 — — 9 9 Risk management liabilities - non-current 79 — 1 78 79 Amortized cost Current portion of long-term debt 360 — 360 — 360 Long-term debt 7,626 — 8,451 — 8,451 Other current liabilities (b) 37 — 37 — 37 $ 8,279 $ — $ 8,942 $ 162 $ 9,104 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Excludes non-financial liabilities. As at December 31, 2019 Carrying Level 1 Level 2 Level 3 Total Financial assets Fair value through net income (a) Risk management assets - current $ 82 $ — $ 31 $ 51 $ 82 Risk management assets - non-current 31 — 7 24 31 Equity securities (b) 4 4 — — 4 Fair value through regulatory assets (a) Risk management assets - current 5 — — 5 5 Risk management assets - non-current 8 — — 8 8 Amortized cost Loans and receivables (b) 45 — 46 — 46 $ 175 $ 4 $ 84 $ 88 $ 176 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 121 $ — $ 99 $ 22 $ 121 Risk management liabilities - non-current 77 — 19 58 77 Fair value through regulatory liabilities (a) Risk management liabilities - current 4 — 1 3 4 Risk management liabilities - non-current 90 — — 90 90 Amortized cost Current portion of long-term debt 923 — 923 — 923 Long-term debt 5,928 — 6,264 — 6,264 Other current liabilities (c) 15 — 15 — 15 $ 7,158 $ — $ 7,321 $ 173 $ 7,494 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (c) Excludes non‑financial liabilities. Financial assets and liabilities not included in the fair value hierarchy table include money market funds, short term debt, commercial paper, and a long-term receivable (Note 12). The carrying value of these financial instruments approximate their fair value, which reflects the short-term maturity and/or normal credit terms of these financial instruments. The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments as at December 31, 2020: Net Fair Value Valuation Technique Unobservable Inputs Range Weighted Average (a) Natural gas $ (73) Discounted Cash Flow Natural Gas Basis Price (per Dth) $ (1.27) - $ 2.64 $ (0.37) Natural gas $ (1) Option Model Natural Gas Basis Price (per Dth) $ (1.27) - $ 2.58 $ (0.01) Annualized Volatility of Spot Market Natural Gas 13 % - 917 % 73 % Electricity $ (19) Discounted Cash Flow Electricity Congestion Price (per MWh) $ (6.26) - $ 61.88 $ 13.57 (a) Unobservable inputs were weighted by transaction volume. The following tables provide a reconciliation of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy: For the year ended December 31 2020 2019 Natural Electricity Total Natural Electricity Total Balance, beginning of year $ (85) $ — $ (85) $ (149) $ (14) $ (163) Realized and unrealized gains (losses): Recorded in income 8 (55) (47) 48 1 49 Recorded in regulatory assets (1) — (1) 24 — 24 Transfers into Level 3 (1) — (1) (9) — (9) Transfers out of Level 3 1 — 1 12 — 12 Purchases — 3 3 — (11) (11) Settlements 4 32 36 (17) 24 7 Foreign exchange translation — 1 1 6 — 6 Balance, end of year $ (74) $ (19) $ (93) $ (85) $ — $ (85) Transfers between different levels of the fair value hierarchy may occur based on fluctuations in the valuation and on the level of observable inputs used to value the instruments from period to period. Transfers into and out of the different levels of the fair value hierarchy are presented at the fair value as of the beginning of the period. Transfers out of Level 3 during the year ended December 31, 2020 were due to an increase in valuations using observable market inputs. Transfers into Level 3 during the year ended December 31, 2020 were due to an increase in unobservable market inputs used in valuations. Realized and Unrealized Gains (Losses) Recorded to Income for Level 3 Measurements Year Ended December 31 2020 2019 Recorded to revenue $ (79) $ 75 Recorded to cost of sales 32 (26) $ (47) $ 49 Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income Year Ended December 31 2020 2019 Natural gas $ 32 $ 23 Energy exports 10 (87) Crude oil and NGLs 4 — NGL frac spread (5) (17) Power (15) (5) Foreign exchange (5) 1 $ 21 $ (85) Offsetting of Derivative Assets and Derivative Liabilities Certain of AltaGas’ risk management contracts are subject to master netting arrangements that create a legally enforceable right for a counterparty to offset the related financial assets and financial liabilities. As part of these master netting agreements, cash, letters of credit and parental guarantees may be required to be posted or obtained from counterparties in order to mitigate credit risk related to both derivative and non-derivative positions. Collateral balances are also offset against the related counterparties’ derivative positions to the extent the application would not result in the over-collateralization of those derivative positions on the balance sheet. As at December 31, 2020 Gross amounts of recognized Gross amounts Netting Net amounts Risk management assets (a) Natural gas $ 104 $ (38) $ (3) $ 63 Energy exports 86 (86) 36 36 Crude oil and NGLs 1 — — 1 Power 30 (8) — 22 Foreign exchange 27 (3) (1) 23 $ 248 $ (135) $ 32 $ 145 Risk management liabilities (b) Natural gas $ 173 $ (38) $ (3) $ 132 Energy exports 153 (86) — 67 NGL frac spread 6 — — 6 Power 58 (8) 1 51 Foreign exchange 3 (3) — — $ 393 $ (135) $ (2) $ 256 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $98 million and risk management assets (non‑current) balance of $47 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $111 million and risk management liabilities (non‑current) balance of $145 million. As at December 31, 2019 Gross amounts of Gross amounts Netting Net amounts Risk management assets (a) Natural gas $ 121 $ (54) $ — $ 67 Energy exports 10 (3) 5 12 Power 54 (7) — 47 $ 185 $ (64) $ 5 $ 126 Risk management liabilities (b) Natural gas $ 226 $ (54) $ (28) $ 144 Energy exports 90 (3) — 87 NGL frac spread 2 — — 2 Power 69 (7) (3) 59 $ 387 $ (64) $ (31) $ 292 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $87 million and risk management assets (non‑current) balance of $39 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $125 million and risk management liabilities (non‑current) balance of $167 million. Cash Collateral The following table presents collateral not offset against risk management assets and liabilities: As at December 31, December 31, Collateral posted with counterparties $ 4 $ 29 Cash collateral held representing an obligation $ — $ — Any collateral posted that is not offset against risk management assets and liabilities is included in line item “prepaid expenses and other current assets” in the Consolidated Balance Sheets. Collateral received and not offset against risk management assets and liabilities is included in line item “customer deposits” in the Consolidated Balance Sheets. Certain derivative instruments contain contract provisions that require collateral to be posted if the credit rating of AltaGas or certain of its subsidiaries falls below certain levels. At December 31, 2020, AltaGas has posted $nil (December 31, 2019 - $6 million) of collateral related to its derivative liabilities that contained credit-related contingent features. The following table shows the aggregate fair value of all derivative instruments with credit-related contingent features that are in a liability position, as well as the maximum amount of collateral that would be required if specific credit-risk-related contingent features underlying these agreements were triggered: As at December 31, December 31, Risk management liabilities with credit-risk-contingent features $ 32 $ 42 Maximum potential collateral requirements $ 26 $ 29 Risks associated with financial instruments AltaGas is exposed to various financial risks in the normal course of operations such as market risks resulting from fluctuations in commodity prices, currency exchange rates and interest rates as well as credit risk and liquidity risk. Commodity Price Risk AltaGas enters into financial derivative contracts to manage exposure to fluctuations in commodity prices. The use of derivative instruments is governed under formal risk management policies and is subject to parameters set out by AltaGas’ Risk Management Committee and Board of Directors. AltaGas does not make use of derivative instruments for speculative purposes. Natural Gas In the normal course of business, AltaGas purchases and sells natural gas to support its infrastructure business. The fixed price and market price contracts for both the purchase and sale of natural gas extend to 2040. In addition, AltaGas may enter into financial derivative contracts as part of WGL’s asset optimization program. WGL optimized the value of its long-term natural gas transportation and storage capacity resources during periods when these resources are not being used to physically serve utility customers. AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2020 and 2019: December 31, 2020 Fixed price Period Notional volume (GJ) Fair Value Sales 1.58 to 7.86 1-157 590,054,996 $ 32 Purchases 1.58 to 6.47 1-240 1,522,958,497 $ (106) Swaps 2.29 to 7.86 1-60 288,613,586 $ 5 December 31, 2019 Fixed price Period Notional volume (GJ) Fair Value Sales 1.32 to 6.81 1-166 698,126,985 $ 29 Purchases 0.22 to 6.81 1-167 1,406,991,689 $ (104) Swaps 0.22 to 10.24 1-51 541,652,374 $ (2) Crude Oil and NGLs In the normal course of business, AltaGas purchases and sells crude oil, condensates, and LPGs. The fixed price and market price contracts for both the purchase and sale of crude oil, condensates, and LPGs extend to 2021. December 31, 2020 Fixed price Period Notional volume (Bbl) Fair Value Sales 37.43 to 62.59 1 680,000 $ (1) Purchases 19.92 to 59.01 1-9 221,000 $ 2 Energy Exports AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to the propane and butane price differentials between North American Indices and the Far East Index for contracts not under tolling arrangements at RIPET and Ferndale. AltaGas had the following contracts outstanding as at December 31, 2020: December 31, 2020 Fixed price Period Notional volume Fair Value Propane and butane swaps 3.57 to 61.46 1-36 37,425,488 $ (31) December 31, 2019 Fixed price Period Notional volume Fair Value Propane 21.49 to 29.71 1-27 9,374,826 $ (75) NGL Frac Spread AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. AltaGas had the following contracts outstanding as at December 31, 2020 and 2019: December 31, 2020 Fixed price Period Notional volume Fair Value Propane swaps 28.83 to 35.36/Bbl 1-12 1,270,350 Bbl $ (5) Butane swaps 32.45 to 34.02/Bbl 1-12 307,784 Bbl $ (1) Crude oil swaps 60.08 to 61.95/Bbl 1-12 123,120 Bbl $ — Natural gas swaps 1.58 to 1.86/GJ 1-12 7,281,570 GJ $ — December 31, 2019 Fixed price Period Notional volume Fair Value Butane swaps 73.02 to 75.15/Bbl 1-12 346,852 Bbl $ (1) Crude oil swaps 73.02 to 75.15/Bbl 1-12 212,587 Bbl $ (1) Natural gas swaps 1.58 to 1.86/GJ 1-12 3,883,992 GJ $ — Power AltaGas sells power to the Alberta Electric System Operator at market prices. AltaGas also sells power through its WGL Energy Services affiliate, to commercial, industrial and mass market users within the PJM Regional Transmission Organization at fixed and market prices. AltaGas' strategy is to mitigate the cash flow risk to power prices to provide predictable earnings. Therefore, AltaGas uses third-party swaps and purchase contracts to fix the prices over time on a portion of the volumes to mitigate financial exposure associated with the sale contracts. These power purchase and sale contracts extend to 2025. As at December 31, 2020, AltaGas had no intention to terminate any contracts prior to maturity. AltaGas had the following power commodity forward contracts and commodity swaps outstanding as at December 31, 2020 and 2019: December 31, 2020 Fixed price Period Notional volume Fair Value Power sales 24.56 to 61.75 1-33 5,482,242 $ 13 Power purchases 24.56 to 61.88 1-63 8,848,007 $ (18) Swap purchases (6.26) to 74.26 1-44 24,081,519 $ (24) December 31, 2019 Fixed price Period Notional volume Fair Value Power sales 31.63 to 66.76 1-42 8,034,024 $ 39 Power purchases 31.63 to 66.76 1-60 8,552,467 $ (27) Swap purchases (7.88) to 74.26 1-48 25,058,577 $ (24) The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2020: Factor Increase or decrease to forward prices Increase or decrease to income before tax ($ millions) PJM power price US$1/MWh 2 AECO natural gas price $0.50/GJ 1 NYMEX natural gas price US$0.50/GJ 36 Energy Exports: Propane Far East Index to domestic supply $1/Bbl 10 Baltic LPG Freight $1/Bbl 11 NGL frac spread: Propane $1/Bbl 1 Natural gas $0.50/GJ 4 Foreign exchange swaps $0.01 CAD to USD 1 Foreign Exchange Risk AltaGas is exposed to foreign exchange risk as changes in foreign exchange rates may affect the fair value or future cash flows of the Corporation’s financial instruments. AltaGas has foreign operations whereby the functional currency is the U.S. dollar. As a result, the Corporation’s earnings, cash flows, and OCI are exposed to fluctuations resulting from changes in foreign exchange rates. This risk is partially mitigated to the extent that AltaGas has U.S. dollar-denominated debt and/or preferred shares outstanding. AltaGas may also enter into foreign exchange forward derivatives to manage the risk of fluctuating cash flows due to variations in foreign exchange rates. AltaGas may designate its U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. As at December 31, 2020, AltaGas has not designated any outstanding debt as a net investment hedge (December 31, 2019 - US$300 million). For the year ended December 31, 2020, AltaGas incurred an after-tax unrealized loss of $9 million arising from the translation of debt in OCI (2019 ‑ after-tax unrealized gains of $60 million). In connection with the Petrogas Acquisition, AltaGas acquired various commodity and financial derivative instruments, including the following foreign exchange forward contracts which are outstanding as at December 31, 2020: Foreign exchange forward contract Notional Amount Duration Weighted average foreign exchange rate Fair Value Forward USD sales US$29 Less than one year 1.3591 $ 3 Forward USD purchases US$356 Less than one year 1.2824 $ (3) Foreign exchange swaps (purchases) US$410 Less than one year 1.3322 $ 23 For the year ended December 31, 2020, AltaGas recorded an after-tax realized gain of $1 million on all foreign exchange forward contracts. Interest Rate Risk AltaGas is exposed to interest rate risk as changes in interest rates may impact future cash flows and the fair value of its financial instruments. The Corporation manages its interest rate risk by holding a mix of both fixed and floating interest rate debt. As at December 31, 2020, approximately 83 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates (December 31, 2019 - 76 percent). In addition, from time to time, AltaGas may enter into interest rate swap agreements to fix the interest rate on a portion of its banker’s acceptances issued under its credit facilities. There were no outstanding interest rate swaps as at December 31, 2020. Credit Risk Credit risk results from the possibility that a counterparty to a financial instrument fails to fulfill its obligations in accordance with the terms of the contract. AltaGas' credit policy details the parameters used to grant, measure, monitor and report on credit provided to counterparties. AltaGas minimizes counterparty risk by conducting credit reviews on counterparties in order to establish specific credit limits, both prior to providing products or services and on a recurring basis. In addition, most contracts include credit mitigation clauses that allow AltaGas to obtain financial or performance assurances from counterparties under certain circumstances. AltaGas maintains an allowance for doubtful accounts in the normal course of its business. AltaGas' maximum credit exposure consists primarily of the carrying value of the non-derivative financial assets and the fair value of derivative financial assets. As at December 31, 2020, AltaGas had no concentration of credit risk with a single counterparty. Weather Related Instruments WGL Energy Services utilizes heating degree day (HDD) instruments from time to time to manage weather and price risks related to its natural gas and electricity sales during the winter heating season. WGL Energy Services also utilizes cooling degree day (CDD) instruments and other instruments to manage weather and price risks related to its electricity sales during the summer cooling season. These instruments cover a portion of estimated revenue or energy-related cost exposure to variations in HDDs or CDDs. For the year ended December 31, 2020, a pre-tax loss of $3 million was recorded related to these instruments (2019 - pre-tax loss of $2 million). Accounts Receivable Past Due or Impaired With the exception of accounts receivable which are due in one year or less as summarized in the following table, AltaGas does not have any past due or impaired accounts receivables (AR) as at December 31, 2020: As at December 31, 2020 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 1,465 $ 396 $ 41 $ 906 $ 52 $ 17 $ 53 Other 20 — — 20 — — — Allowance for credit losses (41) — (41) — — — — $ 1,444 $ 396 $ — $ 926 $ 52 $ 17 $ 53 As at December 31, 2019 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 1,238 $ 343 $ 33 $ 758 $ 61 $ 12 $ 31 Other 17 — — 17 — — — Allowance for credit losses (33) — (33) — — — — $ 1,222 $ 343 $ — $ 775 $ 61 $ 12 $ 31 The following table provides a summary of changes to the allowance for credit losses by segment and major type: Year Ended December 31, 2020 Accounts Receivable Contract Assets (a) Other long-term investments and other assets (b) Total Utilities Balance, beginning of period $ 31 $ — $ — $ 31 Adjustment upon adoption of ASC 326 (c) 2 — — 2 Foreign exchange translation (1) — — (1) New allowance (d) 32 — — 32 Written off (28) — — (28) Recoveries collected 4 — — 4 Balance, end of period $ 40 $ — $ — $ 40 Midstream Balance, beginning of period $ 1 $ — $ — 1 Adjustment upon adoption of ASC 326 — 1 3 4 Recoveries collected — — (1) (1) Balance, end of period $ 1 $ 1 $ 2 $ 4 Corporate/Other Balance, beginning of period $ 2 $ — $ — $ 2 Adjustment upon adoption of ASC 326 — — 1 1 Written off (2) — — (2) Recoveries collected — — (1) (1) Balance, end of period $ — $ — $ — $ — Total $ 41 $ 1 $ 2 $ 44 (a) An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate associated with the estimated time frame that the contract asset will be billed to the customer. (b) Includes loan to affiliate, which is no longer outstanding at December 31, 2020, and other long-term receivables (Notes 12 and 29). An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivable is expected to be collected. (c) Based on previous collection experience, AltaGas did not record an allowance for credit losses for its contract assets associated with its energy management services projects with the U.S. federal government. (d) Includes $8 million recorded to a regulatory asset relating to the impact of COVID-19 on uncollectible accounts. Liquidity Risk Liquidity risk is the risk that AltaGas will not be able to meet its financial obligations as they come due. AltaGas manages this risk through its extensive budgeting and monitoring process to ensure it has sufficient cash and credit facilities to meet its obligations. AltaGas' objective is to maintain its investment-grade ratings to ensure it has access to debt and equity funding as required. AltaGas had the following contractual maturities with respect to financial liabilities: Contractual maturities by period As at December 31, 2020 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,561 $ 1,561 $ — $ — $ — Dividends payable 22 22 — — — Short-term debt 256 256 — — — Other current liabilities (a) 37 37 — — — Risk management contract liabilities 256 111 51 22 72 Current portion of long-term debt (b) 356 356 — — — Long-term debt (b) 7,581 — 1,771 1,324 4,486 $ 10,069 $ 2,343 $ 1,822 $ 1,346 $ 4,558 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition. Contractual maturities by period As at December 31, 2019 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,325 $ 1,325 $ — $ — $ — Dividends payable 22 22 — — — Short-term debt 460 460 — — — Other current liabilities (a) 15 15 — — — Risk management contract liabilities 292 125 34 13 120 Current portion of long-term debt (b) 920 920 — — — Long-term debt (b) 5,873 — 1,489 922 3,462 $ 8,907 $ 2,867 $ 1,523 $ 935 $ 3,582 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue	Revenue The following tables disaggregate revenue by major sources for the year: Year Ended December 31, 2020 Utilities Midstream Corporate/Other Total (a) Revenue from contracts with customers Commodity sales contracts $ 1,338 $ 1,097 $ 1 $ 2,436 Midstream service contracts — 277 — 277 Gas sales and transportation services 2,394 — — 2,394 Storage services 25 — — 25 Other 9 — 20 29 Total revenue from contracts with customers $ 3,766 $ 1,374 $ 21 $ 5,161 Other sources of revenue Revenue from alternative revenue programs (b) $ 96 $ — $ — $ 96 Leasing revenue (c) 1 139 100 240 Risk management and trading activities (d) (e) (31) 112 — 81 Other (15) 10 14 9 Total revenue from other sources $ 51 $ 261 $ 114 $ 426 Total revenue $ 3,817 $ 1,635 $ 135 $ 5,587 (a) In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information. (b) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (c) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (d) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users. (e) Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2020 of $437 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018. Revenue from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020. Year Ended December 31, 2019 Utilities Midstream Corporate/Other Total (a) Revenue from contracts with customers Commodity sales contracts $ 1,428 $ 746 $ 51 $ 2,225 Midstream service contracts — 145 — 145 Gas sales and transportation services 2,501 — — 2,501 Storage services 28 — — 28 Other 9 3 29 41 Total revenue from contracts with customers $ 3,966 $ 894 $ 80 $ 4,940 Other sources of revenue Revenue from alternative revenue programs (b) $ 30 $ — $ — $ 30 Leasing revenue (c) 1 137 105 243 Risk management and trading activities (d) (e) 52 188 22 262 Other (5) 9 16 20 Total revenue from other sources $ 78 $ 334 $ 143 $ 555 Total revenue $ 4,044 $ 1,228 $ 223 $ 5,495 (a) In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information. (b) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (c) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (d) Risk management activities involve the use of derivative instruments such as physical and financial swaps, and forward contracts. These derivatives are accounted for under ASC 815 and ASC 825. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users. (e) Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2019 of $505 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018. Revenue from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020. Revenue Recognition The following is a description of the Corporation’s revenue recognition policy by segment and by major source of revenue from contracts with customers. Utilities Segment Gas Sales and Transportation Services Customers are billed monthly based on regular meter readings. Customer billings are based on two main components: (i) a fixed service fee and (ii) a variable fee based on usage. Revenue is recognized over time when the gas has been delivered or as the service has been performed. As meter readings are performed on a cycle basis, AltaGas recognizes accrued revenue for any services rendered to its customers but not billed at month-end. The vast majority of these contracts are “at-will” as customers may cancel their service at any time, however, there are certain contracts that have terms of one year or longer. For these long-term contracts, there is generally a contract demand specified in the contract whereby the customer has to pay regardless of whether or not gas has been delivered. These contracts generally do not contain any make up rights and revenue is recognized on a monthly basis as service has been performed. Gas Storage Services Gas storage customers are billed monthly for services provided. Customer billings are based on four components: (i) reservation charges; (ii) capacity charges; (iii) injection/withdrawal charges; and (iv) excess charges. Reservation charges are based on the customer’s contract withdrawal quantity, capacity charges are based on the customer’s total contract quantity, and injection/withdrawal charges are based on the volume of gas delivered to or from the customer. Excess charges are applied to each day that the storage quantity exceeds 100 percent of the customer’s maximum storage quantity. Revenue is recognized as the service has been performed over time on a monthly basis, which corresponds to the invoice amount. The majority of these contracts have terms extending beyond one year. Commodity Sales Commodity sales also include gas sales to residential, commercial, and industrial customers in certain jurisdictions where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one five Midstream Segment Commodity Sales A portion of the NGL production from AltaGas’ extraction facilities is subject to frac spread between NGLs extracted and the natural gas purchased to make up the heating value of the NGLs extracted. For commodity sales contracts that do not meet the definition of a derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. These commodity sales contracts have varying terms but the majority of the contracts have a one-year term which coincides with the NGL year. AltaGas recognizes revenue for commodity sales contracts at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. Commodity sales contracts at RIPET and Ferndale generate revenue from the sale and delivery of LPGs to customers in Asia shipped from offshore export terminals. Revenue is recognized when LPGs are loaded onto transport vessels, which is the delivery point. AltaGas has the right to consideration in an amount that directly corresponds to the volumes of LPGs loaded on a vessel. Petrogas' commodity sales also include the sale of upgraded crude oil, processed finished products, and various fuels. Delivery takes place when there is a sales contract in place, specifying delivery volumes and sales prices. The consideration received under these contracts is variable based on commodity prices. Midstream Service Contracts AltaGas earns revenue from its field gathering and processing facilities, extraction facilities, storage facilities, truck hauling services, rail and truck loading and unloading terminalling, and transmission systems through a variety of contractual arrangements. For arrangements that do not contain a lease, the revenue is accounted for under ASC 606 as follows: Fee-for-service – The customer is charged a fee for the service provided on a per unit volume basis. Contract terms generally range from one month to up to the life of the reserves. Revenue under this type of arrangement is recognized over time as the service is provided, which corresponds to the customer’s monthly invoice amount. Take-or-pay – The customer has agreed to a minimum volume commitment whereby the customer must have AltaGas process or deliver a specified volume at a rate per unit that is specified in the contract. Quantities that the customer is unable to deliver are considered deficiency quantities. Certain of AltaGas’ take-or-pay contracts contain provisions whereby the customer can make up deficiency quantities in subsequent periods. Under this type of arrangement, any consideration received relating to the deficiency quantities that will be made up in a future period will be deferred until either: (i) the customer makes up the volumes or (ii) the likelihood that the customer will make up the volumes before the make up period expires becomes remote. If AltaGas does not expect the customer to make up the deficiency quantities (also referred to as breakage amount), AltaGas may recognize the expected breakage amount as revenue before the make up period expires. Significant judgment is required in estimating the breakage amount. For contracts where the customer has no make up rights, revenue is recognized on a monthly basis based on the higher of (i) the actual quantity delivered times the per unit rate or (ii) the contracted minimum amount. Petrogas' storage fees are typically recognized in revenue ratably over the term of the contract and rail and truck loading and unloading fees are recognized when the volumes are delivered or received. Corporate/Other Segment For the Corporate/Other segment, the majority of revenue relates to remaining power assets, from which revenue is primarily earned through power purchase agreements which are accounted for as operating leases. In instances where power generation is not sold under a power purchase agreement, the commodity is sold via a merchant market, or via commodity sales agreements which are accounted for as financial instruments. For commodity sales contracts that do not meet the definition of a lease, derivative or for contracts whereby AltaGas has elected to apply the normal purchase normal sales scope exception, the sales contract is accounted for under ASC 606. This includes energy generated from combined heating and power assets that are sold under long term power purchase agreements with a general duration of approximately 20 years. These long term purchase agreements provide stable cash flow by way of contracted prices for the underlying commodities. Contract Balances As at December 31, 2020, a contract asset of $51 million ($50 million net of credit losses) has been recorded within long-term investments and other assets on the Consolidated Balance Sheets (December 31, 2019 – $30 million). This contract asset represents the difference in revenue recognized under a new rate in a blend-and-extend contract modification with a customer. Revenue from this contract modification will be recognized at the pre-modification rate for the remainder of the original term with the excess revenue recorded as a contract asset. The contract asset will be drawn down over the remaining term of the modified contract. In addition, at December 31, 2020 there is a contract asset of $21 million (December 31, 2019 - $59 million) recorded within prepaid expenses and other current assets on the Consolidated Balance Sheets for WGL Energy Systems’ unbilled revenue relating to design-build construction contracts. The contract asset represents unbilled amounts typically resulting from sales under contracts when the cost-to-cost method of revenue recognition is utilized, and revenue recognized exceeds the amount billed to the customer. Right to payment is achieved when the projects are formally “accepted” by the federal government. At December 31, 2020, contract liabilities of $nil (December 31, 2019 - $2 million) have been recorded within accounts payable and accrued liabilities on the Consolidated Balance Sheets. The contract liabilities consisted of advance payments and billings in excess of revenue recognized and deferred revenue. Contract assets and liabilities are reported in a net position on a contract-by-contract basis at the end of each reporting period. Contract Assets As at December 31, December 31, Balance, beginning of year $ 89 $ 59 Additions 30 32 Transfers to accounts receivable (49) — Foreign exchange translation 1 (2) Balance, end of year $ 71 $ 89 Contract Liabilities As at December 31, December 31, Balance, beginning of year $ 2 $ 2 Additions 2 2 Revenue recognized from contract liabilities (a) (4) (2) Balance, end of year $ — $ 2 (a) Recognition of revenue related to performance obligations satisfied in the current period for amounts that were previously included in contract liabilities. Transaction price allocated to the remaining obligations The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of December 31, 2020: 2021 2022 2023 2024 2025 2026 & beyond Total Midstream service contracts $ 125 $ 131 $ 128 $ 128 $ 125 $ 1,037 $ 1,674 Storage services 24 23 23 23 23 142 258 Other 7 2 2 2 2 9 24 $ 156 $ 156 $ 153 $ 153 $ 150 $ 1,188 $ 1,956

Shareholders_ Equity

Shareholders’ Equity	12 Months Ended
	Dec. 31, 2020
Stockholders' Equity Note [Abstract]
Shareholders’ Equity	Shareholders’ Equity Authorization AltaGas is authorized to issue an unlimited number of voting common shares. AltaGas is also authorized to issue such number of Preferred Shares in series at any time as have aggregate voting rights either directly or on conversion or exchange that in the aggregate represent less than 50 percent of the voting rights attaching to the then issued and outstanding Common Shares. Dividend Reinvestment and Optional Cash Purchase Plan (DRIP or the Plan) The Plan consisted of two components: a Dividend Reinvestment component and an Optional Cash Purchase component. The Premium Dividend™ component of the plan was suspended in December 2018. The Dividend Reinvestment and Optional Cash Purchase component was suspended in December 2019, with the December dividend (paid January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP. The Plan in its entirety will remain suspended until further notice. Common Shares Issued and Outstanding Number of Amount January 1, 2019 275,224,066 $ 6,654 Shares issued for cash on exercise of options 76,177 1 Deferred taxes on share issuance cost — (4) Shares issued under DRIP 3,774,442 68 December 31, 2019 279,074,685 $ 6,719 Shares issued for cash on exercise of options 88,082 1 Deferred taxes on share issuance cost — (3) Shares issued under DRIP 331,532 6 Issued and outstanding at December 31, 2020 279,494,299 $ 6,723 Preferred Shares As at December 31, 2020 December 31, 2019 Issued and Outstanding Number of shares Amount Number of shares Amount Series A 6,746,679 $ 169 5,511,220 $ 138 Series B 1,253,321 31 2,488,780 62 Series C 8,000,000 206 8,000,000 206 Series E 8,000,000 200 8,000,000 200 Series G 6,885,823 172 6,885,823 172 Series H 1,114,177 28 1,114,177 28 Series I — — 8,000,000 200 Series K 12,000,000 300 12,000,000 300 Share issuance costs, net of taxes (29) (29) 44,000,000 $ 1,077 52,000,000 $ 1,277 On December 31, 2020, all outstanding Series I shares were redeemed. No gain or loss was recognized upon redemption. In 2019, all outstanding Washington Gas preferred shares were redeemed. A gain of $4 million was recognized upon redemption. . The following table outlines the characteristics of the cumulative redeemable preferred shares (a) : Current yield Annual dividend per share (b) Redemption price per share Redemption and conversion option date (c)(d) Right to convert into (d) Series A (e) 3.060 % $0.76500 $25 September 30, 2025 Series B Series B (f) (g) Floating Floating $25 September 30, 2025 Series A Series C (h) 5.290 % US$1.32250 US$25 September 30, 2022 Series D Series E (e) 5.393 % $1.34825 $25 December 31, 2023 Series F Series G (e) 4.240 % $1.06050 $25 September 30, 2024 Series H Series H (f) (g) Floating Floating $25 September 30, 2024 Series G Series K (i) 5.000 % $1.25000 $25 March 31, 2022 Series L (a) This table only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares, Series F Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption. (b) The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series H Shares, and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares and Series H Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. (c) AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. (d) The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter. (e) Holders of Series A Shares, Series E Shares, and Series G Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares). (f) Holders of Series B Shares and Series H Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent (Series B Shares) and 3.06 percent (Series H Shares). Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2020, the floating quarterly dividend rate is $0.17069 per share for Series B Shares and $0.195349 per share for Series H Shares for the period starting December 31, 2020 to, but excluding, March 31, 2021. (g) Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. Series H Shares can be redeemed for $25.50 per share on any date after September 30, 2019 that is not a Series H conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. (h) Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent. (i) Holders of Series K Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the then five-year Government of Canada bond yield plus 3.80 percent, provided that, in any event, such rate shall not be less than 5.00 percent per annum. Share Option Plan AltaGas has an employee share option plan under which officers, employees, and service providers (as defined by the TSX) are eligible to receive grants. As at December 31, 2020, 13,915,160 shares were reserved for issuance under the plan. As at December 31, 2020, share options granted under the plan have a term between six four As at December 31, 2020, the unexpensed fair value of share option compensation cost associated with future periods was $4 million (December 31, 2019 ‑ $5 million). The following table summarizes information about the Corporation’s share options: December 31, 2020 December 31, 2019 As at Options outstanding Options outstanding Number of Exercise price (a) Number of Exercise price (a) Share options outstanding, beginning of year 7,043,956 $ 22.49 6,309,183 $ 25.18 Granted 2,501,755 19.46 2,287,385 19.12 Exercised (88,082) 14.89 (76,177) 14.52 Forfeited (631,549) 26.00 (1,165,435) 27.31 Expired (463,869) 27.69 (311,000) 36.16 Share options outstanding, end of year 8,362,211 $ 21.06 7,043,956 $ 22.49 Share options exercisable, end of year 3,607,391 $ 23.59 2,921,642 $ 27.70 (a) Weighted average. As at December 31, 2020, the aggregate intrinsic value of the total share options exercisable was $5 million (December 31, 2019 - $3 million), the total intrinsic value of share options outstanding was $9 million (December 31, 2019 - $12 million) and the total intrinsic value of share options exercised was less than $1 million (December 31, 2019 - less than $1 million). The following table summarizes the employee share option plan as at December 31, 2020: Options outstanding Options exercisable Number outstanding Weighted average exercise price Weighted average remaining contractual life (years) Number exercisable Weighted average exercise price Weighted average remaining contractual life (years) $14.52 to $18.00 2,446,392 $ 15.24 4.07 1,359,457 $ 14.92 4.00 $18.01 to $25.08 3,930,345 19.56 4.80 528,252 19.54 4.47 $25.09 to $41.00 1,985,474 31.21 1.82 1,719,682 31.68 1.64 8,362,211 $ 21.06 3.88 3,607,391 $ 23.59 2.95 The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option pricing model. The weighted average grant date fair value and assumptions are as follows: Year ended December 31 2020 2019 Fair value per options ($) 2.61 2.30 Risk-free interest rate (%) 1.54 1.48 Expected life (years) 6 6 Expected volatility (%) 25.40 24.84 Annual dividend per share ($) (a) 0.96 0.96 Forfeiture rate (%) — — (a) Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as the grant dates. Phantom Unit Plan (Phantom Plan) and Deferred Share Unit Plan (DSUP) AltaGas has a Phantom Plan for employees and executive officers, which includes restricted units (RUs) and performance units (PUs) with vesting periods of 36 to 44 months from the grant date. In addition, AltaGas has a DSUP, which allows granting of deferred share units (DSUs) to directors. DSUs granted under the DSUP vest immediately but settlement of the DSUs occur when the individual ceases to be a director. PUs, RUs, and DSUs (number of units) 2020 2019 Balance, beginning of year 6,484,831 9,908,154 Granted 1,158,547 674,971 Vested and paid out (681,841) (791,335) Forfeited (1,342,832) (3,377,962) Units in lieu of dividends 113,429 71,003 Outstanding, end of year 5,732,134 6,484,831 For the year ended December 31, 2020, the compensation expense recorded for the Phantom Plan and DSUP was $16 million (2019 – $22 million). As at December 31, 2020, the unrecognized compensation expense relating to the remaining vesting period for the Phantom Plan was $23 million (December 31, 2019 ‑ $22 million) and is expected to be recognized over the vesting period.

Net Income Per Common Share

Net Income Per Common Share	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Net Income Per Common Share	Net Income Per Common Share The following table summarizes the computation of net income per common share: Year Ended December 31 2020 2019 Numerator: Net income applicable to controlling interests $ 552 $ 833 Less: Preferred share dividends (66) (68) Gain on redemption of preferred shares (note 25) — 4 Net income applicable to common shares $ 486 $ 769 Denominator: (millions of shares) Weighted average number of common shares outstanding 279.4 276.9 Dilutive equity instruments (a) 0.3 0.5 Weighted average number of common shares outstanding - diluted 279.7 277.4 Basic net income per common share $ 1.74 $ 2.78 Diluted net income per common share $ 1.74 $ 2.77 (a) Determined using the treasury stock method.

Other Income

Other Income	12 Months Ended
	Dec. 31, 2020
Other Income and Expenses [Abstract]
Other Income	Other Income Year Ended December 31 2020 2019 Gains on asset sales (note 4) $ 223 $ 876 Gain on remeasurement of previously held interest in AIJVLP (note 3) 22 — Other components of net benefit cost (note 28) 52 27 Interest income and other revenue 9 9 Losses on investments — (4) Total $ 306 $ 908

Pension Plans and Retiree Benef

Pension Plans and Retiree Benefits	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Pension Plans and Retiree Benefits	Pension Plans and Retiree Benefits The costs of the defined benefit and post-retirement benefit plans are based on Management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits. In 2020, AltaGas made a voluntary change in accounting principle for calculating the market-related value of assets used in the determination of Washington Gas' net periodic pension and other post-retirement benefit plan costs. This change in accounting principle impacts the calculation of net periodic benefit cost recorded within the line item “other income” on the Consolidated Statements of Income. Refer to Note 2 for additional information. Defined Contribution Plan AltaGas has a defined contribution (DC) pension plan for substantially all employees. The pension cost recorded for the DC plan was $21 million for the year ended December 31, 2020 (2019 - $20 million). Defined Benefit Plans AltaGas has several defined benefit pension plans for unionized and non-unionized employees, including one in Canada (which is comprised of five divisions) and six in the United States. The plans in the United States include a qualified, trusteed, non-contributory defined benefit pension plan, and a non-funded defined benefit restoration plan maintained by Washington Gas. The defined benefit plans are partially funded except for three of the divisions in Canada which are fully funded and one of the plans in the United States which is not funded. AltaGas’ most recent actuarial valuation of the Canadian defined benefit plans for funding purposes was completed for the year ended December 31, 2019. AltaGas is required to file an actuarial valuation of its Canadian defined benefit plans with the pension regulators at least every three years. The next actuarial valuation for funding purposes is required to be completed as of a date no later than December 31, 2022, and will be filed with the pension regulators in 2023. Actuarial valuations for funding purposes are required annually for AltaGas’ U.S. defined benefit plans. Supplemental Executive Retirement Plans (SERP) AltaGas has non-registered, defined benefit plans that provide defined benefit pension benefits to eligible executives based on average earnings, years of service and age at retirement. The SERP benefits will be paid from the general revenue of the Corporation as payments come due or from the Rabbi Trusts funded as part of the WGL acquisition. Security will be provided for the SERP benefits through a letter of credit within a retirement compensation arrangement trust account. Several executive officers of Washington Gas participate in a separate non-funded defined benefit SERP (a non-qualified pension plan). This defined benefit SERP was closed to new entrants beginning January 1, 2010. Post-Retirement Benefit Plans AltaGas has several post-retirement benefit plans for unionized and non-unionized employees, including one in Canada and four in the United States. The post-retirement benefit plan in Canada is limited to the payment of life insurance and an annual allocation to a Healthcare Spending Account (HSA). This benefit plan is not funded. Post-retirement benefit plans in the United States provide certain medical, prescription drug, dental, and life insurance benefits to eligible retired employees, their spouses and covered dependents. Benefits are based on a combination of the retiree's age and years of service at retirement. For eligible Washington Gas retirees and dependents not yet receiving Medicare benefits, Washington Gas provides medical, prescription drug, and dental benefits through Preferred Provider Organization (PPO) or Health Maintenance Organization (HMO) plans, through the Washington Gas Light Company Retiree Medical Plan. For Medicare-eligible retirees age 65 and older and their dependents, eligible retirees and dependents participate in a tax-free Health Reimbursement Account (HRA) Plan. The HRA plan provides an annual subsidy to help purchase supplemental medical, prescription drug and dental coverage in the marketplace. One of these benefit plans is partially funded and three are fully funded. Rabbi Trusts Rabbi trusts of $28 million as at December 31, 2020 have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans (December 31, 2019 - $57 million). These balances are included in prepaid expenses and other current assets and long-term investments and other assets in the Consolidated Balance Sheets. The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States: Year Ended December 31, 2020 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Projected benefit obligation (a) Balance, beginning of year $ 36 $ 2 $ 1,725 $ 428 $ 1,761 $ 430 Actuarial loss 1 — 137 32 138 32 Current service cost 3 — 27 9 30 9 Member contributions — — — 2 — 2 Interest cost 1 — 60 15 61 15 Benefits paid (4) — (82) (24) (86) (24) Expenses paid — — (1) — (1) — Settlements — — (25) — (25) — Foreign exchange translation — — (41) (10) (41) (10) Balance, end of year $ 37 $ 2 $ 1,800 $ 452 $ 1,837 $ 454 Plan assets Fair value, beginning of year $ 15 $ — $ 1,504 $ 906 $ 1,519 $ 906 Actual return on plan assets 1 — 275 157 276 157 Employer contributions 4 — 37 — 41 — Member contributions — — — 2 — 2 Benefits paid (4) — (82) (24) (86) (24) Expenses paid — — (1) — (1) — Settlements — — (25) — (25) — Foreign exchange translation — — (41) (25) (41) (25) Fair value, end of year $ 16 $ — $ 1,667 $ 1,016 $ 1,683 $ 1,016 Funded status $ (21) $ (2) $ (133) $ 564 $ (154) $ 562 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation. Year Ended December 31, 2019 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Projected benefit obligation (a) Balance, beginning of year $ 34 $ 2 $ 1,635 $ 458 $ 1,669 $ 460 Actuarial loss (gain) 2 — 182 (15) 184 (15) Current service cost 3 — 24 9 27 9 Member contributions — — — 2 — 2 Interest cost 1 — 68 19 69 19 Benefits paid (4) — (77) (24) (81) (24) Expenses paid — — (1) — (1) — Settlements — — (24) — (24) — Other — — — 1 — 1 Foreign exchange translation — — (82) (22) (82) (22) Balance, end of year $ 36 $ 2 $ 1,725 $ 428 $ 1,761 $ 430 Plan assets Fair value, beginning of year $ 14 $ — $ 1,354 $ 791 $ 1,368 $ 791 Actual return on plan assets 1 — 284 177 285 177 Employer contributions 4 — 39 — 43 — Member contributions — — — 2 — 2 Benefits paid (4) — (77) (23) (81) (23) Expenses paid — — (1) — (1) — Settlements — — (25) — (25) — Foreign exchange translation — — (70) (41) (70) (41) Fair value, end of year $ 15 $ — $ 1,504 $ 906 $ 1,519 $ 906 Funded status $ (21) $ (2) $ (221) $ 478 $ (242) $ 476 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation. For the year ended December 31, 2020, AltaGas' pension plans incurred actuarial losses primarily due to the decrease in discount rates, which were the result of a decline in high-quality corporate bond yield curves in the Canadian and U.S. markets. For the year ended December, 31, 2019, AltaGas' defined benefit plans incurred actuarial losses for the same reason as mentioned above. AltaGas' post-retirement benefits plans incurred actuarial gains primarily due to updated census data and assumptions related to the HRA, partially offset by the decrease in discount rates. The following amounts were included in the Consolidated Balance Sheets: December 31, 2020 December 31, 2019 Defined Benefit Post- Retirement Benefits Total Defined Benefit Post-Retirement Benefits Total (a) Prepaid post-retirement benefits $ — $ 572 $ 572 $ — $ 487 $ 487 Accounts payable and accrued liabilities (a) (9) — (9) (26) — (26) Future employee obligations (145) (10) (155) (216) (11) (227) $ (154) $ 562 $ 408 $ (242) $ 476 $ 234 (a) Account balances on the Consolidated Balance Sheets also include certain non-pension related amounts. The accumulated benefit obligation for all defined benefit plans were: As at December 31, 2020 December 31, 2019 Canada United States Canada United States Accumulated benefit obligation (a) $ 36 $ 1,704 $ 35 $ 1,616 (a) Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels. For those pension plans where the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were: As at December 31, 2020 December 31, 2019 Defined Benefit Post-Retirement Benefits Defined Post-Retirement Benefits Projected benefit obligation $ 1,824 $ 14 $ 1,757 $ 13 Plan assets $ 1,670 $ 3 $ 1,515 $ 3 For those pension plans where the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were: As at December 31, 2020 December 31, 2019 Defined Benefit Post-Retirement Benefits Defined Post-Retirement Benefits Accumulated benefit obligation $ 427 $ 14 $ 1,648 $ 13 Plan assets $ 329 $ 3 $ 1,515 $ 3 The following amounts were recorded in other comprehensive income (loss) and have not yet been recognized in net periodic benefit cost: Year Ended December 31, 2020 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Past service cost $ — $ — $ — $ (3) $ — $ (3) Net actuarial gain (loss) (9) (1) 6 (8) (3) (9) Recognized in AOCI pre-tax $ (9) $ (1) $ 6 $ (11) $ (3) $ (12) Increase (decrease) by the amount 2 — (2) 3 — 3 Net amount in AOCI after-tax $ (7) $ (1) $ 4 $ (8) $ (3) $ (9) Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Net actuarial gain (loss) $ (9) $ — $ (15) $ 18 $ (24) $ 18 Recognized in AOCI pre-tax $ (9) $ — $ (15) $ 18 $ (24) $ 18 Increase (decrease) by the amount 2 — 7 (9) 9 (9) Net amount in AOCI after-tax $ (7) $ — $ (8) $ 9 $ (15) $ 9 The following amounts were recorded in a regulatory asset (liability) and have not yet been recognized in net periodic benefit cost: Year Ended December 31, 2020 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit $ — $ — $ — $ (94) $ — $ (94) Net actuarial loss (gain) — — 68 (241) 68 (241) Recognized in regulatory asset (liability) $ — $ — $ 68 $ (335) $ 68 $ (335) Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service cost (credit) $ — $ — $ 1 $ (105) $ 1 $ (105) Net actuarial loss (gain) — — 127 (156) 127 (156) Recognized in regulatory asset (liability) $ — $ — $ 128 $ (261) $ 128 $ (261) The costs of the defined benefit and post-retirement benefit plans are based on Management's estimate of the future rate of return on the fair value of pension plan assets, salary escalations, mortality rates and other factors affecting the payment of future benefits. The net pension expense by plan was as follows: Year Ended December 31, 2020 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 3 $ — $ 27 $ 9 $ 30 $ 9 Interest cost (b) 1 — 60 15 61 15 Expected return on plan assets (b) (c) (1) — (81) (40) (82) (40) Amortization of past service credit (b) — — — (19) — (19) Amortization of net actuarial loss (gain) (b) (c) 1 — 10 (5) 11 (5) Plan settlements (b) — — 7 — 7 — Net benefit cost (income) recognized $ 4 $ — $ 23 $ (40) $ 27 $ (40) (a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income. (b) Recorded under the line item “other income” on the Consolidated Statements of Income. (c) Includes the impact of the voluntary change in accounting principle implemented in 2020. Refer to Note 2 for additional information. Year Ended December 31, 2019 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 3 $ — $ 24 $ 9 $ 27 $ 9 Interest cost (b) 1 — 68 19 69 19 Expected return on plan assets (b) (1) — (75) (37) (76) (37) Amortization of past service credit (b) — — — (22) — (22) Amortization of net actuarial loss (b) 1 — 12 — 13 — Plan settlements (b) — — 4 — 4 — Other (b) — — — 1 — 1 Net benefit cost (income) recognized $ 4 $ — $ 33 $ (30) $ 37 $ (30) (a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income. (b) Recorded under the line item “other income” on the Consolidated Statements of Income. The objective for fund returns, over three five three five Cash and money market investments may be held from time to time as short-term investment decisions at the discretion of the fund manager(s) within the constraints prescribed by their mandate(s). The Corporation's target asset mix for the Canadian plans is 45 percent to 55 percent fixed income assets. The target asset mix for SEMCO plans is 33 percent fixed income assets and for WGL plans is 50 percent to 70 percent fixed income assets. These objectives have taken into account the nature of the liabilities and the risk-reward tolerance of the Corporation. The collective investment mixes for the plans are as follows as at December 31, 2020: Canada Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 2 $ 2 $ — 13 Canadian equities 3 3 — 19 Foreign equities 4 4 — 25 Fixed income 6 6 — 38 Real estate 1 — 1 5 $ 16 $ 15 $ 1 100 United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 14 $ 14 $ — 1 Canadian equities 1 1 — — Foreign equities (a) 357 357 — 13 Fixed income 1,002 129 873 37 Other (b) 23 — 23 1 Total investments in the fair value hierarchy $ 1,397 $ 501 $ 896 52 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 728 27 Private equity/limited partnership (e) 56 2 Pooled separate accounts (f) 32 1 Collective trust fund (g) 476 18 Total fair value of plan investments $ 2,689 100 Net payable (h) (6) — $ 2,683 100 (a) Investments in foreign equities include U.S. and international securities. (b) As at December 31, 2020, these investments consisted primarily of non-U.S. government bonds. (c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (d) As at December 31, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans. (e) As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies. (f) As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States. (g) As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments. (h) As at December 31, 2020, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. Total Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 16 $ 16 $ — 1 Canadian equities 4 4 — — Foreign equities (a) 361 361 — 13 Fixed income 1,008 135 873 37 Real estate 1 — 1 — Other (b) 23 — 23 1 Total investments in the fair value hierarchy $ 1,413 $ 516 $ 897 52 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 728 27 Private equity/limited partnership (e) 56 2 Pooled separate accounts (f) 32 1 Collective trust fund (g) 476 18 Total fair value of plan investments $ 2,705 100 Net payable (h) (6) — $ 2,699 100 (a) Investments in foreign equities include U.S. and international securities. (b) As at December 31, 2020, these investments consisted primarily of non-U.S. government bonds. (c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (d) As at December 31, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans. (e) As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies. (f) As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States. (g) As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments. (h) As at December 31, 2020, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. Year Ended December 31 2020 2019 Significant actuarial assumptions used in measuring net benefit plan costs Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 2.30 - 3.50 3.10 - 3.60 2.90 - 4.40 3.90 - 4.50 Expected long-term rate of return on plan assets (%) (a) 5.25 - 7.05 4.03 - 7.05 5.75 - 7.15 4.66 - 7.15 Rate of compensation increase (%) 2.75 - 4.00 3.50 2.75 - 4.10 4.10 Average remaining service life of active employees (years) 10.2 13.0 9.0 13.2 (a) Only applicable for funded plans As at December 31 2020 2019 Significant actuarial assumptions used in measuring benefit obligations Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 1.90 - 2.80 2.50 - 2.90 2.90 - 3.50 3.10 - 3.60 Rate of compensation increase (%) 1.73 - 3.93 2.50 - 3.00 2.75 - 4.00 3.50 The expected rate of return on assets is based on the current level of expected returns on risk free investments, the historical level of risk premium associated with other asset classes in which the portfolio is invested, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected rate of return on assets assumption for the portfolio. The discount rate is based on yields available on high-quality long-term corporate bonds, with maturities matching the estimated timing and amount of expected benefit payments. The estimates for health care benefits take into consideration increased health care benefits due to aging and cost increases in the future. The assumed health care cost trend rate used to measure the expected cost of benefits for the next year was between 2.2 and 6.0 percent. The health care cost trend rates were assumed to decline to between 2.2 and 4.5 percent by 2027. The following table shows the expected cash flows for defined benefit pension and other post-retirement plans: Defined Post-Retirement Expected employer contributions: 2021 $ 16 $ — Expected benefit payments: 2021 $ 90 $ 25 2022 $ 91 $ 22 2023 $ 88 $ 22 2024 $ 89 $ 21 2025 $ 90 $ 21 2026 - 2030 $ 466 $ 110

Commitments, Guarantees, and Co

Commitments, Guarantees, and Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments, Guarantees, and Contingencies	Commitments, Guarantees, and Contingencies Commitments AltaGas has long-term natural gas purchase and transportation arrangements, LPG purchase agreements, crude oil and condensate purchase agreements, electricity purchase arrangements, service agreements, pipeline and storage service contracts, capital commitments, environmental commitments, merger commitments, and operating leases for office space, office equipment, vehicles, rail cars, land, storage, aquatic surface use, and other equipment, all of which are transacted at market prices and in the normal course of business. Future payments of these commitments as at December 31, 2020 are estimated as follows: 2021 2022 2023 2024 2025 2026 & beyond Total Gas purchase (a) $ 1,974 $ 2,075 $ 1,858 $ 1,863 $ 1,901 $ 17,612 $ 27,283 LPG purchase (b) 407 199 161 108 83 258 1,216 Crude oil and condensate purchase (c) 184 — — — — — 184 Electricity purchase (d) 463 287 106 29 3 — 888 Service agreements (e) (f) (g) 48 32 26 27 27 282 442 Pipeline and storage services (h) 661 637 621 564 528 3,134 6,145 Capital projects (i) 20 1 1 1 1 1 25 Operating leases (j) 96 81 58 50 40 125 450 Environmental (k) 7 3 1 1 1 — 13 Merger commitments (l) 5 2 2 2 1 3 15 Land purchase commitment (m) 20 — — — — — 20 Post-acquisition contingent payments (n) — 16 — — — — 16 $ 3,885 $ 3,333 $ 2,834 $ 2,645 $ 2,585 $ 21,415 $ 36,697 (a) AltaGas enters into contracts to purchase natural gas from various suppliers for its utilities. These contracts are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. Gas purchase commitments are valued based on fixed prices and forward prices, which may fluctuate significantly from period to period. (b) AltaGas enters into contracts to purchase LPGs for its operations at RIPET and Ferndale. These contracts are used to ensure that there is an adequate supply of LPGs to meet shipment commitments and to minimize exposure to market price fluctuations. LPG purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period. (c) As part of the Petrogas Acquisition (Note 3), AltaGas acquired contracts to purchase crude oil and condensates for marketing, sale, and distribution. These contracts are used to ensure that there is an adequate supply of crude oil and condensates to meet the needs of customers and to minimize exposure to market price fluctuations. Crude oil and condensate commitments are valued based on forward prices, which may fluctuate significantly from period to period. (d) AltaGas enters into contracts to purchase electricity from various suppliers for its non-utility business. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include US$21 million of commitments related to renewable energy credits. (e) In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with a service pro to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hours per CT, or 25 years, whichever comes first. The LTSA has variable fees on a per equivalent operating hour basis. As at December 31, 2020, the total commitment was $153 million payable over the next 15 years, of which $44 million is expected to be paid over the next 5 years. (f) In 2017, AltaGas entered into a 12-year service agreement commencing in 2019 for tug services to support the marine operations of RIPET. (g) In 2015, AltaGas entered into a Project Agreement that contemplated the sublease of lands from Ridley Terminals Inc. (RTI), provision of certain terminal services, and access to RTI's terminal facilities to support RIPET's operations for an initial term of 20 years ending in 2039. In 2019, RILE LP and RTI executed a Terminal Services Agreement that formalized the concepts outlined in the Project Agreement. (h) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044. (i) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs. (j) Operating leases include lease arrangements for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land. (k) Environmental commitments include committed payments related to certain environmental response costs. (l) Represents the estimated future payments of WGL merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that were and will be expensed as the costs are incurred, including the investment of up to US$70 million over a ten year period to further extend natural gas service, investment of US$8 million for leak mitigation within three years, which has been paid as of December 31, 2020, hiring damage prevention trainers in each jurisdiction for a total of US$2 million over five years, and developing 15 megawatts of either electric grid energy storage or Tier 1 renewable resources within five years after the merger closed. As at December 31, 2020, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$12 million. (m) As part of the Petrogas Acquisition (Note 3), AltaGas acquired a commitment to purchase land as part of an agreement for it's continued use of the Ferndale terminal. (n) Contingent payments of up to $16 million are expected to be paid related to the Petrogas Acquisition (Note 3). Guarantees AltaGas has guaranteed payments primarily for certain commitments on behalf of some of its subsidiaries. AltaGas has also guaranteed payments for certain of its external partners. As at December 31, 2020, AltaGas has no guarantees to external parties. Contingencies AltaGas and its subsidiaries are subject to various legal claims and actions arising in the normal course of business. While the final outcome of such legal claims and actions cannot be predicted with certainty, the Corporation does not believe that the resolution of such claims and actions will have a material impact on the Corporation’s consolidated financial position or results of operations. Antero Contract In June 2019, a jury trial was held in the County Court for Denver, Colorado to consider a contractual dispute relating to gas pricing between Washington Gas and WGL Midstream (together, the Companies) and Antero Resources Corporation (Antero). Following the trial, the jury returned a verdict in favor of Antero for approximately US$96 million, of which approximately US$11 million was against Washington Gas with the remainder against WGL Midstream. Following the official entry of the judgment, the Companies filed an appeal on August 16, 2019. On December 10, 2020, the Colorado Court of Appeals issued an unpublished opinion affirming the judgement of the trial court. No further appeal has been taken. The judgment was paid in full in February 2021, and a satisfaction has been filed with the court. AltaGas recorded a net reduction to the acquired working capital of WGL of approximately US$45 million to account for the verdict in favor of Antero net of tax and other expected recoveries. Expected recoveries include a $18 million receivable recorded in "long-term investments and other assets" on the Consolidated Balance Sheets for amounts expected to be recovered under a commercial arrangement with a third party and $7 million recorded in "regulatory assets" on the Consolidated Balance Sheets for amounts expected to be recovered from customers in future periods through the rate-setting process. During 2020, AltaGas entered into an Escrow Agreement and a Letter Agreement with the third party to share the cost related to the judgment. Following the execution of the agreements, $9 million funded by the third party was deposited into an escrow fund and recorded as restricted cash in “accounts receivable". The previously recorded receivable was reduced accordingly. Maryland Show-Cause Order Following the National Transportation and Safety Board (NTSB) hearing that examined the August 10, 2016, explosion and fire at an apartment complex in Silver Spring, Maryland, on September 5, 2019, the PSC of MD ordered Washington Gas to (i) provide a detailed response to the NTSB’s probable cause findings and (ii) provide evidence regarding the status of a 2003 mercury regulator replacement program and, if the program was not completed, to show cause why the PSC of MD should not impose a civil penalty on Washington Gas (Show-Cause Order). Following several hearings throughout the course of 2019 and

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions In the normal course of business, AltaGas transacts with its subsidiaries, affiliates and joint ventures. Amounts due to or from related parties on the Consolidated Balance Sheets were measured at the exchange amount and were as follows: As at December 31, 2020 December 31, 2019 Due from related parties Accounts receivable (a) $ 5 $ 18 Long-term investments and other assets (b) — 45 $ 5 $ 63 Due to related parties Accounts payable (c) $ 3 $ 3 (a) Receivables from joint ventures and from a former affiliate of Petrogas. (b) For the period prior to December 15, 2020, AltaGas provided a $100 million interest bearing secured loan facility to Petrogas of which $50 million was committed. The facility was available for Petrogas to draw upon from time to time for general corporate purposes until the close of the Petrogas Acquisition on December 15, 2020. (c) Payables to a joint venture and a former affiliate of Petrogas. The following transactions with related parties have been recorded on the Consolidated Statements of Income for the years ended December 31, 2020 and 2019: Year Ended December 31 2020 2019 Revenue (a) $ 92 $ 115 Cost of sales (b) $ 12 $ 13 Operating and administrative expenses (recoveries) (c) $ 1 $ (2) Other income (d) $ 3 $ 3 (a) In the ordinary course of business, AltaGas sold commodities to TriSummit Utilities Inc. and Petrogas. (b) In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to affiliates. (c) Subsequent to the close of the Petrogas Acquisition, certain operating and administrative expenses were paid on behalf of Petrogas by a former affiliate. In 2019, administrative cost recoveries included those from joint ventures and from TriSummit Utilities Inc. under a Transition Services Agreement. (d) Interest income from loans to Petrogas (secured loan facility) prior to the acquisition of Petrogas.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2020
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information The following table details the changes in operating assets and liabilities from operating activities: Year Ended 2020 2019 Source (use) of cash: Accounts receivable $ 21 $ 168 Inventory 32 (2) Other current assets 1 (85) Regulatory assets - current (33) 7 Accounts payable and accrued liabilities (41) (280) Customer deposits (2) (17) Regulatory liabilities - current (55) 34 Risk management liabilities - current (1) 1 Other current liabilities 4 (6) Other operating assets and liabilities (129) (52) Changes in operating assets and liabilities $ (203) $ (232) The following table details the changes in non-cash investing and financing activities: Year Ended 2020 2019 (Increase) of balance: Common shares issued under DRIP $ (6) $ (68) Net right-of-use assets obtained in exchange for new operating lease liabilities $ 227 $ 50 Net right-of-use assets obtained in exchange for new finance lease liabilities $ 6 $ 5 Capital expenditures included in accounts payable and accrued liabilities $ (33) $ (7) The following cash payments have been included in the determination of earnings: Year Ended 2020 2019 Interest paid (net of capitalized interest) $ 276 $ 352 Income taxes paid $ 23 $ 67 The following table is a reconciliation of cash and restricted cash balances: As at December 31 2020 2019 Cash and cash equivalents $ 32 $ 57 Restricted cash holdings from customers - current 3 4 Restricted cash holdings from customers - non-current 2 4 Restricted cash included in prepaid expenses and other current assets (a) 9 25 Restricted cash included in long-term investments and other assets (note 12) (a) 19 32 Restricted cash included in accounts receivable (note 29) 9 — Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows $ 74 $ 122 (a) The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relate to Rabbi trusts associated with WGL’s pension plans (see Note 28).

Segmented Information

Segmented Information	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Segmented Information	Segmented Information AltaGas owns and operates a portfolio of assets and services used to move energy from the source to the end‑user. In 2020, AltaGas revised its reportable segments to align with the structure of its business following asset sales completed as part of its 2019 asset monetization program. As a result of these changes, AltaGas has refocused on its core Utilities and Midstream segments. Consistent with Management’s strategic view of the business and the basis on which it assesses performance and allocates resources, beginning in 2020, AltaGas has two operating segments: Utilities (which now includes the WGL retail marketing business) and Midstream. These operating segments have not been aggregated in the determination of AltaGas' reportable segments. All other assets are included in the Corporate/Other segment. Prior period segment information has been restated to conform to the current reporting segment presentation. The following describes the Corporation’s reporting segments: Utilities n rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia, Maryland, and Virginia; n rate-regulated natural gas storage in the United States; and n sale of natural gas to residential, commercial and industrial customers in Washington D.C., Maryland, Virginia, Delaware, Pennsylvania and Ohio. Midstream n NGL processing and extraction plants; n natural gas storage facilities; n liquefied petroleum gas (LPG) terminals; n transmission pipelines to transport natural gas and NGL; n natural gas gathering lines and field processing facilities; n purchase and sale of natural gas; n natural gas and NGL marketing; n marketing, storage and distribution of wellsite fluids and fuels, crude oil and condensate diluents; and n interest in a regulated pipeline in the Marcellus/Utica gas formation; Corporate/Other n the cost of providing corporate services, financing and general corporate overhead, investments in certain public and private entities, corporate assets, financing other segments and the effects of changes in the fair value of certain risk management contracts; and n a small portfolio of remaining power assets, certain of which are pending sale. The following table provides a reconciliation of segment revenue to the disaggregated revenue table disclosed in Note 24: Year Ended December 31, 2020 Utilities Midstream Corporate/Other Total External revenue (note 24) $ 3,817 $ 1,635 $ 135 $ 5,587 Intersegment revenue — 1 — 1 Segment revenue $ 3,817 $ 1,636 $ 135 $ 5,588 Year Ended December 31, 2019 Utilities Midstream Corporate/Other Total External revenue (note 24) $ 4,044 $ 1,228 $ 223 $ 5,495 Intersegment revenue — 32 — 32 Segment revenue $ 4,044 $ 1,260 $ 223 $ 5,527 Geographic Information Year Ended December 31 2020 2019 Revenue (a) Canada $ 1,512 $ 1,245 United States 4,053 4,325 TOTAL $ 5,565 $ 5,570 (a) Operating revenue from external customers, excluding unrealized gains or losses on risk management contracts. As at December 31 2020 2019 Property, plant and equipment Canada $ 3,149 $ 2,682 United States 7,739 7,443 TOTAL $ 10,888 $ 10,125 Operating right-of-use assets Canada $ 293 $ 85 United States 79 85 TOTAL $ 372 $ 170 The following tables show the composition by segment: Year Ended December 31, 2020 Utilities Midstream Corporate/Other Intersegment Elimination (a) Total Segment revenue (note 24) $ 3,817 $ 1,636 $ 135 $ (1) $ 5,587 Cost of sales (2,156) (994) (29) 1 (3,178) Operating and administrative (942) (254) (71) — (1,267) Accretion expenses — (4) (1) — (5) Depreciation and amortization (295) (86) (33) — (414) Provisions on assets (note 6) (1) (105) (3) — (109) Income from equity investments 5 44 — — 49 Other income 259 24 23 — 306 Foreign exchange gains (losses) — (26) 30 — 4 Interest expense — — (274) — (274) Income (loss) before income taxes $ 687 $ 235 $ (223) $ — $ 699 Net additions (reductions) to: Property, plant and equipment (b) $ 740 $ 136 $ (51) $ — $ 825 Intangible assets $ 3 $ 3 $ 4 $ — $ 10 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets. Year Ended December 31, 2019 Utilities Midstream Corporate/Other Intersegment Elimination (a) Total Segment revenue (note 24) $ 4,044 $ 1,260 $ 223 $ (32) $ 5,495 Cost of sales (2,448) (760) (51) 32 (3,227) Operating and administrative (960) (213) (126) — (1,299) Accretion expenses — (4) (1) — (5) Depreciation and amortization (276) (89) (73) — (438) Provision on assets (note 6) — (34) (382) — (416) Income from equity investments 19 122 — — 141 Other income 29 28 851 — 908 Foreign exchange gains (losses) — (5) 4 — (1) Interest expense — — (346) — (346) Income before income taxes $ 408 $ 305 $ 99 $ — $ 812 Net additions (reductions) to: Property, plant and equipment (b) $ 840 $ 351 $ (2,280) $ — $ (1,089) Intangible assets $ 23 $ 5 $ 9 $ — $ 37 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets. The following table shows goodwill and total assets by segment: Utilities Midstream Corporate/Other Total As at December 31, 2020 Goodwill $ 3,706 $ 1,333 $ — $ 5,039 Segmented assets $ 13,675 $ 7,320 $ 537 $ 21,532 As at December 31, 2019 Goodwill $ 3,781 $ 161 $ — $ 3,942 Segmented assets $ 13,719 $ 5,265 $ 811 $ 19,795

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Events	Subsequent EventsSubsequent events have been reviewed through February 25, 2021, the date on which these audited Consolidated Financial Statements were issued.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
BASIS OF PRESENTATION	BASIS OF PRESENTATION These Consolidated Financial Statements have been prepared by Management in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). Pursuant to National Instrument 52‑107, "Acceptable Accounting Principles and Auditing Standards" (NI 52‑107), financial statements of an “SEC issuer” may be prepared in accordance with U.S. GAAP. On January 21, 2020, AltaGas filed a final short form base shelf prospectus in Alberta and a corresponding registration statement on Form F-10 in the United States, by virtue of which AltaGas is now required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. As a result, AltaGas became an SEC issuer at such time and is now entitled to prepare its financial statements in accordance with U.S. GAAP.
PRINCIPLES OF CONSOLIDATION	PRINCIPLES OF CONSOLIDATION These Consolidated Financial Statements of AltaGas include the accounts of the Corporation, its subsidiaries, variable interest entities (VIEs) for which the Corporation is the primary beneficiary, and its interest in various partnerships and joint ventures where AltaGas has an undivided interest in the assets and liabilities. Investments in unconsolidated companies that AltaGas has significant influence, but not control, over are accounted for using the equity method. Hypothetical Liquidation at Book Value (HLBV) methodology is used for certain equity method investments as well as consolidating equity investments with non-controlling interests when the governing structuring agreement over the equity investment results in different liquidation rights and priorities than what is reflected by the underlying ownership interest percentage. The majority of AltaGas' HLBV investments were sold during 2019. All intercompany balances and transactions are eliminated on consolidation. Where there is a party with a non‑controlling interest in a subsidiary that AltaGas controls, that non‑controlling interest is reflected as “non‑controlling interests” in the Consolidated Financial Statements. The non‑controlling interests in net income of consolidated subsidiaries are shown as an allocation of the consolidated net income and are presented separately in "net income applicable to non-controlling interests".
USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY	USE OF ESTIMATES AND MEASUREMENT UNCERTAINTY The preparation of Consolidated Financial Statements in accordance with U.S. GAAP requires Management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenue and expenses during the period. Key areas where Management has made complex or subjective judgments, when matters are inherently uncertain, include but are not limited to: determining the nature and timing of satisfaction of performance obligations and determining the transaction price and amounts allocated to performance obligations for revenue recognition; depreciation and amortization rates; determination as to whether a contract is or contains a lease; determination of the classification, term, and discount rate for leases; fair value of asset retirement obligations; fair value of property, plant and equipment and goodwill for impairment assessments; fair value of financial instruments; measurement of credit losses; provisions for income taxes; assumptions used to measure employee future benefits; provisions for contingencies; purchase price allocations; and carrying value of regulatory assets and liabilities. Certain estimates are necessary for the regulatory environment in which AltaGas' subsidiaries or affiliates operate, which often require amounts to be recorded at estimated values until these amounts are
Rate-Regulated Operations	Rate-Regulated Operations SEMCO Gas, ENSTAR, Washington Gas, and Hampshire Gas (collectively the Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas and ENSTAR are regulated by the Michigan Public Service Commission (MPSC) and Regulatory Commission of Alaska (RCA), respectively. Washington Gas operates in the District of Columbia, Maryland, and Virginia, and is regulated in those jurisdictions by the Public Service Commission of the District of Columbia (PSC of DC), the Maryland Public Service Commission (PSC of MD), and the Commonwealth of Virginia State Corporation Commission (SCC of VA), respectively. Hampshire is regulated under a cost-of-service tariff by the Federal Energy Regulatory Commission (FERC). The MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA exercise statutory authority over matters such as tariffs, rates, construction, operations, financing, returns, accounting, and certain contracts with customers. In order to recognize the economic effects of the actions and decisions of the MPSC, RCA, PSC of DC, PSC of MD, and SCC of VA, the timing of recognition of certain assets, liabilities, revenues, and expenses as a result of regulation may differ from that otherwise expected using U.S. GAAP for entities not subject to rate regulation.
Cash and Cash Equivalents	Cash and Cash Equivalents
Restricted Cash Holdings from Customers	Restricted Cash Holdings from Customers Cash deposited, which is restricted and is not available for general use by AltaGas, is separately presented as restricted cash holdings in the Consolidated Balance Sheets. Pursuant to the acquisition of WGL Holdings, Inc. (the WGL Acquisition), rabbi trust funds were funded to satisfy certain Washington Gas executive and outside director retirement benefit plan obligations. The rabbi trust funds are invested in money market funds which are considered cash equivalents. These balances are included in "prepaid expenses and other current assets" and "long-term investments and other assets" in the Consolidated Balance Sheets. Additionally, cash deposited in an escrow fund related to a cost sharing agreement with a third party has been recorded as restricted cash in “accounts receivable" in the Consolidated Balance Sheets. Please refer to Note 29 for more information.
Accounts Receivable	Accounts Receivable Receivables are recorded net of the allowance for doubtful accounts in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for doubtful accounts is further adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely.
Inventory	Inventory
Property, Plant and Equipment (PP&E), Depreciation and Amortization	Property, Plant, and Equipment (PP&E), Depreciation and Amortization Property, plant, and equipment are carried at cost. The Corporation depreciates the cost of capital assets, net of salvage value, on a straight-line basis over the estimated useful life of the assets, with the exception of rate-regulated utilities assets, for which depreciation is calculated on a straight-line basis or over the contract term of a specific agreement at rates as approved by the regulatory authorities, and a small number of assets acquired as part of the acquisition of Petrogas for which depreciation is calculated using the declining balance method. The Utilities charge maintenance and repairs directly to operating expense and capitalize betterments and renewal costs. In accordance with regulatory requirements, depreciation expense includes an amount allowed for regulatory purposes to be collected in current rates for future removal and site restoration costs. Interest costs are capitalized on major additions to property, plant, and equipment until the asset is ready for its intended use. The interest rate used for calculating the interest costs to be capitalized is based on AltaGas' prior quarter actual borrowing long-term interest rate. The Utilities capitalize an imputed carrying cost on assets during construction as authorized by regulatory authorities and the amount so capitalized is an allowance for funds used during construction (AFUDC). AFUDC is the amount that a rate-regulated enterprise is allowed to recover for its cost of financing assets under construction. Capitalized overhead, administrative expenses, and AFUDC are included in the cost of the related assets and are recovered in rates charged to customers through depreciation expense, as allowed by the regulators. The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 4 to 69 years Midstream assets 3 to 55 years Corporate/Other assets 3 to 46 years As required by the regulatory authority, net additions to SEMCO's utility assets are amortized for one half-year in the year in which they are brought into active service. Net additions to WGL’s assets are amortized in the month after they are brought into active service.
Intangible Assets	Intangible Assets Intangible assets are recorded at cost. Intangible assets which have a finite useful life are amortized on a straight-line basis over their term or estimated useful life. The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 years Software 3 to 20 years Land rights 5 to 43 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 to 20 years
Assets Held for Sale	Assets Held for Sale The Corporation classifies assets as held for sale when the carrying amount will be principally recovered through a sale transaction rather than through continuing use. This condition is met when Management approves and commits to a formal plan to sell the assets, the assets are available for immediate sale in their present condition, and Management expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying value or the estimated fair value less cost to sell. Assets held for sale are not depreciated or amortized.
Business Acquisitions	Business Acquisitions Business acquisitions are accounted for using the acquisition method. Under the acquisition method, assets and liabilities of the acquired entity are recorded at fair value at the date of acquisition. Acquisition-related costs are expensed as incurred. Goodwill represents the excess of purchase price over the fair value of the net assets acquired. Management applies its best estimates and assumptions to determine the fair value of net assets acquired; however, the estimates are subject to further refinement of assumptions over a measurement period, which may be up to one year from the acquisition date. During the measurement period, adjustments to assets acquired and liabilities assumed may be recorded, with a corresponding impact to goodwill.
Provision on Assets	Provisions on Assets If facts and circumstances suggest that a long-lived asset or an intangible asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset is not recoverable, as determined by the projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized.
Investments Accounted for by the Equity Method	Investments Accounted for by the Equity Method The equity method of accounting is used for investments in which AltaGas has the ability to exercise significant influence, but does not have a controlling interest. Equity investments are initially measured at cost and are adjusted for the Corporation’s proportionate share of earnings or losses. Equity investments are increased for contributions made and decreased for distributions received. To the extent an investee undertakes activities necessary to commence its planned principal operations, the Corporation will capitalize interest costs associated with its investment during such period. The HLBV methodology is used to allocate earnings or losses for certain WGL equity method investments when WGL’s ownership interest percentage is different than distribution percentages. When applying HLBV accounting, the Corporation determines the amount that it would receive if an equity investment entity were to liquidate all of its assets at book value (as valued in accordance with U.S. GAAP) and distribute that cash to the investors based on the contractually defined liquidation priorities. The change in the Corporation’s claim on the equity investment entity's book value at the beginning and end of the reporting period (adjusted for contributions and distributions) is the Corporation’s share of the earnings or losses from the equity investment for the period.
Financial Instruments	Financial Instruments Non-Utility Operations All financial instruments are initially recorded at fair value unless they qualify for, and are designated under, a normal purchase and normal sale (NPNS) exemption. Subsequent measurement of the financial instruments is based on their classification. The financial assets are classified as "held-for-trading", "held-to-maturity", or "loans and receivables". Financial liabilities are classified as "held-for-trading" or other financial liabilities. Subsequent measurement is determined by classification. A physical contract generally qualifies for the NPNS exemption if the transaction is reasonable in relation to AltaGas’ business needs and AltaGas has the ability, and intent, to deliver or take delivery of the underlying item. AltaGas continually assesses the contracts designated under the NPNS exemption and will discontinue the treatment of these contracts under this exemption where the criteria are no longer met. Held-for-trading instruments include non-derivative financial assets and financial assets and liabilities that may consist of swaps, options, forwards, and equity securities. These financial instruments are initially recorded at their fair value, with subsequent changes in fair value recorded in net income. Held-to-maturity, loans and receivables, and other financial liabilities are recognized at amortized cost using the effective interest method unless they are held-for-sale and recognized at the lower of cost or fair value less transaction fees. Investments in equity instruments not accounted for under the equity method that do not have a quoted market price in an active market are measured at cost. Income earned from these investments is included in the Consolidated Statements of Income under "other income". Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded separately and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a standalone derivative, and the entire contract is not held-for-trading or accounted for at fair value. Changes in fair value are included in earnings. The fair values recorded on the Consolidated Balance Sheets reflect netting of the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Transaction costs related to the acquisition of held-for-trading financial assets and liabilities are expensed as incurred. Transaction costs for obtaining debt financing other than line-of-credit arrangements are recognized as a direct deduction from the related debt liability on the Consolidated Balance Sheets. Transaction costs related to line-of-credit arrangements are capitalized and included under "long-term investments and other assets" on the Consolidated Balance Sheets. Premiums and discounts are netted against long-term debt on the Consolidated Balance Sheets. The deferred charges are amortized over the life of the related debt on an effective interest basis and included in “interest expense” on the Consolidated Statements of Income. Regulated Utility Operations All physical and financial derivative contracts are initially recorded at fair value. Changes in the fair value of derivative instruments that are recoverable or refunded to customers when they settle are recorded as regulatory assets or liabilities. Changes in the fair value of derivatives not affected by rate regulation are reflected in net income.
Weather-Related Instruments	Weather-Related Instruments
Hedges	Hedges As part of its risk management strategy, AltaGas may use derivatives to reduce its exposure to commodity price, interest rate, and foreign exchange risk. AltaGas may designate certain U.S. dollar-denominated debt as a net investment hedge of its U.S. subsidiaries. No other derivatives have been designated as hedges under ASC Topic 815. Non-Utility Operations The change in fair value of cash flow hedges is recognized in OCI. Gains or losses from cash flow hedges are reclassified to net income when the hedged transaction affects earnings, such as when the hedged forecasted transaction occurs. Regulated Utility Operations
Credit Losses	Credit Losses The following are the Corporation's significant accounting policies upon adoption of ASC 326: Accounts receivable, contract assets, a loan to an affiliate, and other long-term receivables within the scope of ASC 326 are recorded net of the allowance for credit losses in the Consolidated Balance Sheets. AltaGas regularly analyzes and evaluates the collectability of the accounts receivable based on a combination of factors. If circumstances related to the collectability change, the allowance for credit losses is adjusted. Accounts are written off when collection efforts are complete and future recovery is unlikely. See below for a description of how expected credit loss estimates are developed. Utilities Customer Receivables and Contract Assets AltaGas is exposed to risk through the non-payment of utility bills by customers. To manage this customer credit risk, AltaGas' regulated utilities customers are offered budget billing options or high risk customers may be required to provide a cash deposit until the requirement for deposit refunds are met. AltaGas can recover a portion of non-payments from customers in future periods through the rate-setting process. For accounts receivable generated by the Utilities business, an allowance for credit losses is recorded against revenue and is recognized using a historical loss-rate based on historical payment and collection experience. This rate may be adjusted based on Management’s expectations of unusual macroeconomic conditions and other factors. AltaGas regularly evaluates the reasonableness of the allowance based on a combination of factors, such as: the length of time receivables are past due, historical expected payment, collection experience, financial condition of customers, and other circumstances that could impact customers' ability or desire to make payments. For retail energy marketing customer receivables where AltaGas has enrolled in a regulatory utility purchase of receivable program, the associated utility discount rate is used to determine credit losses. Midstream Customer Receivables and Contract Assets AltaGas operates under an existing credit policy that is designed to mitigate credit risk. Credit limits are established for each counterparty and credit enhancements such as letters of credit, parent guarantees, and cash collateral may be required. The creditworthiness of all counterparties is continuously monitored. A credit loss reserve is recorded for receivables with customers and trading counterparties AltaGas considers to be below investment grade by applying an estimated loss rate. The estimated loss rate is based on the historical default rates published by external rating agencies. For accounts receivable, a one-year rate is used. For contract assets, historical loss rates associated with the estimated time frame that the contract asset will be billed to the customer is used. In the event a customer or trading counterparty no longer exhibits similar risk characteristics, the associated receivable is evaluated individually. Other For other long-term receivables, associated counterparties are evaluated and assigned internal credit ratings based on AltaGas' credit policy. An allowance for credit losses is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivables are expected to be collected.
Debt	Debt AltaGas uses short-term debt in the form of commercial paper and advances under its syndicated bank credit facilities to fund seasonal cash requirements. Short-term obligations are excluded from current liabilities if AltaGas has the ability and the intent to refinance these obligations on a long-term basis. The ability to refinance is primarily demonstrated through the availability of
Asset Retirement Obligations	Asset Retirement Obligations AltaGas recognizes asset retirement obligations in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be determined. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the estimated useful life of the asset. The liability is increased due to the passage of time over the estimated period until the settlement of the obligation, with a corresponding charge to accretion expense for asset retirement obligations. There are timing differences between accretion and depreciation amounts being recorded pursuant to GAAP and the recognition of depreciation expense for legal asset removal costs that are recovered in rates, as allowed by the regulators. These timing differences are recorded as a reduction to “regulatory liabilities” in accordance with ASC 980.
Revenue Recognition	Revenue Recognition
Foreign Currency Translation	Foreign Currency Translation Monetary assets and liabilities denominated in a foreign currency are converted to the functional currency using the exchange rate in effect at the balance sheet date. Adjustments resulting from the conversion are recorded in the Consolidated Statements of Income. Non-monetary assets and liabilities are converted at the historical exchange rate in effect at the transaction date. Revenues and expenses are converted at the exchange rate applicable at the transaction date. For foreign entities with a functional currency other than Canadian dollars, AltaGas’ reporting currency, assets and liabilities are translated into Canadian dollars at the rate in effect at the reporting date. Revenues and expenses are translated at average exchange rates during the reporting period. All adjustments resulting from the translation of the foreign operations are recorded in OCI.
Share Options and Other Compensation Plans	Share Options and Other Compensation Plans Share options granted are recorded using fair value. Compensation expense is measured at the date of the grant using the Black-Scholes-Merton model and is recognized over the vesting period of the options. Consideration received by AltaGas on exercise of the share options is credited to shareholders’ equity. AltaGas has a phantom unit plan (Phantom Plan, formerly the medium-term incentive plan) for employees and executive officers which includes two types of awards: restricted units (RUs) and performance units (PUs). A portion of AltaGas’ RUs and
Pension Plans and Post-Retirement Benefits	Pension Plans and Post-Retirement Benefits AltaGas maintains defined benefit pension plans, defined contribution plans, and other post-retirement benefit plans for eligible employees. Contributions made by the Corporation to the defined contribution plans are expensed in the period in which the contribution occurs. The cost of defined benefit pension plans and post-retirement benefits is actuarially determined using the projected benefit method prorated based on service and Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees, expected health care costs, and other actuarial factors including discount rates and mortality. Pension plan assets are measured at fair value. The expected return on plan assets is based on historical and projected rates of return for each asset class in the plan portfolio. The projected benefit obligation is discounted using the market interest rate on high-quality debt instruments with cash flows matching the timing and amount of benefit payments. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation and the fair value of plan assets or the market-related value of assets along with any unamortized past service costs and credits are amortized on a straight-line basis over the expected average remaining service life of active employees. The expected average remaining service period of the active members covered by the defined benefit pension plans and post-retirement benefit plans is 10.2 years and 13.0 years, respectively. AltaGas recognizes the overfunded or underfunded status of its pension and post-retirement benefit plans as either assets or liabilities in the Consolidated Balance Sheets. Unrecognized actuarial gains and losses and past service costs and credits that arise during the period are recognized in OCI or a regulatory asset or liability. For certain regulated utilities, the Corporation expects to recover pension expense in future rates and therefore records unrecognized balances as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees. In 2020, AltaGas made a voluntary change in accounting principle for calculating the market-related value of assets (MRVA) used in the determination of Washington Gas' net periodic pension and other post-retirement benefit plan costs. The change uses the fair value approach for the fixed income investment asset class of the plan assets, compared to the prior method that utilized a calculated value where gains and losses arising from changes in fair value were deferred and amortized into the calculation of the MRVA over a period of five years. The MRVA is used in the calculation of the expected return on assets and the recognized actuarial gain or loss components of net periodic benefit cost. The approach applied for all other classes of assets remains unchanged. Management believes that using the fair value approach for the fixed income investments in plan assets is preferable as it more closely aligns the recognition of related components within the net periodic benefit cost.
Income Taxes	Income Taxes Income taxes for the Corporation and its subsidiaries are calculated using the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based on differences between the carrying value and the tax basis of assets and liabilities and are measured using the enacted tax rates and laws that are in effect in the periods in which the differences are expected to be settled or realized. Deferred income tax assets are routinely reviewed, and a valuation allowance is recorded to reduce the deferred tax assets if it is more likely than not that deferred tax assets will not be realized. The financial statement effects of an uncertain tax position are recognized when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxing authority. The current and deferred tax impact is equal to the largest amount, considering possible settlement outcomes, that is greater than 50 percent likely of being realized upon settlement with the taxing authorities. Investment tax credits are recognized as reductions to income tax expense over the estimated service lives of the related properties.
Net Income per Share	Net Income per Share Basic net income per common share is computed using the weighted average number of common shares outstanding during the period. Dilutive net income per common share is calculated using the weighted average number of common shares outstanding adjusted for dilutive common shares related to the Corporation’s share-based compensation awards.
Contingencies	Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Any such accruals are adjusted thereafter as additional information becomes available or circumstances change.
Leases - Lessee	Leases – Lessee AltaGas determines if an arrangement is a lease at inception. Operating leases are included in right-of-use (ROU) assets, current operating lease liabilities, and long-term operating lease liabilities in the Consolidated Balance Sheets. Finance leases are included in property, plant and equipment and current and long-term debt in the Consolidated Balance Sheets. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Operating lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. AltaGas uses the rate implicit in the lease when readily determinable. When the implicit lease rate is not readily determinable, AltaGas uses its incremental borrowing rate to determine the present value of lease payments. AltaGas includes lessee options to renew or terminate the lease term in the determination of the ROU asset and lease liability when exercise is reasonably certain. The operating lease ROU asset is adjusted for lease payments made in advance of the commencement date, initial direct costs, and any lease incentives. Operating lease expense is recognized on a straight-line basis over the lease term in "operating and administrative expense". Depreciation and interest expense are recorded on finance leases.
Leases - Lessor	Leases – Lessor AltaGas determines if an arrangement is a lease at inception. Lease payments under an operating lease are recognized on a straight-line basis over the term of the lease. Variable lease payments are recognized as revenue as the facts and circumstances on which the variable lease payment is based occur. AltaGas does not include taxes assessed by governmental authorities, such as sales and related taxes, in the lease payments or variable lease payments.
Collaborative Agreements	Collaborative Arrangements
ADOPTION OF NEW ACCOUNTING STANDARDS AND FUTURE CHANGES IN ACCOUNTING PRINCIPLES	ADOPTION OF NEW ACCOUNTING STANDARDS Effective January 1, 2020, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU): § In June 2016, FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses and all related amendments (collectively "ASC 326"): Measurement of Credit Losses on Financial Instruments”. The ASU replaces the current “incurred loss” impairment methodology with an “expected loss” model for financial assets measured at amortized cost. AltaGas has applied ASC 326 using the modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date of the new standard. Prior periods presented for comparative purposes were not adjusted. Upon adoption of ASC 326, "accounts receivable, net of allowances" decreased by $2 million and "long-term investments and other assets" decreased by $5 million, with an offsetting increase to "accumulated deficit". AltaGas has elected to account for its cash equivalents at fair value. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details; § ASU No. 2018-13 “Fair Value Measurement – Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement”. The amendments in this ASU modify the disclosure requirements on fair value measurements. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements, but resulted in certain minor adjustments to the fair value disclosures. Please also refer to Note 23 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details; § ASU No. 2018-17 “Consolidation: Targeted Improvements to Related Party Guidance for Variable Interest Entities”. The amendments in this ASU provide a private-company scope exception to the VIE guidance for certain entities and clarify that indirect interests held through related parties under common control are considered on a proportional basis when determining whether fees paid to decision makers and service providers are variable interests. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; § ASU No. 2018-18 "Collaborative Arrangements: Clarifying the Interaction between Topic 808 and Topic 606". The amendments in this ASU clarifies that certain transactions between collaborative arrangement participants should be accounted for as revenue under ASC 606, adds unit-of-account guidance in ASC 808 to align with the guidance in ASC 606, and requires that a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, is precluded from presenting the transaction together with revenue recognized under ASC 606 if the collaborative arrangement participant is not a customer. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; § ASU No. 2019-01 "Leases: Codification Improvements". The amendments in this ASU provide a fair value exception for lessors that are not manufacturers or dealers, clarifies the presentation of principal payments received under sales-type and direct finance leases for depository and lending institutions, and clarifies that interim transition disclosure requirements related to the change on income statement, net income and related per share amounts for the adoption of ASC 842 are not required. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; § ASU No. 2019-04 “Financial Instruments: Codification Improvements". The amendments in this ASU provide clarification and improve the codification in recently issued accounting standards relating to credit losses, hedge accounting, and financial instruments. The amendments related to credit losses were evaluated in conjunction with ASU 2016-13 above. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements; and § ASU No. 2020-03 "Codification Improvements to Financial Instruments". The amendments in this ASU provide clarification and improve the codification to certain aspects of accounting standards related to financial instruments. The adoption of this ASU did not have a material impact on AltaGas’ consolidated financial statements. Effective December 31, 2020, AltaGas adopted the following FASB issued ASU: § ASU No. 2018-14 “Compensation-Retirement Benefits-Defined Benefit Plans – General: Disclosure Framework – Changes to the Disclosure Requirements for the Defined Benefit Plans”. The amendments in this ASU modify the disclosure requirements on defined benefit pension and other post-retirement plans. The adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements, but resulted in certain modifications to the disclosures in the pension footnote. Please also refer to Note 28 of the Consolidated Financial statements as at and for the year ended December 31, 2020 for further details. FUTURE CHANGES IN ACCOUNTING PRINCIPLES In December 2019, FASB issued ASU No. 2019-12 "Income Taxes: Simplifying the Accounting for Income Taxes". The amendments in this ASU simplify the accounting for income taxes by clarifying certain aspects of current guidance and removing some exceptions to the general principles in ASC 740. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. The adoption of this ASU is not expected to have a material impact on AltaGas’ financial statements. In January 2020, FASB issued ASU No. 2020-01 "Derivatives and Hedging: Clarifying the Interactions between Topic 321, Topic 323, and Topic 815". The amendments in this ASU clarify the application of the measurement alternative for equity instruments and the measurement of non-derivative forward contracts or purchased call options used to acquire equity securities. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas’ financial statements. In March 2020, FASB issued ASU No. 2020-04 "Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting." The amendments in this ASU provide optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships affected by reference rate reform if certain criteria are met. These apply only to contracts, hedging relationships, and other transactions that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. The amendments in this ASU are effective as of March 12, 2020 through December 31, 2022. AltaGas may elect to apply the amendments as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020 on a prospective basis. AltaGas has not elected to adopt this ASU as of December 31, 2020, and is assessing the impact of this ASU on its consolidated financial statements.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Summary of Estimated Useful Lives of Property, Plant and Equipment	The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 4 to 69 years Midstream assets 3 to 55 years Corporate/Other assets 3 to 46 years As at December 31, 2020 December 31, 2019 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value Utilities $ 7,791 $ (286) $ 7,505 $ 7,316 $ (155) $ 7,161 Midstream 4,094 (951) 3,143 3,182 (585) 2,597 Corporate/Other 842 (598) 244 1,025 (636) 389 Reclassified to assets held for sale (4) — (4) (24) 2 (22) $ 12,723 $ (1,835) $ 10,888 $ 11,499 $ (1,374) $ 10,125
Summary of Estimated Useful Lives of Finite-Lived Intangible Assets	The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 years Software 3 to 20 years Land rights 5 to 43 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 to 20 years As at December 31, 2020 December 31, 2019 Cost Accumulated Net book Cost Accumulated Net book E&T contracts $ 26 $ (16) $ 10 $ 27 $ (15) $ 12 Electricity service agreements — — — 9 (8) 1 Energy services relationships 90 (45) 45 91 (27) 64 Software 304 (133) 171 304 (102) 202 Land rights 1 — 1 1 — 1 Commodity contracts 332 (20) 312 327 (21) 306 $ 753 $ (214) $ 539 $ 759 $ (173) $ 586

Acquisition of Petrogas Energ_2

Acquisition of Petrogas Energy Corporation (Tables)	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
Schedule of Final Purchase Price Allocation	The following table summarizes the preliminary purchase price allocation representing the consideration paid and the estimated fair value of the net assets acquired as at December 15, 2020. The purchase price allocation is preliminary and reflects Management’s current best estimate of the fair value of Petrogas' assets and liabilities based on the analysis of information obtained to date. Management is continuing to obtain specific information to support the valuation of property, plant and equipment, intangibles, investments accounted for by the equity method, non-controlling interest, contingencies, income taxes, environmental matters and asset retirement obligations. As additional information becomes available, the purchase price allocation may differ materially from the preliminary purchase price allocation below. The offset to any adjustments made to the aforementioned financial statement captions during the measurement period are expected to be recorded in goodwill. Any adjustments to the purchase price allocation will be made as soon as practicable but no later than one year from the date of acquisition. Fair value of previously held interest in AltaGas Idemitsu Joint Venture LP (AIJVLP) on the acquisition date $ 631 Less: Carrying value of previously held interest in AIJVLP (609) Gain on re-measurement of previously held interest $ 22 Purchase consideration for an additional 37 percent of Petrogas $ 715 Deemed settlement of intercompany debt 120 Fair value of previously held interest on the acquisition date 631 Less: Fair value assigned to net assets Current assets 536 Property, plant and equipment 523 Intangible assets 10 Operating right-of-use assets 192 Long-term investments and other assets 4 Investments accounted for by the equity method 125 Current liabilities (363) Long-term debt (53) Asset retirement obligations (13) Deferred income taxes (21) Operating lease liabilities (152) Other long-term liabilities (26) Fair value of net assets acquired $ 762 Fair value of AIJVLP's non-controlling interest in Petrogas on the acquisition date 467 Goodwill $ 1,171
Business Acquisition, Pro Forma Information	The following supplemental unaudited, pro forma consolidated financial information for the years ended December 31, 2020 and 2019 gives effect to the Petrogas Acquisition as if it had closed on January 1, 2019. This pro forma information is presented for information purposes only and does not purport to be indicative of the results that would have occurred had the Petrogas Acquisition taken place at the beginning of 2019, nor is it indicative of the results that may be expected in future periods. Year Ended December 31 2020 2019 Pro forma revenue $ 7,917 $ 9,217 Pro forma net income after tax $ 537 $ 1,004

Assets Held For Sale (Tables)

Assets Held For Sale (Tables)	12 Months Ended
	Dec. 31, 2020
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Assets Held for Sale	As at December 31, 2020 December 31, 2019 Assets held for sale Property, plant and equipment $ 4 $ 22 Operating right-of-use assets — 1 Goodwill — 1 Other long-term assets — 3 $ 4 $ 27 Liabilities associated with assets held for sale Unamortized investment tax credits $ 1 $ 3 Operating lease liabilities - long-term — 1 $ 1 $ 4

Provisions on Assets (Tables)

Provisions on Assets (Tables)	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Provisions on Assets	Year Ended December 31 2020 2019 Midstream $ 106 $ 34 Corporate/Other 3 382 $ 109 $ 416

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2020
Inventory Disclosure [Abstract]
Schedule of Inventory	As at December 31 2020 2019 Natural gas held in storage (a) $ 309 $ 359 Natural gas liquids 116 26 Materials and supplies 84 57 Renewable energy credits and emission compliance instruments 80 64 Crude oil and condensate 43 — Processed finished products 4 — $ 636 $ 506 (a) As at December 31, 2020, $193 million of the natural gas held in storage was held by rate-regulated utilities (2019 - $214 million).

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	The range of useful lives for AltaGas’ PP&E is as follows: Utilities assets 4 to 69 years Midstream assets 3 to 55 years Corporate/Other assets 3 to 46 years As at December 31, 2020 December 31, 2019 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value Utilities $ 7,791 $ (286) $ 7,505 $ 7,316 $ (155) $ 7,161 Midstream 4,094 (951) 3,143 3,182 (585) 2,597 Corporate/Other 842 (598) 244 1,025 (636) 389 Reclassified to assets held for sale (4) — (4) (24) 2 (22) $ 12,723 $ (1,835) $ 10,888 $ 11,499 $ (1,374) $ 10,125

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Summary of Intangible Assets	The range of useful lives for intangible assets with a finite life is as follows: Energy services relationships 5 years Software 3 to 20 years Land rights 5 to 43 years Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 5 to 20 years As at December 31, 2020 December 31, 2019 Cost Accumulated Net book Cost Accumulated Net book E&T contracts $ 26 $ (16) $ 10 $ 27 $ (15) $ 12 Electricity service agreements — — — 9 (8) 1 Energy services relationships 90 (45) 45 91 (27) 64 Software 304 (133) 171 304 (102) 202 Land rights 1 — 1 1 — 1 Commodity contracts 332 (20) 312 327 (21) 306 $ 753 $ (214) $ 539 $ 759 $ (173) $ 586
Summary of Estimated Amortization Expense of Intangible Assets	The following table sets forth the estimated amortization expense of intangible assets, excluding any amortization of assets not yet subject to amortization as well as assets with an indefinite life, for the years ended December 31: 2021 $ 75 2022 $ 72 2023 $ 60 2024 $ 39 2025 $ 15 Thereafter $ 102

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Components of Lease cost	The components of lease expense were as follows: Year Ended Year Ended Operating lease cost (includes variable lease payments) $ 43 $ 29 Finance lease cost Amortization of right-of-use assets $ 4 $ 4 Total finance lease cost $ 4 $ 4 Total lease cost $ 47 $ 33 Supplemental cash flow information related to leases was as follows: Year Ended December 31 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ (36) $ (21) Financing cash flows from finance leases (a) $ (4) $ (4) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 227 $ 50 Finance leases $ 6 $ 5 (a) Included within repayment of long-term debt on the Consolidated Statements of Cash Flows. As at December 31, December 31, Weighted average remaining lease term (years) Operating leases 7.4 10.9 Finance leases 4.8 5.2 Weighted average discount rate (%) Operating leases 2.42 3.51 Finance leases 2.89 3.68
Supplemental Balance Sheet Location	Supplemental balance sheet information related to leases was as follows: As at December 31 2020 2019 Operating Leases Operating lease right-of-use assets Long-term $ 372 $ 170 Total operating lease right-of-use assets $ 372 $ 170 Operating lease liabilities Current $ (95) $ (27) Long-term (304) (153) Total operating lease liabilities $ (399) $ (180) Finance Leases Property and equipment, gross $ 19 $ 13 Accumulated depreciation (7) (3) Property and equipment, net $ 12 $ 10 Current portion of long-term debt $ (4) $ (4) Long-term debt (8) (6) Total finance lease liabilities $ (12) $ (10)
Operating Lease Liability, Maturity Analysis	Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2021 $ 96 $ 4 2022 81 4 2023 58 2 2024 50 1 2025 40 1 Thereafter 125 2 Total lease payments 450 14 Less: imputed interest (51) (2) Total $ 399 $ 12
Finance Lease Liability, Maturity Analysis	Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2021 $ 96 $ 4 2022 81 4 2023 58 2 2024 50 1 2025 40 1 Thereafter 125 2 Total lease payments 450 14 Less: imputed interest (51) (2) Total $ 399 $ 12
Maturity Analysis of Lease Receivables	Maturity analysis of lease receivables was as follows: Operating 2021 $ 127 2022 117 2023 108 2024 41 2025 41 Thereafter 404 Total $ 838

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	As at December 31, December 31, Balance, beginning of year $ 3,942 $ 4,068 Business acquisition (note 3) 1,171 — Adjustment to goodwill on business acquisition — 92 Goodwill included in dispositions — (29) Reclassified to assets held for sale — (1) Foreign exchange translation (74) (188) Balance, end of year $ 5,039 $ 3,942

Long-Term Investments and Oth_2

Long-Term Investments and Other Assets (Tables)	12 Months Ended
	Dec. 31, 2020
Investments, All Other Investments [Abstract]
Schedule of Long-Term and Other Investments	As at December 31, December 31, Investments in publicly-traded entities $ — $ 4 Loan to affiliate (notes 23 and 30) — 45 Deferred lease receivable 12 17 Debt issuance costs associated with credit facilities 3 6 Refundable deposits 9 9 Prepayment on long-term service agreements 70 81 Deferred information technology costs 4 — Cash calls from joint venture partners 26 10 Contract asset (net of credit losses of $1 million) (notes 23 and 24) 50 30 Rabbi trust and other restricted cash (notes 28, 29 and 31) 19 32 Other long-term receivables (net of credit losses of $2 million) (notes 23 and 29) 18 33 Capitalized contract costs 5 — Financial transmission rights 12 12 Other 17 18 $ 245 $ 297

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2020
VARIABLE INTEREST ENTITIES [Abstract]
Schedule of VIE Amounts in Consolidated Balance Sheets	The following table represents amounts included in the Consolidated Balance Sheets attributable to AltaGas’ consolidated VIE: As at December 31, 2020 December 31, 2019 Current assets $ 7 $ 6 Property, plant and equipment 358 371 Long-term investments and other assets 50 53 Current liabilities (2) (3) Asset retirement obligations (2) (3) Net assets $ 411 $ 424

Investments Accounted for by _2

Investments Accounted for by the Equity Method (Tables)	12 Months Ended
	Dec. 31, 2020
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Equity Method Investments	Carrying value as at December 31 Equity income (loss) for the year ended December 31 Description Location Ownership Percentage 2020 2019 2020 2019 AltaGas Canada Inc. (ACI) (a) Canada — $ — $ 164 $ 3 $ 17 AltaGas Idemitsu Joint Venture LP (b) Canada — — 431 (25) 63 Constitution Pipeline, LLC (Constitution) (c) United States — — — (7) — Eaton Rapids Gas Storage System United States 50 26 27 2 1 Meade Pipeline Co. LLC (d) United States — — — — (4) Mountain Valley Pipeline, LLC (Mountain Valley) (e) United States 10 718 672 62 43 Sarnia Airport Storage Pool LP Canada 50 18 18 1 1 Petrogas Preferred Shares (f) Canada n/a — 150 13 13 Petrogas Terminals Penn LLC (g) United States 37 1 — — — Stonewall Gas Gathering Systems LLC (d) United States — — — — 7 Strathcona Storage LP (g) Canada 30 124 — — — $ 887 $ 1,462 $ 49 $ 141 (a) ACI was acquired by the Public Sector Pension Investment Board and the Alberta Teachers' Retirement Fund Board on March 31, 2020 (Note 4). (b) Upon acquisition of Petrogas on December 15, 2020 (Note 3), AltaGas no longer has an equity investment in AIJVLP. (c) The equity method is considered appropriate because Constitution is a Limited Liability Company (LLC) with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. In February 2020, the partners of Constitution elected not to proceed with the pipeline project and Constitution was dissolved. The loss recorded in 2020 relates to a provision recorded against the equity investment (see below for further discussion). (d) Disposed of in 2019. (e) The equity method is considered appropriate because Mountain Valley is an LLC with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream exercising a more than minor influence over the investee's operating and financing policies. (f) Petrogas' preferred shares ceased to be an investment accounted for by the equity method after AltaGas acquired a controlling interest in Petrogas on December 15, 2020 (Note 3). (g) Acquired on December 15, 2020 as part of the Petrogas Acquisition (Note 3).
Schedule of Combined Financial Information of Equity Method Investments	Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows: Year Ended December 31 (a) 2020 2019 Revenues $ 828 $ 1,109 Expenses (181) (355) $ 647 $ 754 As at December 31 (a) 2020 2019 Current assets $ 351 $ 411 Property, plant and equipment $ 7,598 $ 8,034 Intangible assets $ — $ 22 Long-term investments and other assets $ 5 $ 1,459 Current liabilities $ (281) $ (394) Other long-term liabilities $ (2) $ (992) (a) For equity investments that were disposed of in the periods presented, revenues and expenses reflect the period prior to disposition and balance sheet amounts are $nil. For equity investments that were acquired in the year (Note 3), revenues and expenses reflect the period subsequent to acquisition and balance sheet amounts are included as at December 31, 2020.

Short-term Debt (Tables)

Short-term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Schedule of Short-Term Debt	As at December 31, December 31, Commercial paper (a) $ 236 $ 389 Project financing 20 71 $ 256 $ 460

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	As at Maturity date December 31, December 31, Credit facilities $1,400 million unsecured extendible revolving facility (a) 15-May-2023 $ 802 $ 90 US$300 million unsecured extendible revolving facility 27-Feb-2021 — 390 US$150 million unsecured extendible revolving facility 20-Dec-2023 81 163 Commercial paper (b) Various 260 367 $175 million secured extendible revolving facility 18-Jun-2022 51 — AltaGas Ltd. medium-term notes (MTNs) $200 million Senior unsecured - 4.07 percent 1-Jun-2020 — 200 $350 million Senior unsecured - 3.72 percent 28-Sep-2021 350 350 $500 million Senior unsecured - 2.61 percent 16-Dec-2022 500 500 $300 million Senior unsecured - 3.57 percent 12-Jun-2023 300 300 $200 million Senior unsecured - 4.40 percent 15-Mar-2024 200 200 $300 million Senior unsecured - 3.84 percent 15-Jan-2025 300 300 $500 million Senior unsecured - 2.16 percent 10-Jun-2025 500 — $350 million Senior unsecured - 4.12 percent 7-Apr-2026 350 350 $200 million Senior unsecured - 3.98 percent 4-Oct-2027 200 200 $500 million Senior unsecured - 2.08 percent 30-May-2028 500 — $200 million Senior unsecured - 2.48 percent 30-Nov-2030 200 — $100 million Senior unsecured - 5.16 percent 13-Jan-2044 100 100 $300 million Senior unsecured - 4.50 percent 15-Aug-2044 300 300 $250 million Senior unsecured - 4.99 percent 4-Oct-2047 250 250 WGL and Washington Gas MTNs US$250 million Senior unsecured - 2.44 percent (c) 12-Mar-2020 — 325 US$20 million Senior unsecured - 6.65 percent 20-Mar-2023 25 26 US$41 million Senior unsecured - 5.44 percent 11-Aug-2025 52 53 US$53 million Senior unsecured - 6.62 to 6.82 percent Oct 2026 67 69 US$72 million Senior unsecured - 6.40 to 6.57 percent Feb - Sep 2027 92 93 US$52 million Senior unsecured - 6.57 to 6.85 percent Jan - Mar 2028 66 67 US$9 million Senior unsecured - 7.50 percent 1-Apr-2030 11 11 US$50 million Senior unsecured - 5.70 to 5.78 percent Jan - Mar 2036 64 65 US$75 million Senior unsecured - 5.21 percent 3-Dec-2040 95 97 US$75 million Senior unsecured - 5.00 percent 15-Dec-2043 95 97 US$300 million Senior unsecured - 4.22 to 4.60 percent Sep - Nov 2044 382 390 US$450 million Senior unsecured - 3.80 percent 15-Sep-2046 573 584 US$400 million Senior unsecured - 3.65 percent (d) 15-Sep-2049 530 390 SEMCO long-term debt US$300 million SEMCO Senior Secured - 5.15 percent (e) 21-Apr-2020 — 390 US$82 million SEMCO Senior Secured - 4.48 percent (f) 2-Mar-2032 69 76 US$225 million First Mortgage Bonds - 3.15 percent 21-Apr-2030 286 — US$225 million First Mortgage Bonds - 2.45 percent 21-Apr-2050 286 — Fair value adjustment on WGL Acquisition 80 84 Finance lease liabilities (note 10) 12 10 $ 8,029 $ 6,887 Less debt issuance costs (43) (36) $ 7,986 $ 6,851 Less current portion (360) (923) $ 7,626 $ 5,928 (a) Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, LIBOR loans, bankers' acceptances, or letters of credit. Borrowings on the facility have fees and interest at rates relevant to the nature of the draw made. (b) Commercial paper is supported by the availability of long-term committed credit facilities with maturity dates ranging from 2022 to 2024. Commercial paper intended to be repaid within the next year is recorded as short-term debt (Note 15). (c) Floating rate per annum reset quarterly based on terms set forth in the prospectus filed by WGL pursuant to Securities Act Rule 424 on March 13, 2018. (d) On December 10, 2020, Washington Gas issued MTNs with an aggregate principal amount of $100 million. This offering constituted the reopening of it's $300 million MTNs originally issued in 2019. The total includes a US$17 million premium which will be amortized as a reduction to interest expense over the term of the note. (e) Collateral for the U.S. dollar MTNs is certain SEMCO assets. (f) Collateral for the CINGSA Senior secured loan is certain CINGSA assets. Alaska Storage Holding Company, LLC, a subsidiary in which AltaGas has a controlling interest, is the non-recourse guarantor of this loan.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes in Asset Retirement Obligations	As at December 31 2020 2019 Balance, beginning of year $ 362 $ 500 Obligations acquired (note 3) 13 — New obligations 14 7 Obligations settled (4) (2) Disposals (1) (6) Revision in estimated cash flow (10) (129) Accretion expense (a) 17 19 Foreign exchange translation (6) (21) Total $ 385 $ 368 Less: current portion (included in accounts payable and accrued liabilities) (6) (6) Balance, end of year $ 379 $ 362

Other Long-term Liabilities (Ta

Other Long-term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
Other Liabilities Disclosure [Abstract]
Schedule of Other Long-Term Liabilities	As at December 31, December 31, Deferred revenue $ 8 $ 4 Customer advances for construction 60 64 Merger commitments 10 14 Other employee benefits 6 6 Deferred payroll taxes (a) 6 — Petrogas equalization reserve (b) 5 — Uncertain tax positions (note 20) 21 2 Non-pension retirement benefits 16 — Other 21 12 $ 153 $ 102 (a) Represents U.S. federal payroll tax deferrals from the Coronavirus Aid, Relief, and Economic Security (CARES) Act. (b) Reserve is held by a wholly owned subsidiary of Petrogas.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Schedule of Income Tax Provision	Year Ended December 31 2020 2019 Income before income taxes - consolidated $ 699 $ 812 Statutory income tax rate (%) 24.0 26.5 Expected taxes at statutory rates $ 168 $ 215 Add (deduct) the tax effect of: Permanent differences $ 2 $ 11 Statutory and other rate differences 9 (52) Rate adjustment for change in tax rates — (11) Deferred income tax recovery on regulated assets (15) (25) Tax differences on divestitures and transactions (33) (159) Change in valuation allowance (2) (11) Other (2) 4 $ 127 $ (28) Income tax provision Current $ 1 $ 63 Deferred 126 (91) $ 127 $ (28) Effective income tax rate (%) 18.2 (3.4)
Schedule of Deferred Income Tax Liabilities	Net deferred income tax liabilities were composed of the following: As at December 31, December 31, PP&E and intangible assets $ 1,645 $ 1,450 Regulatory assets (229) (204) Tax pools, deferred financing, and compensation (208) (138) Other (94) (161) Valuation allowance 4 12 $ 1,118 $ 959
Schedule of Uncertain Tax Positions	Management determined that the following provision was required for uncertainty on income taxes during the year: Year ended December 31 2020 2019 Balance, beginning of year $ 2 $ 2 Gross increases for tax positions of prior year 21 — Lapses of statute of limitations (2) — Balance, end of year $ 21 $ 2

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	The following table summarizes the regulatory assets and liabilities recorded in the Consolidated Balance Sheets, as well as the remaining period, as at December 31, 2020 and 2019, over which the Corporation expects to realize or settle the assets or liabilities: As at December 31 2020 2019 Recovery Regulatory assets - current Deferred cost of gas (a) $ 18 $ 8 Less than one year Accelerated replacement recovery mechanisms (b) 6 2 Less than one year Interruptible sharing (a) 2 3 Less than one year Energy optimization costs 1 — Less than one year Virginia and Maryland revenue normalization (a) 19 — Less than one year $ 46 $ 13 Regulatory assets - non-current Deferred regulatory costs (a) (c) $ 158 $ 150 2 - 55 years Future recovery of pension and other retirement benefits (a) 68 128 Various Future recovery of non-retirement employee benefits (a) (d) 22 19 Various Deferred environmental costs (a) (e) 15 18 Various Deferred loss on debt transactions and derivative instruments (a) (f) 93 99 Various Deferred future income taxes (a) (g) 46 43 Various Energy efficiency program - Maryland (h) 18 12 Various COVID-19 costs (i) 10 — Various Other 14 18 Various $ 444 $ 487 Regulatory liabilities - current Deferred cost of gas (a) $ 56 $ 61 Less than one year Refundable tax credit (j) 2 2 Less than one year Federal income tax rate change (k) 20 33 Less than one year Virginia rate refund (l) — 41 Less than one year Interruptible sharing (a) 1 — Less than one year Virginia Coronavirus Relief Fund (m) 10 — Less than one year Other 1 9 Less than one year $ 90 $ 146 Regulatory liabilities - non-current Refundable tax credit (j) 2 4 2 years Future expense of pension and other retirement benefits (a) 335 261 Various Future removal and site restoration costs (n) 462 484 Various Deferred gain on debt transactions and derivative instruments (a) (f) 1 2 Various Federal income tax rate change (k) 578 628 Various Other 3 4 Various $ 1,381 $ 1,383 (a) Washington Gas is not entitled to a rate of return on these assets. Washington Gas is allowed to recover and required to pay, using short-term interest rates, the carrying costs related to billed gas costs due from and to its customers in the District of Columbia and Virginia jurisdictions. (b) Represents amounts for deferred over or under collections of surcharges associated with Washington Gas' accelerated pipeline recovery programs in the District of Columbia, Maryland, and Virginia. (c) Includes deferred gas costs and fair value of derivatives, which are not included in customer bills until settled. (d) Represents the timing difference between the recognition of workers compensation and short-term disability costs in accordance with generally accepted accounting principles and the way these costs are recovered through rates. Certain utilities have recovered pension costs related to regulated operations in rates, and as such, the Corporation has recorded a regulatory asset for the unamortized costs associated with the defined benefit and post-retirement benefit plans. Depending on the method utilized by the utility, the recovery period can be either the expected service life of the employees, the benefit period for employees, or a specific recovery period as approved by the respective regulator. (e) This balance represents allowed environmental remediation expenditures at SEMCO and Washington Gas sites to be recovered through rates. (f) The losses or gains on the issuance and extinguishment of debt and interest-rate derivative instruments include unamortized balances from transactions executed in prior years. These transactions create gains and losses that are amortized over the remaining life of the debt as prescribed by regulatory accounting requirements. As at December 31, 2020, this also includes a fair value adjustment of $76 million (December 31, 2019 - $80 million) recorded on the WGL Acquisition in 2018. (g) This balance represents amounts due from customers for deferred tax assets and liabilities related to tax benefits/expenses on deductions flowed directly to customers prior to the adoption of income tax normalizations for ratemaking purposes and to tax rate changes. (h) Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland. (i) Regulatory assets established to capture and track incremental COVID-19 related costs. (j) On September 18, 2013, CINGSA received a US$15 million gas storage facility tax credit from the State of Alaska for the benefit of its firm storage service customers. CINGSA will derive no direct or indirect benefit from the tax credit. Following receipt of the tax credit, CINGSA deposited it in a separate interest-bearing account. CINGSA will act as a custodian of the tax credit and any interest earned for the benefit of CINGSA's customers. On an annual basis, covering the years 2012 through 2021, CINGSA will disburse to the customers 1/10th of the amount of the tax credit not subject to refund to the State and interest earned. The RCA has approved the disbursement methodology. (k) The Tax Cuts and Jobs Act (TCJA) was enacted on December 22, 2017, and required the Corporation to revalue its U.S. deferred tax assets and liabilities in 2018 to the lower federal corporate tax rate of 21 percent, resulting in excess accumulated deferred income taxes. The tax rate reduction created a reduction in deferred tax liability, which SEMCO Gas and Washington Gas are required to refund to ratepayers. (l) Represents estimated refunds related to customers billed at a higher rate during the interim period as part of the 2019 Virginia rate case. (m) The Virginia Coronavirus Relief Fund was received by WGL to provide direct assistance to Virginia customers with balances over 30 days in arrears. (n) This amount and timing of draw down is dependent upon the cost of removal of underlying utility property, plant and equipment and the life of property, plant and equipment.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of Accumulated Other Comprehensive Income	($ millions) Defined benefit pension and PRB plans Hedge net investments Translation foreign operations Equity investee Total Opening balance, January 1, 2020 $ (6) $ (149) $ 395 $ 5 $ 245 OCI before reclassification (11) (10) (175) (5) (201) Amounts reclassified from OCI 3 — — — 3 Current period OCI (pre-tax) (8) (10) (175) (5) (198) Income tax on amounts retained in AOCI 3 1 — — 4 Income tax on amounts reclassified to earnings (1) — — — (1) Net current period OCI (6) (9) (175) (5) (195) Ending balance, December 31, 2020 $ (12) $ (158) $ 220 $ — $ 50 Opening balance, January 1, 2019 $ (19) $ (209) $ 801 $ 6 $ 579 OCI before reclassification 15 68 (406) (1) (324) Amounts reclassified from OCI 1 — — — 1 Current period OCI (pre-tax) 16 68 (406) (1) (323) Income tax on amounts retained in AOCI (3) (8) — — (11) Net current period OCI 13 60 (406) (1) (334) Ending balance, December 31, 2019 $ (6) $ (149) $ 395 $ 5 $ 245
Summary of Reclassification from Accumulated Other Comprehensive Income	Reclassification From Accumulated Other Comprehensive Income AOCI components reclassified Income statement line item Year Ended December 31, 2020 Year Ended Defined benefit pension and PRB plans Other income $ 3 $ 1 Deferred income taxes Income tax expense – deferred (1) — $ 2 $ 1

Financial Instruments and Fin_2

Financial Instruments and Financial Risk Management (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Fair Value of Risk Management Assets and Liabilities	As at December 31, 2020 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income (a) Risk management assets - current $ 94 $ — $ 73 $ 21 $ 94 Risk management assets - non-current 38 — 2 36 38 Fair value through regulatory assets (a) Risk management assets - current 4 — 1 3 4 Risk management assets - non-current 9 — — 9 9 $ 145 $ — $ 76 $ 69 $ 145 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 102 $ — $ 78 $ 24 $ 102 Risk management liabilities - non-current 66 — 15 51 66 Fair value through regulatory liabilities (a) Risk management liabilities - current 9 — — 9 9 Risk management liabilities - non-current 79 — 1 78 79 Amortized cost Current portion of long-term debt 360 — 360 — 360 Long-term debt 7,626 — 8,451 — 8,451 Other current liabilities (b) 37 — 37 — 37 $ 8,279 $ — $ 8,942 $ 162 $ 9,104 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Excludes non-financial liabilities. As at December 31, 2019 Carrying Level 1 Level 2 Level 3 Total Financial assets Fair value through net income (a) Risk management assets - current $ 82 $ — $ 31 $ 51 $ 82 Risk management assets - non-current 31 — 7 24 31 Equity securities (b) 4 4 — — 4 Fair value through regulatory assets (a) Risk management assets - current 5 — — 5 5 Risk management assets - non-current 8 — — 8 8 Amortized cost Loans and receivables (b) 45 — 46 — 46 $ 175 $ 4 $ 84 $ 88 $ 176 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 121 $ — $ 99 $ 22 $ 121 Risk management liabilities - non-current 77 — 19 58 77 Fair value through regulatory liabilities (a) Risk management liabilities - current 4 — 1 3 4 Risk management liabilities - non-current 90 — — 90 90 Amortized cost Current portion of long-term debt 923 — 923 — 923 Long-term debt 5,928 — 6,264 — 6,264 Other current liabilities (c) 15 — 15 — 15 $ 7,158 $ — $ 7,321 $ 173 $ 7,494 (a) To manage price risk associated with acquiring natural gas supply for Maryland, Virginia, and District of Columbia utility customers, Washington Gas, a subsidiary of the Corporation, enters into physical and financial derivative transactions. Any gains and losses associated with these derivatives are recorded as regulatory liabilities or assets, respectively, to reflect the rate treatment for these economic hedging activities. Additionally, as part of its asset optimization program, Washington Gas enters into derivatives with the primary objective of securing operating margins that Washington Gas will ultimately realize. Regulatory sharing mechanisms provide for the annual realized profit from these transactions to be shared between Washington Gas' shareholder and customers; therefore, changes in fair value are recorded through earnings, or as regulatory assets or liabilities to the extent that it is probable that realized gains and losses associated with these derivative transactions will be included in the rates charged to customers when they are realized. (b) Included under the line item "long-term investments and other assets" on the Consolidated Balance Sheets. (c) Excludes non‑financial liabilities.
Quantitative Information About the Significant Unobservable Inputs Used In The Fair Value Measurement Of Level 3	The following table includes quantitative information about the significant unobservable inputs used in the fair value measurement of Level 3 financial instruments as at December 31, 2020: Net Fair Value Valuation Technique Unobservable Inputs Range Weighted Average (a) Natural gas $ (73) Discounted Cash Flow Natural Gas Basis Price (per Dth) $ (1.27) - $ 2.64 $ (0.37) Natural gas $ (1) Option Model Natural Gas Basis Price (per Dth) $ (1.27) - $ 2.58 $ (0.01) Annualized Volatility of Spot Market Natural Gas 13 % - 917 % 73 % Electricity $ (19) Discounted Cash Flow Electricity Congestion Price (per MWh) $ (6.26) - $ 61.88 $ 13.57 (a) Unobservable inputs were weighted by transaction volume.
Changes In Net Fair Value Of Derivative Assets And Liabilities Classified As Level 3	The following tables provide a reconciliation of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy: For the year ended December 31 2020 2019 Natural Electricity Total Natural Electricity Total Balance, beginning of year $ (85) $ — $ (85) $ (149) $ (14) $ (163) Realized and unrealized gains (losses): Recorded in income 8 (55) (47) 48 1 49 Recorded in regulatory assets (1) — (1) 24 — 24 Transfers into Level 3 (1) — (1) (9) — (9) Transfers out of Level 3 1 — 1 12 — 12 Purchases — 3 3 — (11) (11) Settlements 4 32 36 (17) 24 7 Foreign exchange translation — 1 1 6 — 6 Balance, end of year $ (74) $ (19) $ (93) $ (85) $ — $ (85)
Realized and Unrealized Losses Recorded To Income For Level 3 Measurements	Realized and Unrealized Gains (Losses) Recorded to Income for Level 3 Measurements Year Ended December 31 2020 2019 Recorded to revenue $ (79) $ 75 Recorded to cost of sales 32 (26) $ (47) $ 49
Summary of Unrealized Gains (Losses) on Risk Management Contracts	Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income Year Ended December 31 2020 2019 Natural gas $ 32 $ 23 Energy exports 10 (87) Crude oil and NGLs 4 — NGL frac spread (5) (17) Power (15) (5) Foreign exchange (5) 1 $ 21 $ (85)
Schedule of Offsetting Assets and Liabilities	As at December 31, 2020 Gross amounts of recognized Gross amounts Netting Net amounts Risk management assets (a) Natural gas $ 104 $ (38) $ (3) $ 63 Energy exports 86 (86) 36 36 Crude oil and NGLs 1 — — 1 Power 30 (8) — 22 Foreign exchange 27 (3) (1) 23 $ 248 $ (135) $ 32 $ 145 Risk management liabilities (b) Natural gas $ 173 $ (38) $ (3) $ 132 Energy exports 153 (86) — 67 NGL frac spread 6 — — 6 Power 58 (8) 1 51 Foreign exchange 3 (3) — — $ 393 $ (135) $ (2) $ 256 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $98 million and risk management assets (non‑current) balance of $47 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $111 million and risk management liabilities (non‑current) balance of $145 million. As at December 31, 2019 Gross amounts of Gross amounts Netting Net amounts Risk management assets (a) Natural gas $ 121 $ (54) $ — $ 67 Energy exports 10 (3) 5 12 Power 54 (7) — 47 $ 185 $ (64) $ 5 $ 126 Risk management liabilities (b) Natural gas $ 226 $ (54) $ (28) $ 144 Energy exports 90 (3) — 87 NGL frac spread 2 — — 2 Power 69 (7) (3) 59 $ 387 $ (64) $ (31) $ 292 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $87 million and risk management assets (non‑current) balance of $39 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $125 million and risk management liabilities (non‑current) balance of $167 million. Cash Collateral The following table presents collateral not offset against risk management assets and liabilities: As at December 31, December 31, Collateral posted with counterparties $ 4 $ 29 Cash collateral held representing an obligation $ — $ — As at December 31, December 31, Risk management liabilities with credit-risk-contingent features $ 32 $ 42 Maximum potential collateral requirements $ 26 $ 29
Schedule of Notional Amounts of Outstanding Derivative Positions	AltaGas had the following forward contracts and commodity swaps outstanding related to the activities in the energy services business as at December 31, 2020 and 2019: December 31, 2020 Fixed price Period Notional volume (GJ) Fair Value Sales 1.58 to 7.86 1-157 590,054,996 $ 32 Purchases 1.58 to 6.47 1-240 1,522,958,497 $ (106) Swaps 2.29 to 7.86 1-60 288,613,586 $ 5 December 31, 2019 Fixed price Period Notional volume (GJ) Fair Value Sales 1.32 to 6.81 1-166 698,126,985 $ 29 Purchases 0.22 to 6.81 1-167 1,406,991,689 $ (104) Swaps 0.22 to 10.24 1-51 541,652,374 $ (2) December 31, 2020 Fixed price Period Notional volume (Bbl) Fair Value Sales 37.43 to 62.59 1 680,000 $ (1) Purchases 19.92 to 59.01 1-9 221,000 $ 2 December 31, 2020 Fixed price Period Notional volume Fair Value Propane and butane swaps 3.57 to 61.46 1-36 37,425,488 $ (31) December 31, 2019 Fixed price Period Notional volume Fair Value Propane 21.49 to 29.71 1-27 9,374,826 $ (75) AltaGas entered into a series of swaps to lock in a portion of the volumes exposed to NGL frac spread. AltaGas had the following contracts outstanding as at December 31, 2020 and 2019: December 31, 2020 Fixed price Period Notional volume Fair Value Propane swaps 28.83 to 35.36/Bbl 1-12 1,270,350 Bbl $ (5) Butane swaps 32.45 to 34.02/Bbl 1-12 307,784 Bbl $ (1) Crude oil swaps 60.08 to 61.95/Bbl 1-12 123,120 Bbl $ — Natural gas swaps 1.58 to 1.86/GJ 1-12 7,281,570 GJ $ — December 31, 2019 Fixed price Period Notional volume Fair Value Butane swaps 73.02 to 75.15/Bbl 1-12 346,852 Bbl $ (1) Crude oil swaps 73.02 to 75.15/Bbl 1-12 212,587 Bbl $ (1) Natural gas swaps 1.58 to 1.86/GJ 1-12 3,883,992 GJ $ — December 31, 2020 Fixed price Period Notional volume Fair Value Power sales 24.56 to 61.75 1-33 5,482,242 $ 13 Power purchases 24.56 to 61.88 1-63 8,848,007 $ (18) Swap purchases (6.26) to 74.26 1-44 24,081,519 $ (24) December 31, 2019 Fixed price Period Notional volume Fair Value Power sales 31.63 to 66.76 1-42 8,034,024 $ 39 Power purchases 31.63 to 66.76 1-60 8,552,467 $ (27) Swap purchases (7.88) to 74.26 1-48 25,058,577 $ (24) In connection with the Petrogas Acquisition, AltaGas acquired various commodity and financial derivative instruments, including the following foreign exchange forward contracts which are outstanding as at December 31, 2020: Foreign exchange forward contract Notional Amount Duration Weighted average foreign exchange rate Fair Value Forward USD sales US$29 Less than one year 1.3591 $ 3 Forward USD purchases US$356 Less than one year 1.2824 $ (3) Foreign exchange swaps (purchases) US$410 Less than one year 1.3322 $ 23
Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives	The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2020: Factor Increase or decrease to forward prices Increase or decrease to income before tax ($ millions) PJM power price US$1/MWh 2 AECO natural gas price $0.50/GJ 1 NYMEX natural gas price US$0.50/GJ 36 Energy Exports: Propane Far East Index to domestic supply $1/Bbl 10 Baltic LPG Freight $1/Bbl 11 NGL frac spread: Propane $1/Bbl 1 Natural gas $0.50/GJ 4 Foreign exchange swaps $0.01 CAD to USD 1
Schedule of Accounts Receivable Past Due or Impaired	As at December 31, 2020 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 1,465 $ 396 $ 41 $ 906 $ 52 $ 17 $ 53 Other 20 — — 20 — — — Allowance for credit losses (41) — (41) — — — — $ 1,444 $ 396 $ — $ 926 $ 52 $ 17 $ 53 As at December 31, 2019 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 1,238 $ 343 $ 33 $ 758 $ 61 $ 12 $ 31 Other 17 — — 17 — — — Allowance for credit losses (33) — (33) — — — — $ 1,222 $ 343 $ — $ 775 $ 61 $ 12 $ 31 The following table provides a summary of changes to the allowance for credit losses by segment and major type: Year Ended December 31, 2020 Accounts Receivable Contract Assets (a) Other long-term investments and other assets (b) Total Utilities Balance, beginning of period $ 31 $ — $ — $ 31 Adjustment upon adoption of ASC 326 (c) 2 — — 2 Foreign exchange translation (1) — — (1) New allowance (d) 32 — — 32 Written off (28) — — (28) Recoveries collected 4 — — 4 Balance, end of period $ 40 $ — $ — $ 40 Midstream Balance, beginning of period $ 1 $ — $ — 1 Adjustment upon adoption of ASC 326 — 1 3 4 Recoveries collected — — (1) (1) Balance, end of period $ 1 $ 1 $ 2 $ 4 Corporate/Other Balance, beginning of period $ 2 $ — $ — $ 2 Adjustment upon adoption of ASC 326 — — 1 1 Written off (2) — — (2) Recoveries collected — — (1) (1) Balance, end of period $ — $ — $ — $ — Total $ 41 $ 1 $ 2 $ 44 (a) An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate associated with the estimated time frame that the contract asset will be billed to the customer. (b) Includes loan to affiliate, which is no longer outstanding at December 31, 2020, and other long-term receivables (Notes 12 and 29). An allowance for credit loss is assessed quarterly and is recorded based on historical default rates published by external credit rating agencies and a rate commensurate with the period in which the receivable is expected to be collected. (c) Based on previous collection experience, AltaGas did not record an allowance for credit losses for its contract assets associated with its energy management services projects with the U.S. federal government. (d) Includes
Schedule of Contractual Maturities for Financial Liabilities	AltaGas had the following contractual maturities with respect to financial liabilities: Contractual maturities by period As at December 31, 2020 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,561 $ 1,561 $ — $ — $ — Dividends payable 22 22 — — — Short-term debt 256 256 — — — Other current liabilities (a) 37 37 — — — Risk management contract liabilities 256 111 51 22 72 Current portion of long-term debt (b) 356 356 — — — Long-term debt (b) 7,581 — 1,771 1,324 4,486 $ 10,069 $ 2,343 $ 1,822 $ 1,346 $ 4,558 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition. Contractual maturities by period As at December 31, 2019 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,325 $ 1,325 $ — $ — $ — Dividends payable 22 22 — — — Short-term debt 460 460 — — — Other current liabilities (a) 15 15 — — — Risk management contract liabilities 292 125 34 13 120 Current portion of long-term debt (b) 920 920 — — — Long-term debt (b) 5,873 — 1,489 922 3,462 $ 8,907 $ 2,867 $ 1,523 $ 935 $ 3,582 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, and the fair value adjustment on the WGL Acquisition.

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue by Major Sources	The following tables disaggregate revenue by major sources for the year: Year Ended December 31, 2020 Utilities Midstream Corporate/Other Total (a) Revenue from contracts with customers Commodity sales contracts $ 1,338 $ 1,097 $ 1 $ 2,436 Midstream service contracts — 277 — 277 Gas sales and transportation services 2,394 — — 2,394 Storage services 25 — — 25 Other 9 — 20 29 Total revenue from contracts with customers $ 3,766 $ 1,374 $ 21 $ 5,161 Other sources of revenue Revenue from alternative revenue programs (b) $ 96 $ — $ — $ 96 Leasing revenue (c) 1 139 100 240 Risk management and trading activities (d) (e) (31) 112 — 81 Other (15) 10 14 9 Total revenue from other sources $ 51 $ 261 $ 114 $ 426 Total revenue $ 3,817 $ 1,635 $ 135 $ 5,587 (a) In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information. (b) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (c) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (d) Risk management activities involve the use of derivative instruments such as physical and financial swaps, forward contracts, and options. These derivatives are accounted for under ASC 815 and ASC 825. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users. (e) Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2020 of $437 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018. Revenue from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020. Year Ended December 31, 2019 Utilities Midstream Corporate/Other Total (a) Revenue from contracts with customers Commodity sales contracts $ 1,428 $ 746 $ 51 $ 2,225 Midstream service contracts — 145 — 145 Gas sales and transportation services 2,501 — — 2,501 Storage services 28 — — 28 Other 9 3 29 41 Total revenue from contracts with customers $ 3,966 $ 894 $ 80 $ 4,940 Other sources of revenue Revenue from alternative revenue programs (b) $ 30 $ — $ — $ 30 Leasing revenue (c) 1 137 105 243 Risk management and trading activities (d) (e) 52 188 22 262 Other (5) 9 16 20 Total revenue from other sources $ 78 $ 334 $ 143 $ 555 Total revenue $ 4,044 $ 1,228 $ 223 $ 5,495 (a) In the first quarter of 2020, AltaGas revised its reportable segments. Comparative period numbers have been adjusted to reflect this change. Refer to Note 32 for additional information. (b) A large portion of revenue generated from the Utilities segment is subject to rate regulation and accordingly there are circumstances where the revenue recognized is mandated by the applicable regulators in accordance with ASC 980. (c) Revenue generated from certain of AltaGas’ gas facilities is accounted for as operating leases. For the Corporate/Other segment, a significant amount of revenue earned is through power purchase agreements which are accounted for as operating leases. (d) Risk management activities involve the use of derivative instruments such as physical and financial swaps, and forward contracts. These derivatives are accounted for under ASC 815 and ASC 825. A portion of revenue generated by the Utilities segment is from the physical sale and delivery of natural gas and power to end users. (e) Trading margins in the Midstream segment are reported in risk management and trading activities. AltaGas enters into derivative contracts for the purpose of optimizing its storage and transportation capacity as well as managing the transportation and storage assets on behalf of third parties. The trading margins, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2019 of $505 million associated with the GAIL Global (USA) LNG LLC (GAIL) contract and an Asset Management Agreement (AMA), which are in scope of ASC 606, are reported within risk management and trading activities. Revenue from the GAIL contract is recognized at a point in time based on the actual volumes of the commodity sold at the delivery point, which corresponds to the customer’s monthly invoice amount. The GAIL contract has a term of 20 years and began on March 31, 2018. Revenue from the AMA is recognized based on the amount WGL Midstream has the right to invoice the customer in accordance with ASC 606. WGL executed the AMA in April 2020.
Contract with Customer, Asset and Liability	Contract Assets As at December 31, December 31, Balance, beginning of year $ 89 $ 59 Additions 30 32 Transfers to accounts receivable (49) — Foreign exchange translation 1 (2) Balance, end of year $ 71 $ 89 Contract Liabilities As at December 31, December 31, Balance, beginning of year $ 2 $ 2 Additions 2 2 Revenue recognized from contract liabilities (a) (4) (2) Balance, end of year $ — $ 2
Schedule of Estimated Revenue Related to Performance Obligations	The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied as of December 31, 2020: 2021 2022 2023 2024 2025 2026 & beyond Total Midstream service contracts $ 125 $ 131 $ 128 $ 128 $ 125 $ 1,037 $ 1,674 Storage services 24 23 23 23 23 142 258 Other 7 2 2 2 2 9 24 $ 156 $ 156 $ 153 $ 153 $ 150 $ 1,188 $ 1,956

Shareholders_ Equity (Tables)

Shareholders’ Equity (Tables)	12 Months Ended
	Dec. 31, 2020
Stockholders' Equity Note [Abstract]
Schedule of Common Shares Issued and Outstanding	Common Shares Issued and Outstanding Number of Amount January 1, 2019 275,224,066 $ 6,654 Shares issued for cash on exercise of options 76,177 1 Deferred taxes on share issuance cost — (4) Shares issued under DRIP 3,774,442 68 December 31, 2019 279,074,685 $ 6,719 Shares issued for cash on exercise of options 88,082 1 Deferred taxes on share issuance cost — (3) Shares issued under DRIP 331,532 6 Issued and outstanding at December 31, 2020 279,494,299 $ 6,723
Schedule of Preferred Shares Issued and Outstanding	As at December 31, 2020 December 31, 2019 Issued and Outstanding Number of shares Amount Number of shares Amount Series A 6,746,679 $ 169 5,511,220 $ 138 Series B 1,253,321 31 2,488,780 62 Series C 8,000,000 206 8,000,000 206 Series E 8,000,000 200 8,000,000 200 Series G 6,885,823 172 6,885,823 172 Series H 1,114,177 28 1,114,177 28 Series I — — 8,000,000 200 Series K 12,000,000 300 12,000,000 300 Share issuance costs, net of taxes (29) (29) 44,000,000 $ 1,077 52,000,000 $ 1,277
Summary of Cumulative Redeemable Preferred Shares	The following table outlines the characteristics of the cumulative redeemable preferred shares (a) : Current yield Annual dividend per share (b) Redemption price per share Redemption and conversion option date (c)(d) Right to convert into (d) Series A (e) 3.060 % $0.76500 $25 September 30, 2025 Series B Series B (f) (g) Floating Floating $25 September 30, 2025 Series A Series C (h) 5.290 % US$1.32250 US$25 September 30, 2022 Series D Series E (e) 5.393 % $1.34825 $25 December 31, 2023 Series F Series G (e) 4.240 % $1.06050 $25 September 30, 2024 Series H Series H (f) (g) Floating Floating $25 September 30, 2024 Series G Series K (i) 5.000 % $1.25000 $25 March 31, 2022 Series L (a) This table only includes those series of preferred shares that are currently issued and outstanding. The Corporation is authorized to issue up to 8,000,000 of each of Series D Shares, Series F Shares, and up to 12,000,000 of Series L Shares, subject to certain conditions, upon conversion by the holders of the applicable currently issued and outstanding series of preferred shares noted opposite such series in the table on the applicable conversion option date. If issued upon the conversion of the applicable series of preferred shares, Series F Shares, and Series L Shares are also redeemable for $25.50, and Series D Shares are redeemable for US$25.50 on any date after the applicable conversion option date, plus all accrued but unpaid dividends to, but excluding, the date fixed for redemption. (b) The holders of Series A Shares, Series C Shares, Series E Shares, Series G Shares, Series H Shares, and Series K Shares are entitled to receive a cumulative quarterly fixed dividend as and when declared by the Board of Directors. The holders of Series B Shares and Series H Shares are entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. If issued upon the conversion of the applicable series of Preferred Shares, the holders of Series D Shares, Series F Shares, and Series L Shares will be entitled to receive a quarterly floating dividend as and when declared by the Board of Directors. (c) AltaGas may, at its option, redeem all or a portion of the outstanding shares for the redemption price per share, plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. (d) The holder will have the right, subject to certain conditions, to convert their preferred shares of a specified series into Preferred Shares of that other specified series as noted in this column of the table on the applicable conversion option date and every fifth anniversary thereafter. (e) Holders of Series A Shares, Series E Shares, and Series G Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redemption and conversion option date and every fifth year thereafter, at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.66 percent (Series A Shares), 3.17 percent (Series E Shares), and 3.06 percent (Series G Shares). (f) Holders of Series B Shares and Series H Shares will be entitled to receive cumulative quarterly floating dividends, which will reset each quarter thereafter at a rate equal to the sum of the then 90-day government of Canada Treasury Bill rate plus 2.66 percent (Series B Shares) and 3.06 percent (Series H Shares). Each quarterly dividend is calculated as the annualized amount multiplied by the number of days in the quarter, divided by the number of days in the year. Commencing December 31, 2020, the floating quarterly dividend rate is $0.17069 per share for Series B Shares and $0.195349 per share for Series H Shares for the period starting December 31, 2020 to, but excluding, March 31, 2021. (g) Series B Shares can be redeemed for $25.50 per share on any date after September 30, 2015 that is not a Series B conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. Series H Shares can be redeemed for $25.50 per share on any date after September 30, 2019 that is not a Series H conversion date, plus all accrued and unpaid dividends to, but excluding, the date fixed for redemption. (h) Holders of Series C Shares will be entitled to receive cumulative quarterly fixed dividends, which will reset on the redeemable and conversion option date and every fifth year thereafter, at a rate equal to the sum of the five-year U.S. Government bond yield plus 3.58 percent.
Summary of Share Option Activity	The following table summarizes information about the Corporation’s share options: December 31, 2020 December 31, 2019 As at Options outstanding Options outstanding Number of Exercise price (a) Number of Exercise price (a) Share options outstanding, beginning of year 7,043,956 $ 22.49 6,309,183 $ 25.18 Granted 2,501,755 19.46 2,287,385 19.12 Exercised (88,082) 14.89 (76,177) 14.52 Forfeited (631,549) 26.00 (1,165,435) 27.31 Expired (463,869) 27.69 (311,000) 36.16 Share options outstanding, end of year 8,362,211 $ 21.06 7,043,956 $ 22.49 Share options exercisable, end of year 3,607,391 $ 23.59 2,921,642 $ 27.70 (a) Weighted average.
Summary of Employee Share Option Plan	The following table summarizes the employee share option plan as at December 31, 2020: Options outstanding Options exercisable Number outstanding Weighted average exercise price Weighted average remaining contractual life (years) Number exercisable Weighted average exercise price Weighted average remaining contractual life (years) $14.52 to $18.00 2,446,392 $ 15.24 4.07 1,359,457 $ 14.92 4.00 $18.01 to $25.08 3,930,345 19.56 4.80 528,252 19.54 4.47 $25.09 to $41.00 1,985,474 31.21 1.82 1,719,682 31.68 1.64 8,362,211 $ 21.06 3.88 3,607,391 $ 23.59 2.95
Summary of Fair Value of Options Granted	The fair value of each option granted is estimated on the date of grant using the Black-Scholes-Merton option pricing model. The weighted average grant date fair value and assumptions are as follows: Year ended December 31 2020 2019 Fair value per options ($) 2.61 2.30 Risk-free interest rate (%) 1.54 1.48 Expected life (years) 6 6 Expected volatility (%) 25.40 24.84 Annual dividend per share ($) (a) 0.96 0.96 Forfeiture rate (%) — — (a) Annual dividend per share is calculated based on a weighted average share price and forward dividend yields as the grant dates.
Schedule of MTIP and DSUP Activity	PUs, RUs, and DSUs (number of units) 2020 2019 Balance, beginning of year 6,484,831 9,908,154 Granted 1,158,547 674,971 Vested and paid out (681,841) (791,335) Forfeited (1,342,832) (3,377,962) Units in lieu of dividends 113,429 71,003 Outstanding, end of year 5,732,134 6,484,831

Net Income Per Common Share (Ta

Net Income Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2020
Earnings Per Share [Abstract]
Summary of Net Income per Common Share	The following table summarizes the computation of net income per common share: Year Ended December 31 2020 2019 Numerator: Net income applicable to controlling interests $ 552 $ 833 Less: Preferred share dividends (66) (68) Gain on redemption of preferred shares (note 25) — 4 Net income applicable to common shares $ 486 $ 769 Denominator: (millions of shares) Weighted average number of common shares outstanding 279.4 276.9 Dilutive equity instruments (a) 0.3 0.5 Weighted average number of common shares outstanding - diluted 279.7 277.4 Basic net income per common share $ 1.74 $ 2.78 Diluted net income per common share $ 1.74 $ 2.77 (a) Determined using the treasury stock method.

Other Income (Tables)

Other Income (Tables)	12 Months Ended
	Dec. 31, 2020
Other Income and Expenses [Abstract]
Schedule of Other Income	Year Ended December 31 2020 2019 Gains on asset sales (note 4) $ 223 $ 876 Gain on remeasurement of previously held interest in AIJVLP (note 3) 22 — Other components of net benefit cost (note 28) 52 27 Interest income and other revenue 9 9 Losses on investments — (4) Total $ 306 $ 908

Pension Plans and Retiree Ben_2

Pension Plans and Retiree Benefits (Tables)	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
Summary of Defined Benefit Plans	The following table summarizes the details of the defined benefit plans, including the SERP and post-retirement plans in Canada and the United States: Year Ended December 31, 2020 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Projected benefit obligation (a) Balance, beginning of year $ 36 $ 2 $ 1,725 $ 428 $ 1,761 $ 430 Actuarial loss 1 — 137 32 138 32 Current service cost 3 — 27 9 30 9 Member contributions — — — 2 — 2 Interest cost 1 — 60 15 61 15 Benefits paid (4) — (82) (24) (86) (24) Expenses paid — — (1) — (1) — Settlements — — (25) — (25) — Foreign exchange translation — — (41) (10) (41) (10) Balance, end of year $ 37 $ 2 $ 1,800 $ 452 $ 1,837 $ 454 Plan assets Fair value, beginning of year $ 15 $ — $ 1,504 $ 906 $ 1,519 $ 906 Actual return on plan assets 1 — 275 157 276 157 Employer contributions 4 — 37 — 41 — Member contributions — — — 2 — 2 Benefits paid (4) — (82) (24) (86) (24) Expenses paid — — (1) — (1) — Settlements — — (25) — (25) — Foreign exchange translation — — (41) (25) (41) (25) Fair value, end of year $ 16 $ — $ 1,667 $ 1,016 $ 1,683 $ 1,016 Funded status $ (21) $ (2) $ (133) $ 564 $ (154) $ 562 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation. Year Ended December 31, 2019 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Projected benefit obligation (a) Balance, beginning of year $ 34 $ 2 $ 1,635 $ 458 $ 1,669 $ 460 Actuarial loss (gain) 2 — 182 (15) 184 (15) Current service cost 3 — 24 9 27 9 Member contributions — — — 2 — 2 Interest cost 1 — 68 19 69 19 Benefits paid (4) — (77) (24) (81) (24) Expenses paid — — (1) — (1) — Settlements — — (24) — (24) — Other — — — 1 — 1 Foreign exchange translation — — (82) (22) (82) (22) Balance, end of year $ 36 $ 2 $ 1,725 $ 428 $ 1,761 $ 430 Plan assets Fair value, beginning of year $ 14 $ — $ 1,354 $ 791 $ 1,368 $ 791 Actual return on plan assets 1 — 284 177 285 177 Employer contributions 4 — 39 — 43 — Member contributions — — — 2 — 2 Benefits paid (4) — (77) (23) (81) (23) Expenses paid — — (1) — (1) — Settlements — — (25) — (25) — Foreign exchange translation — — (70) (41) (70) (41) Fair value, end of year $ 15 $ — $ 1,504 $ 906 $ 1,519 $ 906 Funded status $ (21) $ (2) $ (221) $ 478 $ (242) $ 476 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation.
Schedule of Amounts Included in the Consolidated Balance Sheets	The following amounts were included in the Consolidated Balance Sheets: December 31, 2020 December 31, 2019 Defined Benefit Post- Retirement Benefits Total Defined Benefit Post-Retirement Benefits Total (a) Prepaid post-retirement benefits $ — $ 572 $ 572 $ — $ 487 $ 487 Accounts payable and accrued liabilities (a) (9) — (9) (26) — (26) Future employee obligations (145) (10) (155) (216) (11) (227) $ (154) $ 562 $ 408 $ (242) $ 476 $ 234
Schedule of Funded Status Based on Accumulated Benefit Obligation	The accumulated benefit obligation for all defined benefit plans were: As at December 31, 2020 December 31, 2019 Canada United States Canada United States Accumulated benefit obligation (a) $ 36 $ 1,704 $ 35 $ 1,616 (a) Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels.
Defined Benefit Plan, Plan with Accumulated Benefit Obligation in Excess of Plan Assets	For those pension plans where the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were: As at December 31, 2020 December 31, 2019 Defined Benefit Post-Retirement Benefits Defined Post-Retirement Benefits Projected benefit obligation $ 1,824 $ 14 $ 1,757 $ 13 Plan assets $ 1,670 $ 3 $ 1,515 $ 3 For those pension plans where the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the cumulative obligation and asset balances were: As at December 31, 2020 December 31, 2019 Defined Benefit Post-Retirement Benefits Defined Post-Retirement Benefits Accumulated benefit obligation $ 427 $ 14 $ 1,648 $ 13 Plan assets $ 329 $ 3 $ 1,515 $ 3
Summary of Amounts Recorded in Other Comprehensive Income (Loss)	The following amounts were recorded in other comprehensive income (loss) and have not yet been recognized in net periodic benefit cost: Year Ended December 31, 2020 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Past service cost $ — $ — $ — $ (3) $ — $ (3) Net actuarial gain (loss) (9) (1) 6 (8) (3) (9) Recognized in AOCI pre-tax $ (9) $ (1) $ 6 $ (11) $ (3) $ (12) Increase (decrease) by the amount 2 — (2) 3 — 3 Net amount in AOCI after-tax $ (7) $ (1) $ 4 $ (8) $ (3) $ (9) Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Net actuarial gain (loss) $ (9) $ — $ (15) $ 18 $ (24) $ 18 Recognized in AOCI pre-tax $ (9) $ — $ (15) $ 18 $ (24) $ 18 Increase (decrease) by the amount 2 — 7 (9) 9 (9) Net amount in AOCI after-tax $ (7) $ — $ (8) $ 9 $ (15) $ 9
Summary of Amounts Recorded in A Regulatory Asset (Liability)	The following amounts were recorded in a regulatory asset (liability) and have not yet been recognized in net periodic benefit cost: Year Ended December 31, 2020 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit $ — $ — $ — $ (94) $ — $ (94) Net actuarial loss (gain) — — 68 (241) 68 (241) Recognized in regulatory asset (liability) $ — $ — $ 68 $ (335) $ 68 $ (335) Year Ended December 31, 2019 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service cost (credit) $ — $ — $ 1 $ (105) $ 1 $ (105) Net actuarial loss (gain) — — 127 (156) 127 (156) Recognized in regulatory asset (liability) $ — $ — $ 128 $ (261) $ 128 $ (261)
Schedule of Net Periodic Benefit Expense	The net pension expense by plan was as follows: Year Ended December 31, 2020 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 3 $ — $ 27 $ 9 $ 30 $ 9 Interest cost (b) 1 — 60 15 61 15 Expected return on plan assets (b) (c) (1) — (81) (40) (82) (40) Amortization of past service credit (b) — — — (19) — (19) Amortization of net actuarial loss (gain) (b) (c) 1 — 10 (5) 11 (5) Plan settlements (b) — — 7 — 7 — Net benefit cost (income) recognized $ 4 $ — $ 23 $ (40) $ 27 $ (40) (a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income. (b) Recorded under the line item “other income” on the Consolidated Statements of Income. (c) Includes the impact of the voluntary change in accounting principle implemented in 2020. Refer to Note 2 for additional information. Year Ended December 31, 2019 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 3 $ — $ 24 $ 9 $ 27 $ 9 Interest cost (b) 1 — 68 19 69 19 Expected return on plan assets (b) (1) — (75) (37) (76) (37) Amortization of past service credit (b) — — — (22) — (22) Amortization of net actuarial loss (b) 1 — 12 — 13 — Plan settlements (b) — — 4 — 4 — Other (b) — — — 1 — 1 Net benefit cost (income) recognized $ 4 $ — $ 33 $ (30) $ 37 $ (30) (a) Recorded under the line item “operating and administrative” expenses on the Consolidated Statements of Income. (b) Recorded under the line item “other income” on the Consolidated Statements of Income.
Schedule of Collective Investment Mixes for Plan Assets	The collective investment mixes for the plans are as follows as at December 31, 2020: Canada Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 2 $ 2 $ — 13 Canadian equities 3 3 — 19 Foreign equities 4 4 — 25 Fixed income 6 6 — 38 Real estate 1 — 1 5 $ 16 $ 15 $ 1 100 United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 14 $ 14 $ — 1 Canadian equities 1 1 — — Foreign equities (a) 357 357 — 13 Fixed income 1,002 129 873 37 Other (b) 23 — 23 1 Total investments in the fair value hierarchy $ 1,397 $ 501 $ 896 52 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 728 27 Private equity/limited partnership (e) 56 2 Pooled separate accounts (f) 32 1 Collective trust fund (g) 476 18 Total fair value of plan investments $ 2,689 100 Net payable (h) (6) — $ 2,683 100 (a) Investments in foreign equities include U.S. and international securities. (b) As at December 31, 2020, these investments consisted primarily of non-U.S. government bonds. (c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (d) As at December 31, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans. (e) As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies. (f) As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States. (g) As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments. (h) As at December 31, 2020, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable. Total Fair value Level 1 Level 2 Percentage of Plan Assets (%) Cash and short-term equivalents $ 16 $ 16 $ — 1 Canadian equities 4 4 — — Foreign equities (a) 361 361 — 13 Fixed income 1,008 135 873 37 Real estate 1 — 1 — Other (b) 23 — 23 1 Total investments in the fair value hierarchy $ 1,413 $ 516 $ 897 52 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 728 27 Private equity/limited partnership (e) 56 2 Pooled separate accounts (f) 32 1 Collective trust fund (g) 476 18 Total fair value of plan investments $ 2,705 100 Net payable (h) (6) — $ 2,699 100 (a) Investments in foreign equities include U.S. and international securities. (b) As at December 31, 2020, these investments consisted primarily of non-U.S. government bonds. (c) In accordance with ASC Topic 820, these investments are measured at fair value using net asset value (NAV) per share as a practical expedient and, therefore, have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliations of the fair value hierarchy to the statements of net assets available for plan benefits. (d) As at December 31, 2020, investments in commingled funds consisted of approximately 50 percent common stock of large-cap U.S. companies, 20 percent U.S. Government fixed income securities, and 30 percent corporate bonds for WGL’s post-retirement benefit plans. (e) As at December 31, 2020, investments in a private equity/limited partnership consisted of common stock of international companies. (f) As at December 31, 2020, investments in pooled separate accounts consisted of income producing properties located in the United States. (g) As at December 31, 2020, investments in collective trust funds consisted primarily of 90 percent common stock of U.S, companies, 7 percent income producing properties located in the United States, and 3 percent short-term money market investments. (h) As at December 31, 2020, this net payable primarily represents pending trades for investments purchased net of pending trades for investments sold and interest receivable.
Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations	Year Ended December 31 2020 2019 Significant actuarial assumptions used in measuring net benefit plan costs Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 2.30 - 3.50 3.10 - 3.60 2.90 - 4.40 3.90 - 4.50 Expected long-term rate of return on plan assets (%) (a) 5.25 - 7.05 4.03 - 7.05 5.75 - 7.15 4.66 - 7.15 Rate of compensation increase (%) 2.75 - 4.00 3.50 2.75 - 4.10 4.10 Average remaining service life of active employees (years) 10.2 13.0 9.0 13.2 (a) Only applicable for funded plans As at December 31 2020 2019 Significant actuarial assumptions used in measuring benefit obligations Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 1.90 - 2.80 2.50 - 2.90 2.90 - 3.50 3.10 - 3.60 Rate of compensation increase (%) 1.73 - 3.93 2.50 - 3.00 2.75 - 4.00 3.50
Schedule of Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Plans	The following table shows the expected cash flows for defined benefit pension and other post-retirement plans: Defined Post-Retirement Expected employer contributions: 2021 $ 16 $ — Expected benefit payments: 2021 $ 90 $ 25 2022 $ 91 $ 22 2023 $ 88 $ 22 2024 $ 89 $ 21 2025 $ 90 $ 21 2026 - 2030 $ 466 $ 110

Commitments, Guarantees, and _2

Commitments, Guarantees, and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Summary of Future Payment Commitments	Future payments of these commitments as at December 31, 2020 are estimated as follows: 2021 2022 2023 2024 2025 2026 & beyond Total Gas purchase (a) $ 1,974 $ 2,075 $ 1,858 $ 1,863 $ 1,901 $ 17,612 $ 27,283 LPG purchase (b) 407 199 161 108 83 258 1,216 Crude oil and condensate purchase (c) 184 — — — — — 184 Electricity purchase (d) 463 287 106 29 3 — 888 Service agreements (e) (f) (g) 48 32 26 27 27 282 442 Pipeline and storage services (h) 661 637 621 564 528 3,134 6,145 Capital projects (i) 20 1 1 1 1 1 25 Operating leases (j) 96 81 58 50 40 125 450 Environmental (k) 7 3 1 1 1 — 13 Merger commitments (l) 5 2 2 2 1 3 15 Land purchase commitment (m) 20 — — — — — 20 Post-acquisition contingent payments (n) — 16 — — — — 16 $ 3,885 $ 3,333 $ 2,834 $ 2,645 $ 2,585 $ 21,415 $ 36,697 (a) AltaGas enters into contracts to purchase natural gas from various suppliers for its utilities. These contracts are used to ensure that there is an adequate supply of natural gas to meet the needs of customers and to minimize exposure to market price fluctuations. Gas purchase commitments are valued based on fixed prices and forward prices, which may fluctuate significantly from period to period. (b) AltaGas enters into contracts to purchase LPGs for its operations at RIPET and Ferndale. These contracts are used to ensure that there is an adequate supply of LPGs to meet shipment commitments and to minimize exposure to market price fluctuations. LPG purchase commitments are valued based on forward prices, which may fluctuate significantly from period to period. (c) As part of the Petrogas Acquisition (Note 3), AltaGas acquired contracts to purchase crude oil and condensates for marketing, sale, and distribution. These contracts are used to ensure that there is an adequate supply of crude oil and condensates to meet the needs of customers and to minimize exposure to market price fluctuations. Crude oil and condensate commitments are valued based on forward prices, which may fluctuate significantly from period to period. (d) AltaGas enters into contracts to purchase electricity from various suppliers for its non-utility business. Electricity purchase commitments are based on existing fixed price and fixed volume contracts, and include US$21 million of commitments related to renewable energy credits. (e) In 2014, AltaGas' Blythe facility entered into a Long-Term Service Agreement (LTSA) with a service pro to complete various upgrade and maintenance services on the Combustion Turbines (CT) at the Blythe facility over 124,000 equivalent operating hours per CT, or 25 years, whichever comes first. The LTSA has variable fees on a per equivalent operating hour basis. As at December 31, 2020, the total commitment was $153 million payable over the next 15 years, of which $44 million is expected to be paid over the next 5 years. (f) In 2017, AltaGas entered into a 12-year service agreement commencing in 2019 for tug services to support the marine operations of RIPET. (g) In 2015, AltaGas entered into a Project Agreement that contemplated the sublease of lands from Ridley Terminals Inc. (RTI), provision of certain terminal services, and access to RTI's terminal facilities to support RIPET's operations for an initial term of 20 years ending in 2039. In 2019, RILE LP and RTI executed a Terminal Services Agreement that formalized the concepts outlined in the Project Agreement. (h) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044. (i) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs. (j) Operating leases include lease arrangements for office space, office equipment, field equipment, rail cars, aquatic use, vehicles, power and gas facilities, transmission and distribution assets, and land. (k) Environmental commitments include committed payments related to certain environmental response costs. (l) Represents the estimated future payments of WGL merger commitments that have been accrued but not paid. In addition, there are certain additional merger commitments that were and will be expensed as the costs are incurred, including the investment of up to US$70 million over a ten year period to further extend natural gas service, investment of US$8 million for leak mitigation within three years, which has been paid as of December 31, 2020, hiring damage prevention trainers in each jurisdiction for a total of US$2 million over five years, and developing 15 megawatts of either electric grid energy storage or Tier 1 renewable resources within five years after the merger closed. As at December 31, 2020, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$12 million. (m) As part of the Petrogas Acquisition (Note 3), AltaGas acquired a commitment to purchase land as part of an agreement for it's continued use of the Ferndale terminal. (n) Contingent payments of up to $16 million are expected to be paid related to the Petrogas Acquisition (Note 3).

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2020
Related Party Transactions [Abstract]
Summary of Related Party Amounts Included in Balance Sheets	Amounts due to or from related parties on the Consolidated Balance Sheets were measured at the exchange amount and were as follows: As at December 31, 2020 December 31, 2019 Due from related parties Accounts receivable (a) $ 5 $ 18 Long-term investments and other assets (b) — 45 $ 5 $ 63 Due to related parties Accounts payable (c) $ 3 $ 3 (a) Receivables from joint ventures and from a former affiliate of Petrogas. (b) For the period prior to December 15, 2020, AltaGas provided a $100 million interest bearing secured loan facility to Petrogas of which $50 million was committed. The facility was available for Petrogas to draw upon from time to time for general corporate purposes until the close of the Petrogas Acquisition on December 15, 2020. (c) Payables to a joint venture and a former affiliate of Petrogas.
Schedule of Related Party Transactions	The following transactions with related parties have been recorded on the Consolidated Statements of Income for the years ended December 31, 2020 and 2019: Year Ended December 31 2020 2019 Revenue (a) $ 92 $ 115 Cost of sales (b) $ 12 $ 13 Operating and administrative expenses (recoveries) (c) $ 1 $ (2) Other income (d) $ 3 $ 3 (a) In the ordinary course of business, AltaGas sold commodities to TriSummit Utilities Inc. and Petrogas. (b) In the ordinary course of business, AltaGas obtained natural gas storage services from a joint venture as well as incurred costs related to the sale of natural gas liquids to affiliates. (c) Subsequent to the close of the Petrogas Acquisition, certain operating and administrative expenses were paid on behalf of Petrogas by a former affiliate. In 2019, administrative cost recoveries included those from joint ventures and from TriSummit Utilities Inc. under a Transition Services Agreement. (d) Interest income from loans to Petrogas (secured loan facility) prior to the acquisition of Petrogas.

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2020
Supplemental Cash Flow Elements [Abstract]
Schedule of Changes in Operating Assets and Liabilities	The following table details the changes in operating assets and liabilities from operating activities: Year Ended 2020 2019 Source (use) of cash: Accounts receivable $ 21 $ 168 Inventory 32 (2) Other current assets 1 (85) Regulatory assets - current (33) 7 Accounts payable and accrued liabilities (41) (280) Customer deposits (2) (17) Regulatory liabilities - current (55) 34 Risk management liabilities - current (1) 1 Other current liabilities 4 (6) Other operating assets and liabilities (129) (52) Changes in operating assets and liabilities $ (203) $ (232)
Schedule of Supplemental Cash Payments	The following table details the changes in non-cash investing and financing activities: Year Ended 2020 2019 (Increase) of balance: Common shares issued under DRIP $ (6) $ (68) Net right-of-use assets obtained in exchange for new operating lease liabilities $ 227 $ 50 Net right-of-use assets obtained in exchange for new finance lease liabilities $ 6 $ 5 Capital expenditures included in accounts payable and accrued liabilities $ (33) $ (7) The following cash payments have been included in the determination of earnings: Year Ended 2020 2019 Interest paid (net of capitalized interest) $ 276 $ 352 Income taxes paid $ 23 $ 67
Reconciliation of Cash and Restricted Cash Balances	The following table is a reconciliation of cash and restricted cash balances: As at December 31 2020 2019 Cash and cash equivalents $ 32 $ 57 Restricted cash holdings from customers - current 3 4 Restricted cash holdings from customers - non-current 2 4 Restricted cash included in prepaid expenses and other current assets (a) 9 25 Restricted cash included in long-term investments and other assets (note 12) (a) 19 32 Restricted cash included in accounts receivable (note 29) 9 — Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows $ 74 $ 122 (a) The restricted cash balances included in prepaid expenses and other current assets and long-term investments and other assets relate to Rabbi trusts associated with WGL’s pension plans (see Note 28).

Segmented Information (Tables)

Segmented Information (Tables)	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Schedule of Description of Reporting Segments	The following describes the Corporation’s reporting segments: Utilities n rate-regulated natural gas distribution assets in Michigan, Alaska, the District of Columbia, Maryland, and Virginia; n rate-regulated natural gas storage in the United States; and n sale of natural gas to residential, commercial and industrial customers in Washington D.C., Maryland, Virginia, Delaware, Pennsylvania and Ohio. Midstream n NGL processing and extraction plants; n natural gas storage facilities; n liquefied petroleum gas (LPG) terminals; n transmission pipelines to transport natural gas and NGL; n natural gas gathering lines and field processing facilities; n purchase and sale of natural gas; n natural gas and NGL marketing; n marketing, storage and distribution of wellsite fluids and fuels, crude oil and condensate diluents; and n interest in a regulated pipeline in the Marcellus/Utica gas formation; Corporate/Other n the cost of providing corporate services, financing and general corporate overhead, investments in certain public and private entities, corporate assets, financing other segments and the effects of changes in the fair value of certain risk management contracts; and n a small portfolio of remaining power assets, certain of which are pending sale.
Reconciliation Of Segment Revenue	The following table provides a reconciliation of segment revenue to the disaggregated revenue table disclosed in Note 24: Year Ended December 31, 2020 Utilities Midstream Corporate/Other Total External revenue (note 24) $ 3,817 $ 1,635 $ 135 $ 5,587 Intersegment revenue — 1 — 1 Segment revenue $ 3,817 $ 1,636 $ 135 $ 5,588 Year Ended December 31, 2019 Utilities Midstream Corporate/Other Total External revenue (note 24) $ 4,044 $ 1,228 $ 223 $ 5,495 Intersegment revenue — 32 — 32 Segment revenue $ 4,044 $ 1,260 $ 223 $ 5,527
Schedule of Geographic Information	Geographic Information Year Ended December 31 2020 2019 Revenue (a) Canada $ 1,512 $ 1,245 United States 4,053 4,325 TOTAL $ 5,565 $ 5,570 (a) Operating revenue from external customers, excluding unrealized gains or losses on risk management contracts. As at December 31 2020 2019 Property, plant and equipment Canada $ 3,149 $ 2,682 United States 7,739 7,443 TOTAL $ 10,888 $ 10,125 Operating right-of-use assets Canada $ 293 $ 85 United States 79 85 TOTAL $ 372 $ 170
Schedule of Segment Composition	The following tables show the composition by segment: Year Ended December 31, 2020 Utilities Midstream Corporate/Other Intersegment Elimination (a) Total Segment revenue (note 24) $ 3,817 $ 1,636 $ 135 $ (1) $ 5,587 Cost of sales (2,156) (994) (29) 1 (3,178) Operating and administrative (942) (254) (71) — (1,267) Accretion expenses — (4) (1) — (5) Depreciation and amortization (295) (86) (33) — (414) Provisions on assets (note 6) (1) (105) (3) — (109) Income from equity investments 5 44 — — 49 Other income 259 24 23 — 306 Foreign exchange gains (losses) — (26) 30 — 4 Interest expense — — (274) — (274) Income (loss) before income taxes $ 687 $ 235 $ (223) $ — $ 699 Net additions (reductions) to: Property, plant and equipment (b) $ 740 $ 136 $ (51) $ — $ 825 Intangible assets $ 3 $ 3 $ 4 $ — $ 10 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets. Year Ended December 31, 2019 Utilities Midstream Corporate/Other Intersegment Elimination (a) Total Segment revenue (note 24) $ 4,044 $ 1,260 $ 223 $ (32) $ 5,495 Cost of sales (2,448) (760) (51) 32 (3,227) Operating and administrative (960) (213) (126) — (1,299) Accretion expenses — (4) (1) — (5) Depreciation and amortization (276) (89) (73) — (438) Provision on assets (note 6) — (34) (382) — (416) Income from equity investments 19 122 — — 141 Other income 29 28 851 — 908 Foreign exchange gains (losses) — (5) 4 — (1) Interest expense — — (346) — (346) Income before income taxes $ 408 $ 305 $ 99 $ — $ 812 Net additions (reductions) to: Property, plant and equipment (b) $ 840 $ 351 $ (2,280) $ — $ (1,089) Intangible assets $ 23 $ 5 $ 9 $ — $ 37 (a) Intersegment transactions are recorded at market value. (b) Net additions to property, plant, and equipment, and intangible assets may not agree to changes reflected in the Consolidated Statements of Cash Flows due to classification of business acquisition and foreign exchange changes on U.S. assets.
Schedule of Goodwill and Total Assets by Segment	The following table shows goodwill and total assets by segment: Utilities Midstream Corporate/Other Total As at December 31, 2020 Goodwill $ 3,706 $ 1,333 $ — $ 5,039 Segmented assets $ 13,675 $ 7,320 $ 537 $ 21,532 As at December 31, 2019 Goodwill $ 3,781 $ 161 $ — $ 3,942 Segmented assets $ 13,719 $ 5,265 $ 811 $ 19,795

Organization and Overview of _2

Organization and Overview of the Business (Details) customer in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2020USD ($)customersegment
Organization And Overview Of Business [Line Items]
Number of segments | segment	2
Utilities
Organization And Overview Of Business [Line Items]
Number of customers	1.7
Utilities customers, base rate | $	$ 4.3
Utilities | Storage services
Organization And Overview Of Business [Line Items]
Number of customers	0.5
Midstream | Ridley Island Propane Terminal
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	70.00%
Midstream | Ferndale Terminal
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	74.00%
Midstream | Petrogas Preferred Shares
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	74.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Summary of Estimated Useful Lives of Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2020
Minimum | Corporate
Property, Plant and Equipment
Useful life	3 years
Minimum | Utilities
Property, Plant and Equipment
Useful life	4 years
Minimum | Midstream
Property, Plant and Equipment
Useful life	3 years
Maximum | Corporate
Property, Plant and Equipment
Useful life	46 years
Maximum | Utilities
Property, Plant and Equipment
Useful life	69 years
Maximum | Midstream
Property, Plant and Equipment
Useful life	55 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Summary of Estimated Useful Lives of Finite-Lived Intangible Assets (Details)	12 Months Ended
	Dec. 31, 2020
Energy services relationships
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Software | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	3 years
Software | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	20 years
Land rights | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Land rights | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	43 years
E&T contracts
Finite-Lived Intangible Assets
Intangible asset, useful life	25 years
Commodity contracts | Minimum
Finite-Lived Intangible Assets
Intangible asset, useful life	5 years
Commodity contracts | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	20 years

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Share Options and Other Compensation Plans (Details)	12 Months Ended
	Dec. 31, 2020multiple$ / shares
Share-based Compensation Arrangement by Share-based Payment Award
Other portions of RU's and PSU's (per share) | $ / shares	$ 1
Performance units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Performance multiplier	0
Performance units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Performance multiplier	2.4

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Pension Plan and Post Retirement Benefits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2020$ / shares	Dec. 31, 2019CAD ($)
Defined Benefit Plan Disclosure
Income before income taxes - consolidated	$ 699		$ 812
Net income applicable to common shares	486		769
Deferred income tax expense (recovery) (note 20)	126		$ (91)
Revision of Prior Period, Change in Accounting Principle, Adjustment
Defined Benefit Plan Disclosure
Income before income taxes - consolidated	25
Net income applicable to common shares	19
Earnings per share basic and diluted (in dollars per share) | $ / shares		$ 0.07
Deferred income tax expense (recovery) (note 20)	$ 6
Defined Benefit
Defined Benefit Plan Disclosure
Average remaining service life of active employees	10 years 2 months 12 days		9 years
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Average remaining service life of active employees	13 years		13 years 2 months 12 days

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Collaborative Agreements (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Income (loss) from collaborative agreements	$ 21	$ 1

Summary of Significant Accoun_9

Summary of Significant Accounting Policies - Effects of Adoption of New Accounting Principles (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Jan. 01, 2020	Dec. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle\
Long-term investments and other assets (net of credit losses of $3 million) (notes 12, 28, and 31)	$ (245)		$ (297)
ASU 2016-13 | Cumulative Effect, Period of Adoption, Adjustment
New Accounting Pronouncements or Change in Accounting Principle\
Accounts receivable, net		$ 2
Long-term investments and other assets (net of credit losses of $3 million) (notes 12, 28, and 31)		$ 5

Acquisition of Petrogas Energ_3

Acquisition of Petrogas Energy Corporation - Narrative (Details) - CAD ($) $ in Millions	Dec. 15, 2020	Dec. 30, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition
Gain on re-measurement of previously held interest			$ 22	$ 0
Goodwill			5,039	3,942	$ 4,068
Petrogas Energy Corporation
Business Acquisition
Additional ownership interest acquired (as a percent)	37.00%
Purchase consideration for an additional 37 percent of Petrogas	$ 715
Consulting fees	$ 16
Total ownership interest in acquiree (as a percent)	74.00%
Previous ownership percentage	37.00%
Acquisition date fair value	$ 631
Gain on re-measurement of previously held interest	22
Fair value of AIJVLP's non-controlling interest in Petrogas on the acquisition date	467
Inventory acquired			164
Goodwill	$ 1,171
Pre-tax acquisition expenses			(6)
Revenues since acquisition		$ 143
Net income after taxes since acquisition		$ 3
Petrogas Energy Corporation | Petrogas Terminals Penn LLC
Business Acquisition
Noncontrolling ownership interest (percent)	50.00%
Petrogas Energy Corporation | Strathcona Storage LP
Business Acquisition
Noncontrolling ownership interest (percent)	40.00%
Petrogas Energy Corporation | Acquisition-related Costs
Business Acquisition
Total after-tax pro forma adjustments, decrease to net income			$ (31)	$ (75)

Acquisition of Petrogas Energ_4

Acquisition of Petrogas Energy Corporation - Schedule of Final Purchase Price Allocation (Details) - CAD ($) $ in Millions	Dec. 15, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition
Gain on re-measurement of previously held interest		$ 22	$ 0
Less: Fair value assigned to net assets
Goodwill		$ 5,039	$ 3,942	$ 4,068
Petrogas Energy Corporation
Business Acquisition
Acquisition date fair value	$ 631
Less: Carrying value of previously held interest in AIJVLP	(609)
Gain on re-measurement of previously held interest	22
Purchase consideration for an additional 37 percent of Petrogas	715
Deemed settlement of intercompany debt	120
Less: Fair value assigned to net assets
Current assets	536
Property, plant and equipment	523
Intangible assets	10
Operating right-of-use assets	192
Long-term investments and other assets	4
Investments accounted for by the equity method	125
Current liabilities	(363)
Long-term debt	(53)
Asset retirement obligations	(13)
Deferred income taxes	(21)
Operating lease liabilities	(152)
Other long-term liabilities	(26)
Fair value of net assets acquired	762
Fair value of AIJVLP's non-controlling interest in Petrogas on the acquisition date	467
Goodwill	$ 1,171
Previous ownership percentage	37.00%

Acquisition of Petrogas Energ_5

Acquisition of Petrogas Energy Corporation - Pro Forma Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Business Combinations [Abstract]
Pro forma revenue	$ 7,917	$ 9,217
Pro forma net income (loss) after taxes	$ 537	$ 1,004

Dispositions (Details)

Dispositions (Details) shares in Thousands, $ in Millions	Mar. 31, 2020CAD ($)	Sep. 30, 2020CAD ($)	Jun. 30, 2020CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Mar. 31, 2020$ / sharesshares
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Gain (loss) on disposition of assets				$ 223	$ 876
Provisions on assets (note 6)				109	416
Proceeds from sale of land parcels			$ 3
Corporate/Other
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Provisions on assets (note 6)					$ 382
Distributed Generation Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Gain (loss) on disposition of assets				9
Distributed Generation Assets | Corporate/Other
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Provisions on assets (note 6)				3
Disposal by sale | Altagas Canada Inc.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Share price of interests disposed of (in dollars per share) | $ / shares						$ 33.50
Shares disposed of (in shares) | shares						11,025
Ownership percentage (percent)						37.00%
Proceeds from disposition of business	$ 369
Gain (loss) on disposal of business				$ 206
Disposal by sale | Pomona Energy Storage Facility and Ripon Gas-fired Facility
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition of business		$ 67
Gain (loss) on disposal of business		$ 8

Assets Held For Sale - Schedule

Assets Held For Sale - Schedule of Assets Held for Sale (Details) - Held for sale $ in Millions, $ in Millions	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)
Assets held for sale
Property, plant and equipment	$ 4		$ 22
Operating right-of-use assets	0		1
Goodwill	0		1
Other long-term assets	0		3
Total assets held for sale	4		27
Liabilities associated with assets held for sale
Unamortized investment tax credits	1		3
Operating lease liabilities - long-term	0		1
Total liabilities associated with assets held for sale	1		$ 4
US Portfolio
Liabilities associated with assets held for sale
Total liabilities associated with assets held for sale	$ 4	$ 3

Provisions on Assets - Schedule

Provisions on Assets - Schedule of Provisions on Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Provisions On Assets Disclosure
Provisions on assets	$ 109	$ 416
Midstream
Provisions On Assets Disclosure
Provisions on assets	$ 106	34
Corporate/Other
Provisions On Assets Disclosure
Provisions on assets		$ 382

Provisions on Assets - Narrativ

Provisions on Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Provisions On Assets Disclosure
Provisions on assets	$ 109	$ 416
Midstream
Provisions On Assets Disclosure
Provisions on assets	106	34
Midstream | Natural Gas Storage Project
Provisions On Assets Disclosure
Provisions on assets	104
Midstream | Land [Member]
Provisions On Assets Disclosure
Provisions on assets	$ 2
Corporate/Other
Provisions On Assets Disclosure
Provisions on assets		$ 382

Inventory (Details)

Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Inventory
Natural gas held in storage	$ 309	$ 359
Natural gas liquids	116	26
Materials and supplies	84	57
Renewable energy credits and emission compliance instruments	80	64
Crude oil and condensate	43	0
Processed finished products	4	0
Total inventory	636	506
Rate Regulated Utilities
Inventory
Natural gas held in storage	$ 193	$ 214

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment
Cost	$ 12,723	$ 11,499
Accumulated amortization	1,835	1,374
Net book value	10,888	10,125
Held for sale
Property, Plant and Equipment
Cost	4	24
Accumulated amortization	0	2
Net book value	4	22
Utilities
Property, Plant and Equipment
Cost	7,791	7,316
Accumulated amortization	286	155
Net book value	7,505	7,161
Midstream
Property, Plant and Equipment
Cost	4,094	3,182
Accumulated amortization	951	585
Net book value	3,143	2,597
Corporate/Other
Property, Plant and Equipment
Cost	842	1,025
Accumulated amortization	598	636
Net book value	$ 244	$ 389

Property, Plant and Equipment_2

Property, Plant and Equipment - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Interest capitalized	$ 6	$ 15
Capital projects under construction	457	725
Depreciation expense	$ 346	$ 358

Intangible Assets - Summary of

Intangible Assets - Summary of Intangible Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Finite-Lived Intangible Assets
Cost	$ 753	$ 759
Accumulated amortization	(214)	(173)
Net book value	539	586
E&T contracts
Finite-Lived Intangible Assets
Cost	26	27
Accumulated amortization	(16)	(15)
Net book value	10	12
Electricity service agreements
Finite-Lived Intangible Assets
Cost	0	9
Accumulated amortization	0	(8)
Net book value	0	1
Energy services relationships
Finite-Lived Intangible Assets
Cost	90	91
Accumulated amortization	(45)	(27)
Net book value	45	64
Software
Finite-Lived Intangible Assets
Cost	304	304
Accumulated amortization	(133)	(102)
Net book value	171	202
Land rights
Finite-Lived Intangible Assets
Cost	1	1
Accumulated amortization	0	0
Net book value	1	1
Commodity contracts
Finite-Lived Intangible Assets
Cost	332	327
Accumulated amortization	(20)	(21)
Net book value	$ 312	$ 306

Intangible Assets - Narratives

Intangible Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense	$ 68	$ 80
Assets excluded from asset base subject to amortization	$ 176	$ 185

Intangible Assets - Summary o_2

Intangible Assets - Summary of Estimated Amortization Expense of Intangible Assets (Details) $ in Millions	Dec. 31, 2020CAD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2021	$ 75
2022	72
2023	60
2024	39
2025	15
Thereafter	$ 102

Leases - Components of Lease Co

Leases - Components of Lease Cost (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lease, Cost
Operating lease cost (includes variable lease payments)	$ 43	$ 29
Amortization of right-of-use assets	4	4
Total finance lease cost	4	4
Total lease cost	$ 47	$ 33

Leases - Supplemental Cashflow

Leases - Supplemental Cashflow Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ (36)	$ (21)
Financing cash flows from finance leases	(4)	(4)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	227	50
Finance leases	$ 6	$ 5

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet Location (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Operating lease right-of-use assets
Long-term	$ 372	$ 170
Total operating lease right-of-use assets	372	170
Operating lease liabilities
Current	(95)	(27)
Long-term	(304)	(153)
Total operating lease liabilities	(399)	(180)
Finance Leases
Property and equipment, gross	19	13
Accumulated depreciation	(7)	(3)
Property and equipment, net	12	10
Current portion of long-term debt	(4)	(4)
Long-term debt	(8)	(6)
Total finance lease liabilities	$ (12)	$ (10)
Weighted average remaining lease term (years)
Operating leases	7 years 4 months 24 days	10 years 10 months 24 days
Finance leases	4 years 9 months 18 days	5 years 2 months 12 days
Weighted average discount rate (%)
Operating leases	2.42%	3.51%
Finance leases (percent)	2.89%	3.68%

Leases - Schedule of Future Lea

Leases - Schedule of Future Lease Liability for Operating and Finance Lease (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Operating Leases
2021	$ 96
2022	81
2023	58
2024	50
2025	40
Thereafter	125
Total lease payments	450
Less: imputed interest	(51)
Total	399	$ 180
Finance Leases
2021	4
2022	4
2023	2
2024	1
2025	1
Thereafter	2
Total lease payments	14
Less: imputed interest	(2)
Total	$ 12	$ 10

Leases - Narrative (Details)

Leases - Narrative (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Operating Leased Assets
Property, plant and equipment	$ 10,888	$ 10,125
Assets leased to others
Operating Leased Assets
Property, plant and equipment	$ 500

Leases - Schedule of Operating

Leases - Schedule of Operating Lease Receivables (Details) $ in Millions	Dec. 31, 2020CAD ($)
Operating Leases
2021	$ 127
2022	117
2023	108
2024	41
2025	41
Thereafter	404
Total	$ 838

Goodwill (Details)

Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Goodwill
Balance, beginning of year	$ 3,942	$ 4,068
Business acquisition (note 3)	1,171	0
Adjustment to goodwill on business acquisition	0	92
Goodwill included in dispositions	0	(29)
Reclassified to assets held for sale	0	(1)
Foreign exchange translation	(74)	(188)
Balance, end of year	$ 5,039	$ 3,942

Long-Term Investments and Oth_3

Long-Term Investments and Other Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Investments, All Other Investments [Abstract]
Investments in publicly-traded entities	$ 0	$ 4
Loan to affiliate (notes 23 and 30)	0	45
Deferred lease receivable	12	17
Debt issuance costs associated with credit facilities	3	6
Refundable deposits	9	9
Prepayment on long-term service agreements	70	81
Deferred information technology costs	4	0
Cash calls from joint venture partners	26	10
Contract asset (net of credit losses of $1 million) (notes 23 and 24)	50	30
Rabbi trust and other restricted cash (notes 28, 29 and 31)	19	32
Other long-term receivables (net of credit losses of $2 million) (notes 23 and 29)	18	33
Capitalized contract costs	5	0
Financial transmission rights	12	12
Other	17	18
Long-term investments and other assets	245	297
Contract assets, allowance for credit loss	1	1
Other long-term receivables, allowance for credit loss	$ 2	$ 2

Variable Interest Entities - Na

Variable Interest Entities - Narratives (Details) - CAD ($) $ in Millions	May 05, 2017	Dec. 31, 2020	Dec. 31, 2019
Variable Interest Entity
Investments accounted for by the equity method (note 14)		$ 887	$ 1,462
Strathcona Storage LP | CANADA
Variable Interest Entity
Equity method investment, ownership interest (percent)		30.00%
Investments accounted for by the equity method (note 14)		$ 124	$ 0
Altagas LPG | RILE LP
Variable Interest Entity
VIE ownership percentage	70.00%
Vopak | RILE LP
Variable Interest Entity
VIE ownership percentage	30.00%

Variable Interest Entities - Sc

Variable Interest Entities - Schedule of VIE Amounts in Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Variable Interest Entity
Current assets	$ 2,497	$ 2,196
Property, plant and equipment	10,888	10,125
Long-term investments and other assets	245	297
Current liabilities	(2,607)	(3,125)
Asset retirement obligations	(385)	(368)
VIE
Variable Interest Entity
Current assets	7	6
Property, plant and equipment	358	371
Long-term investments and other assets	50	53
Current liabilities	(2)	(3)
Asset retirement obligations	(2)	(3)
Net assets	$ 411	$ 424

Investments Accounted for by _3

Investments Accounted for by the Equity Method - Schedule of Equity Method Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments
Equity method investment	$ 887	$ 1,462
Income from equity investments	49	141
CANADA | Altagas Canada Inc.
Schedule of Equity Method Investments
Equity method investment	0	164
Income from equity investments	3	17
CANADA | AltaGas Idemitsu Joint Venture LP
Schedule of Equity Method Investments
Equity method investment	0	431
Income from equity investments	$ (25)	63
CANADA | Sarnia Airport Storage Pool LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 18	18
Income from equity investments	1	1
CANADA | Petrogas Preferred Shares
Schedule of Equity Method Investments
Equity method investment	0	150
Income from equity investments	$ 13	13
CANADA | Strathcona Storage LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	30.00%
Equity method investment	$ 124	0
Income from equity investments	0	0
United States | Constitution Pipeline, LLC (Constitution)
Schedule of Equity Method Investments
Equity method investment	0	0
Income from equity investments	$ (7)	0
United States | Eaton Rapids Gas Storage System
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50.00%
Equity method investment	$ 26	27
Income from equity investments	2	1
United States | Meade Pipeline Co. LLC (Meade)
Schedule of Equity Method Investments
Equity method investment	0	0
Income from equity investments	$ 0	(4)
United States | Mountain Valley Pipeline, LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	10.00%
Equity method investment	$ 718	672
Income from equity investments	$ 62	43
United States | Petrogas Terminals Penn LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	37.00%
Equity method investment	$ 1	0
Income from equity investments	0	0
United States | Stonewall Gas Gathering System LLC
Schedule of Equity Method Investments
Equity method investment	0	0
Income from equity investments	$ 0	$ 7

Investments Accounted for by _4

Investments Accounted for by the Equity Method - Schedule of Combined Financial Information of Equity Method Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Equity Method Investments
Revenues	$ 5,587	$ 5,495
Cost of sales	(3,178)	(3,227)
Current assets	2,497	2,196
Property, plant and equipment	10,888	10,125
Intangible assets	539	586
Long-term investments and other assets	245	297
Current liabilities	(2,607)	(3,125)
Other long-term liabilities	(153)	(102)
Equity Method Investment, Nonconsolidated Investee or Group of Investees
Schedule of Equity Method Investments
Revenues	828	1,109
Cost of sales	(181)	(355)
Gross profit	647	754
Current assets	351	411
Property, plant and equipment	7,598	8,034
Intangible assets	0	22
Long-term investments and other assets	5	1,459
Current liabilities	(281)	(394)
Other long-term liabilities	$ (2)	$ (992)

Investments Accounted for by _5

Investments Accounted for by the Equity Method - Narratives (Details) $ in Millions	Dec. 15, 2020CAD ($)	Mar. 31, 2020CAD ($)	Dec. 31, 2020CAD ($)	Mar. 31, 2020$ / sharesshares	Dec. 31, 2019CAD ($)
Disposal by sale | Altagas Canada Inc.
Schedule of Equity Method Investments
Gain (loss) on disposal of business			$ 206
Petrogas Terminals Penn LLC | Petrogas Energy Corporation
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)			50.00%
Strathcona Storage LP | Petrogas Energy Corporation
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)			40.00%
AltaGas Canada Inc. | Public Sector Pension Investment Board and Alberta Teachers' Retirement Fund Board
Schedule of Equity Method Investments
Equity method investment, acquired (in dollars per share) | $ / shares				$ 33.50
AltaGas Canada Inc. | AltaGas
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)				37.00%
Equity method investment, shares owned prior to sale | shares				11,025,000
Proceeds from sale of equity method investments		$ 369
Constitution Pipeline
Schedule of Equity Method Investments
Provision on equity method investments			$ (7)
Meade Pipeline Co LLC
Schedule of Equity Method Investments
Provision on equity method investments					$ (44)
Craven County Wood Energy LP
Schedule of Equity Method Investments
Provision on equity method investments					$ 2
Petrogas Energy Corporation
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)				29.20%	33.30%
Pre-tax dilution losses			30
Additional expenses			$ 12
AIJVLP
Schedule of Equity Method Investments
Equity method investment, pre-tax gain on re-measurement of investment	$ (22)

Short-term Debt - Schedule of S

Short-term Debt - Schedule of Short-Term Debt (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Commercial paper	$ 236	$ 389
Project financing	20	71
Short-term debt	$ 256	$ 460

Short-term Debt - Narrative (De

Short-term Debt - Narrative (Details)	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)
Short-term Debt
Project financing	$ 20,000,000		$ 71,000,000
Commercial paper	236,000,000		389,000,000
Unsecured Extendible Revolving Facility | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity	150,000,000		150,000,000
Amount outstanding	$ 0		26,000,000
Debt instrument term (years)	4 years
Credit facility cancelled	$ 300,000,000
Unsecured Bilateral Demand Facility | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity		$ 200,000,000		$ 200,000,000
Amount outstanding	190,000,000		156,000,000
Unsecured Extendible Revolving Facility II | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity		1,200,000,000		$ 1,200,000,000
Revolving Letter of Credit Facility
Short-term Debt
Credit facility maximum borrowing capacity	30,000,000
Letters of credit outstanding	22,000,000
Operating Facility
Short-term Debt
Credit facility maximum borrowing capacity		15,000,000
Letters of credit outstanding		0
Seasonal Budget Facility
Short-term Debt
Credit facility maximum borrowing capacity		$ 40,000,000
Amount outstanding	0
Parent Company | Unsecured Demand Revolving Operating Credit Facility
Short-term Debt
Credit facility maximum borrowing capacity	70,000,000		70,000,000
Amount outstanding	$ 0		$ 0

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-Term Debt (Details)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 10, 2020CAD ($)	Dec. 31, 2019CAD ($)
Debt Instrument
Fair value adjustment on WGL Acquisition (note 3)	$ 80,000,000			$ 84,000,000
Finance lease liabilities (note 10)	12,000,000			10,000,000
Long-term debt including lease obligations	8,029,000,000			6,887,000,000
Less debt issuance costs	(43,000,000)			(36,000,000)
Total long-term debt	7,986,000,000			6,851,000,000
Less current portion	(360,000,000)			(923,000,000)
Long-term debt, noncurrent	7,626,000,000			5,928,000,000
WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross			$ 100,000,000	300,000,000
Premium from debt issued			$ 17,000,000
$200 million Senior unsecured - 4.07 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	0			200,000,000
Debt face amount	$ 200,000,000
Debt instrument rate (as a percent)	4.07%	4.07%
$350 million Senior unsecured - 3.72 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 350,000,000			350,000,000
Debt face amount	$ 350,000,000
Debt instrument rate (as a percent)	3.72%	3.72%
$500 million Senior unsecured - 2.61 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 500,000,000			500,000,000
Debt face amount	$ 500,000,000
Debt instrument rate (as a percent)	2.61%	2.61%
$300 million Senior unsecured - 3.57 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 300,000,000			300,000,000
Debt face amount	$ 300,000,000
Debt instrument rate (as a percent)	3.57%	3.57%
$200 million Senior unsecured - 4.40 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 200,000,000			200,000,000
Debt face amount	$ 200,000,000
Debt instrument rate (as a percent)	4.40%	4.40%
$300 million Senior unsecured - 3.84 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 300,000,000			300,000,000
Debt face amount	$ 300,000,000
Debt instrument rate (as a percent)	3.84%	3.84%
$500 million Senior unsecured - 2.16 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 500,000,000			0
Debt face amount	$ 500,000,000
Debt instrument rate (as a percent)	2.16%	2.16%
$350 million Senior unsecured - 4.12 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 350,000,000			350,000,000
Debt face amount	$ 350,000,000
Debt instrument rate (as a percent)	4.12%	4.12%
$200 million Senior unsecured - 3.98 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 200,000,000			200,000,000
Debt face amount	$ 200,000,000
Debt instrument rate (as a percent)	3.98%	3.98%
$500 million Senior unsecured - 2.08 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 500,000,000			0
Debt face amount	$ 500,000,000
Debt instrument rate (as a percent)	2.08%	2.08%
$200 million Senior unsecured - 2.48 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 200,000,000			0
Debt face amount	$ 200,000,000
Debt instrument rate (as a percent)	2.48%	2.48%
$100 million Senior unsecured - 5.16 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 100,000,000			100,000,000
Debt face amount	$ 100,000,000
Debt instrument rate (as a percent)	5.16%	5.16%
$300 million Senior unsecured - 4.50 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 300,000,000			300,000,000
Debt face amount	$ 300,000,000
Debt instrument rate (as a percent)	4.50%	4.50%
$250 million Senior unsecured - 4.99 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 250,000,000			250,000,000
Debt face amount	$ 250,000,000
Debt instrument rate (as a percent)	4.99%	4.99%
US$250 million Senior unsecured - 2.44 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 250,000,000
Debt instrument rate (as a percent)	2.44%	2.44%
US$250 million Senior unsecured - 2.44 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 0			325,000,000
US$20 million Senior unsecured - 6.65 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 20,000,000
Debt instrument rate (as a percent)	6.65%	6.65%
US$20 million Senior unsecured - 6.65 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 25,000,000			26,000,000
US$41 million Senior unsecured - 5.44 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 41,000,000
Debt instrument rate (as a percent)	5.44%	5.44%
US$41 million Senior unsecured - 5.44 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 52,000,000			53,000,000
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 53,000,000
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	6.62%	6.62%
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	6.82%	6.82%
US$53 million Senior unsecured - 6.62 to 6.82 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 67,000,000			69,000,000
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 72,000,000
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	6.40%	6.40%
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	6.57%	6.57%
US$72 million Senior unsecured - 6.40 to 6.57 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 92,000,000			93,000,000
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 52,000,000
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	6.57%	6.57%
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	6.85%	6.85%
US$52 million Senior unsecured - 6.57 to 6.85 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 66,000,000			67,000,000
US$9 million Senior unsecured - 7.50 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 9,000,000
Debt instrument rate (as a percent)	7.50%	7.50%
US$9 million Senior unsecured - 7.50 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 11,000,000			11,000,000
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 50,000,000
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	5.70%	5.70%
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	5.78%	5.78%
US$50 million Senior unsecured - 5.70 to 5.78 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 64,000,000			65,000,000
US$75 million Senior unsecured - 5.21 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 75,000,000
Debt instrument rate (as a percent)	5.21%	5.21%
US$75 million Senior unsecured - 5.21 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 95,000,000			97,000,000
US$75 million Senior unsecured - 5.00 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 75,000,000
Debt instrument rate (as a percent)	5.00%	5.00%
US$75 million Senior unsecured - 5.00 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 95,000,000			97,000,000
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 300,000,000
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | Minimum
Debt Instrument
Debt instrument rate (as a percent)	4.22%	4.22%
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | Maximum
Debt Instrument
Debt instrument rate (as a percent)	4.60%	4.60%
US$300 million Senior unsecured - 4.22 to 4.60 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 382,000,000			390,000,000
US$450 million Senior unsecured - 3.80 percent | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 450,000,000
Debt instrument rate (as a percent)	3.80%	3.80%
US$450 million Senior unsecured - 3.80 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 573,000,000			584,000,000
US$400 million Senior unsecured - 3.65 percent (d) | WGL And Washington Gas
Debt Instrument
Debt face amount		$ 400,000,000
Debt instrument rate (as a percent)	3.65%	3.65%
US$400 million Senior unsecured - 3.65 percent (d) | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 530,000,000			390,000,000
US$300 million SEMCO Senior Secured - 5.15 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross	$ 0			390,000,000
Debt face amount		$ 300,000,000
Debt instrument rate (as a percent)	5.15%	5.15%
US$82 million SEMCO Senior Secured - 4.48 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross	$ 69,000,000			76,000,000
Debt face amount		$ 82,000,000
Debt instrument rate (as a percent)	4.48%	4.48%
US$225 million First Mortgage Bonds - 3.15 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross	$ 286,000,000			0
Debt face amount		$ 225,000,000
Debt instrument rate (as a percent)	3.15%	3.15%
US$225 million First Mortgage Bonds - 2.45 percent | SEMCO long-term debt
Debt Instrument
Long-term debt, gross	$ 286,000,000			0
Debt face amount		$ 225,000,000
Debt instrument rate (as a percent)	2.45%	2.45%
Credit facilities | $1,400 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross	$ 802,000,000			90,000,000
Debt face amount	1,400,000,000
Credit facilities | US$300 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross	0			390,000,000
Debt face amount		$ 300,000,000
Credit facilities | US$150 million unsecured extendible revolving facility
Debt Instrument
Long-term debt, gross	81,000,000			163,000,000
Debt face amount		$ 150,000,000
Credit facilities | Commercial paper
Debt Instrument
Long-term debt, gross	260,000,000			367,000,000
Credit facilities | Secured Extendible Revolving Facility Due June 2022
Debt Instrument
Long-term debt, gross	51,000,000			$ 0
Debt face amount	$ 175,000,000

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)
Operating Facility
Debt Instrument
Credit facility maximum borrowing capacity		$ 15,000,000
Revolving credit facility
Debt Instrument
Credit facility maximum borrowing capacity		300,000,000		$ 300,000,000
Amount outstanding	$ 0
Revolving credit facility | Commercial paper
Debt Instrument
Long-term debt, gross	260,000,000		$ 367,000,000
Revolving credit facility | Petrogas Energy Corporation
Debt Instrument
Credit facility maximum borrowing capacity	175,000,000
Amount outstanding	0
Revolving credit facility | Petrogas Energy Corporation | Operating Facility
Debt Instrument
Credit facility maximum borrowing capacity		10,000,000
Revolving credit facility | Letter of Credit | WGL Holdings
Debt Instrument
Credit facility maximum borrowing capacity		250,000,000		250,000,000
Amount outstanding	0
Revolving credit facility | Letter of Credit | Washington Gas
Debt Instrument
Credit facility maximum borrowing capacity		$ 450,000,000		$ 450,000,000
Amount outstanding	0
Revolving credit facility | Letter of Credit | Petrogas Energy Corporation
Debt Instrument
Credit facility maximum borrowing capacity	25,000,000
Amount outstanding	57,000,000
Revolving credit facility | Letter of Credit | Petrogas Energy Corporation | Operating Facility
Debt Instrument
Amount outstanding	$ 0

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis
Balance, beginning of year	$ 362	$ 500
Obligations acquired (note 3)	13	0
New obligations	14	7
Obligations settled	(4)	(2)
Disposals	(1)	(6)
Revision in estimated cash flow	(10)	(129)
Accretion expense	17	19
Foreign exchange translation	(6)	(21)
Total	385	368
Less: current portion (included in accounts payable and accrued liabilities)	(6)	(6)
Balance, end of year	$ 379	$ 362

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligations
Undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation	$ 816	$ 727
Minimum
Asset Retirement Obligations
Discount rate for asset retirement obligations (percent)	2.00%	2.00%
Maximum
Asset Retirement Obligations
Discount rate for asset retirement obligations (percent)	8.50%	8.50%

Environmental Matters (Details)

Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)site	Dec. 31, 2019CAD ($)
Site Contingency
Identified operated manufactured gas plants | site	12
Accrual for environmental loss contingencies	$ 13	$ 14
Regulatory assets	15	18
Maximum
Site Contingency
Accrual for environmental loss contingencies	$ 39	$ 40

Other Long-term Liabilities - S

Other Long-term Liabilities - Schedule of Other Long-Term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Liabilities Disclosure [Abstract]
Deferred revenue	$ 8	$ 4
Customer advances for construction	60	64
Merger commitments	10	14
Other employee benefits	6	6
Deferred payroll taxes	6	0
Petrogas equalization reserve	5	0
Uncertain tax positions	21	2	$ 2
Non-pension retirement benefits	16	0
Other	21	12
Other long-term liabilities	$ 153	$ 102

Income Taxes - Schedule of Inco

Income Taxes - Schedule of Income Tax Provision (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income before income taxes - consolidated	$ 699	$ 812
Statutory income tax rate (percent)	24.00%	26.50%
Expected taxes at statutory rates	$ 168	$ 215
Permanent differences	2	11
Statutory and other rate differences	9	(52)
Rate adjustment for change in tax rates	0	(11)
Deferred income tax recovery on regulated assets	(15)	(25)
Tax differences on divestitures and transactions	(33)	(159)
Change in valuation allowance	(2)	(11)
Other	(2)	4
Income tax expense, total	127	(28)
Current	1	63
Deferred	$ 126	$ (91)
Effective income tax rate (percent)	18.20%	(3.40%)

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Income Tax Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
PP&E and intangible assets	$ 1,645	$ 1,450
Regulatory assets	(229)	(204)
Tax pools, deferred financing, and compensation	(208)	(138)
Other	(94)	(161)
Valuation allowance	4	12
Net deferred income tax liabilities	$ 1,118	$ 959

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - CAD ($) $ in Millions	Jul. 01, 2020	Jul. 01, 2019	Jun. 30, 2020	Dec. 31, 2020	Dec. 31, 2019
Income Tax Contingency
Statutory income tax rate (percent)				24.00%	26.50%
Tax-affected non-capital losses				$ 293
Canada Revenue Agency
Income Tax Contingency
Statutory income tax rate (percent)	8.00%	11.00%	12.00%

Income Taxes - Schedule of Unce

Income Taxes - Schedule of Uncertain Tax Positions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of Unrecognized Tax Benefits
Balance, beginning of year	$ 2	$ 2
Gross increases for tax positions of prior year	21	0
Lapses of statute of limitations	(2)	0
Balance, end of year	$ 21	$ 2

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Details) $ in Millions, $ in Millions	Sep. 18, 2013USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 46	$ 13
Regulatory assets - non-current		444	487
Regulatory liabilities - current		90	146
Regulatory liabilities - non-current		1,381	1,383
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		56	61
Refundable tax credit
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		2	2
Gas storage facility tax credit	$ 15
Virginia Rate Refund
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		0	41
Federal income tax rate change
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		20	33
Regulatory liabilities - non-current		578	628
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		335	261
Future removal and site restoration costs
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		462	484
Deferred gain on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		1	2
Fair value adjustment		76	80
Interruptible sharing
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		1	0
Virginia Coronavirus Relief Fund
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		10	0
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current		1	9
Regulatory liabilities - non-current		3	4
Refundable tax credit noncurrent
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current		$ 2	4
Recovery period (years)		2 years
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		$ 18	8
Accelerated replacement recovery mechanisms
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		6	2
Interruptible sharing
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		2	3
Energy Optimization Costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		1	0
Virginia and Maryland Revenue Normalization
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current		19	0
Deferred regulatory costs and rate stabilization adjustment mechanism
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 158	150
Deferred regulatory costs and rate stabilization adjustment mechanism | Minimum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		2 years
Deferred regulatory costs and rate stabilization adjustment mechanism | Maximum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)		55 years
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 68	128
Future recovery of non-retirement employee benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		22	19
Deferred environmental costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		15	18
Deferred loss on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		93	99
Fair value adjustment		76	80
Deferred future income taxes
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		46	43
Energy efficiency program - Maryland
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		18	12
COVID-19 Costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		10	0
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current		$ 14	$ 18

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	$ 7,369
Total other comprehensive loss (OCI), net of taxes (note 22)	(195)	$ (334)
Balance, end of year	7,661	7,369
Total
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	245	579
OCI before reclassification	(201)	(324)
Amounts reclassified from OCI	3	1
Current period OCI (pre-tax)	(198)	(323)
Income tax on amounts retained in AOCI	4	(11)
Income tax on amounts reclassified to earnings	(1)	0
Total other comprehensive loss (OCI), net of taxes (note 22)	(195)	(334)
Balance, end of year	50	245
Defined benefit pension and PRB plans
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(6)	(19)
OCI before reclassification	(11)	15
Amounts reclassified from OCI	3	1
Current period OCI (pre-tax)	(8)	16
Income tax on amounts retained in AOCI	3	(3)
Income tax on amounts reclassified to earnings	(1)
Total other comprehensive loss (OCI), net of taxes (note 22)	(6)	13
Balance, end of year	(12)	(6)
Hedge net investments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(149)	(209)
OCI before reclassification	(10)	68
Amounts reclassified from OCI	0	0
Current period OCI (pre-tax)	(10)	68
Income tax on amounts retained in AOCI	1	(8)
Income tax on amounts reclassified to earnings	0
Total other comprehensive loss (OCI), net of taxes (note 22)	(9)	60
Balance, end of year	(158)	(149)
Translation foreign operations
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	395	801
OCI before reclassification	(175)	(406)
Amounts reclassified from OCI	0	0
Current period OCI (pre-tax)	(175)	(406)
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0
Total other comprehensive loss (OCI), net of taxes (note 22)	(175)	(406)
Balance, end of year	220	395
Equity investee
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	5	6
OCI before reclassification	(5)	(1)
Amounts reclassified from OCI	0	0
Current period OCI (pre-tax)	(5)	(1)
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings	0
Total other comprehensive loss (OCI), net of taxes (note 22)	(5)	(1)
Balance, end of year	$ 0	$ 5

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income - Summary of Reclassification from Accumulated Other Comprehensive Income (Details) - Total - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Defined benefit pension and PRB plans	$ 3	$ 1
Deferred income taxes	(1)	0
Reclassifications from AOCI, net	$ 2	$ 1

Financial Instruments and Fin_3

Financial Instruments and Financial Risk Management - Schedule of Fair Value of Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	$ 98	$ 87
Risk management assets - non-current	47	39
Risk management liabilities - current	111	125
Risk management liabilities - non-current	145	167
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		45
Financial assets	145	175
Current portion of long-term debt	360	923
Long-term debt	7,626	5,928
Other current liabilities	37	15
Financial liabilities	8,279	7,158
Carrying Amount | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	94	82
Risk management assets - non-current	38	31
Equity securities		4
Risk management liabilities - current	102	121
Risk management liabilities - non-current	66	77
Carrying Amount | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	4	5
Risk management assets - non-current	9	8
Risk management liabilities - current	9	4
Risk management liabilities - non-current	79	90
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		46
Financial assets	145	176
Current portion of long-term debt	360	923
Long-term debt	8,451	6,264
Other current liabilities	37	15
Financial liabilities	9,104	7,494
Fair Value | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	94	82
Risk management assets - non-current	38	31
Equity securities		4
Risk management liabilities - current	102	121
Risk management liabilities - non-current	66	77
Fair Value | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	4	5
Risk management assets - non-current	9	8
Risk management liabilities - current	9	4
Risk management liabilities - non-current	79	90
Fair Value | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		0
Financial assets	0	4
Current portion of long-term debt	0	0
Long-term debt	0	0
Other current liabilities	0	0
Financial liabilities	0	0
Fair Value | Level 1 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	0	0
Risk management assets - non-current	0	0
Equity securities		4
Risk management liabilities - current	0	0
Risk management liabilities - non-current	0	0
Fair Value | Level 1 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	0	0
Risk management assets - non-current	0	0
Risk management liabilities - current	0	0
Risk management liabilities - non-current	0	0
Fair Value | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		46
Financial assets	76	84
Current portion of long-term debt	360	923
Long-term debt	8,451	6,264
Other current liabilities	37	15
Financial liabilities	8,942	7,321
Fair Value | Level 2 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	73	31
Risk management assets - non-current	2	7
Equity securities		0
Risk management liabilities - current	78	99
Risk management liabilities - non-current	15	19
Fair Value | Level 2 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	1	0
Risk management assets - non-current	0	0
Risk management liabilities - current	0	1
Risk management liabilities - non-current	1	0
Fair Value | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loans and receivables		0
Financial assets	69	88
Current portion of long-term debt	0	0
Long-term debt	0	0
Other current liabilities	0	0
Financial liabilities	162	173
Fair Value | Level 3 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	21	51
Risk management assets - non-current	36	24
Equity securities		0
Risk management liabilities - current	24	22
Risk management liabilities - non-current	51	58
Fair Value | Level 3 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	3	5
Risk management assets - non-current	9	8
Risk management liabilities - current	9	3
Risk management liabilities - non-current	$ 78	$ 90

Financial Instruments and Fin_4

Financial Instruments and Financial Risk Management - Quantitative Information About The Significant Unobservable Inputs Used In The Fair Value Measurement Of Level 3 (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)$ / dekatherm$ / MWh
Natural Gas | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (73)
Fair Value, Net Asset (Liability), Per Dekatherm	(0.37)
Natural Gas | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(1.27)
Natural Gas | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	2.64
Natural Gas | Option Model
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (1)
Fair Value, Net Asset (Liability), Per Dekatherm	(0.01)
Fair Value, Net Asset (Liability), Percent	73.00%
Natural Gas | Option Model | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(1.27)
Fair Value, Net Asset (Liability), Percent	13.00%
Natural Gas | Option Model | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	2.58
Fair Value, Net Asset (Liability), Percent	917.00%
Electricity | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (19)
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MWh	13.57
Electricity | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MWh	(6.26)
Electricity | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MWh	61.88

Financial Instruments and Fin_5

Financial Instruments and Financial Risk Management - Changes In Net Fair Value Of Derivative Assets And Liabilities Classified As Level 3 (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	$ (85)	$ (163)
Recorded in income	(47)	49
Recorded in regulatory assets	(1)	24
Transfers into Level 3	(1)	(9)
Transfers out of Level 3	1	12
Purchases	3	(11)
Settlements	36	7
Foreign exchange translation	1	6
Balance, end of year	(93)	(85)
Natural Gas
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	(85)	(149)
Recorded in income	8	48
Recorded in regulatory assets	(1)	24
Transfers into Level 3	(1)	(9)
Transfers out of Level 3	1	12
Purchases	0	0
Settlements	4	(17)
Foreign exchange translation	0	6
Balance, end of year	(74)	(85)
Electricity
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	0	(14)
Recorded in income	(55)	1
Recorded in regulatory assets	0	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Purchases	3	(11)
Settlements	32	24
Foreign exchange translation	1	0
Balance, end of year	$ (19)	$ 0

Financial Instruments and Fin_6

Financial Instruments and Financial Risk Management - Realized and Unrealized Losses Recorded to Income for Level 3 Measurements (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ (47)	$ 49
Commodity contracts | Recorded to revenue
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	(79)	75
Commodity contracts | Recorded to cost of sales
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ 32	$ (26)

Financial Instruments and Fin_7

Financial Instruments and Financial Risk Management - Summary of Unrealized Gains (Losses) on Risk Management Contracts (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ 21	$ (85)
Natural gas
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	32	23
Energy exports
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	10	(87)
Crude oil and NGLs
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	4	0
NGL frac spread
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(5)	(17)
Power
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(15)	(5)
Foreign exchange
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ (5)	$ 1

Financial Instruments and Fin_8

Financial Instruments and Financial Risk Management - Schedule of Offsetting Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Offsetting Assets And Liabilities
Netting of collateral	$ 0	$ 6
Risk management assets - current	98	87
Risk management assets - non-current	47	39
Risk management liabilities - current	111	125
Risk management liabilities - non-current	145	167
Risk management contracts
Offsetting Assets And Liabilities
Gross amounts of recognized assets	248	185
Gross amounts offset in balance sheet	(135)	(64)
Netting of collateral	32	5
Net amount of assets presented in balance sheet	145	126
Gross amounts of recognized liabilities	393	387
Gross amounts offset in balance sheet	(135)	(64)
Netting of collateral	(2)	(31)
Net amount of liabilities presented in balance sheet	256	292
Natural gas
Offsetting Assets And Liabilities
Gross amounts of recognized assets	104	121
Gross amounts offset in balance sheet	(38)	(54)
Netting of collateral	(3)	0
Net amount of assets presented in balance sheet	63	67
Gross amounts of recognized liabilities	173	226
Gross amounts offset in balance sheet	(38)	(54)
Netting of collateral	(3)	(28)
Net amount of liabilities presented in balance sheet	132	144
Energy exports
Offsetting Assets And Liabilities
Gross amounts of recognized assets	86
Gross amounts offset in balance sheet	(86)
Netting of collateral	36
Net amount of assets presented in balance sheet	36
Gross amounts of recognized liabilities	153	90
Gross amounts offset in balance sheet	(86)	(3)
Netting of collateral	0	0
Net amount of liabilities presented in balance sheet	67	87
Crude oil and NGLs
Offsetting Assets And Liabilities
Gross amounts of recognized assets	1
Gross amounts offset in balance sheet	0
Netting of collateral	0
Net amount of assets presented in balance sheet	1
NGL frac spread
Offsetting Assets And Liabilities
Gross amounts of recognized assets		10
Gross amounts offset in balance sheet		(3)
Netting of collateral		5
Net amount of assets presented in balance sheet		12
Gross amounts of recognized liabilities	6	2
Gross amounts offset in balance sheet	0	0
Netting of collateral	0	0
Net amount of liabilities presented in balance sheet	6	2
Power
Offsetting Assets And Liabilities
Gross amounts of recognized assets	30	54
Gross amounts offset in balance sheet	(8)	(7)
Netting of collateral	0	0
Net amount of assets presented in balance sheet	22	47
Gross amounts of recognized liabilities	58	69
Gross amounts offset in balance sheet	(8)	(7)
Netting of collateral	1	(3)
Net amount of liabilities presented in balance sheet	51	$ 59
Foreign exchange
Offsetting Assets And Liabilities
Gross amounts of recognized assets	27
Gross amounts offset in balance sheet	(3)
Netting of collateral	(1)
Net amount of assets presented in balance sheet	23
Gross amounts of recognized liabilities	3
Gross amounts offset in balance sheet	(3)
Netting of collateral	0
Net amount of liabilities presented in balance sheet	$ 0

Financial Instruments and Fin_9

Financial Instruments and Financial Risk Management - Collateral Not Offset Against Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Collateral posted with counterparties	$ 4	$ 29
Cash collateral held representing an obligation	$ 0	$ 0

Financial Instruments and Fi_10

Financial Instruments and Financial Risk Management - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Netting of collateral	$ 0	$ 6
Long term debt	7,986	6,851
Other comprehensive loss	(195)	(334)
Unrealized gain on net investment hedge	(9)	60
Unrealized gains (losses) on risk management contracts	21	$ (85)
Foreign Exchange Forward
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Realized gain on foreign exchange forward contracts	$ 1
Interest rate risk
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Fixed rate debt, percent	83.00%	76.00%	76.00%
Weather related instruments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Unrealized gains (losses) on risk management contracts	$ (3)	$ (2)
Net investment hedge
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Long term debt			$ 300
Hedge net investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Other comprehensive loss	$ (9)	$ 60

Financial Instruments and Fi_11

Financial Instruments and Financial Risk Management - Risk Management Liabilities And Maximum Potential Collateral Requirements (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk management liabilities with credit-risk-contingent features	$ 32	$ 42
Maximum potential collateral requirements	$ 26	$ 29

Financial Instruments and Fi_12

Financial Instruments and Financial Risk Management - Schedule of Fixed and Market Price Contract (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)kJMWh$ / gigajoule$ / barrel$ / MWhbbl	Dec. 31, 2019CAD ($)kJMWh$ / barrel$ / MWh$ / gigajoulebbl
Natural gas | Sales
Derivative
Notional volume (GJ) | kJ	590,054,996	698,126,985
Fair Value ($)	$ 32	$ 29
Natural gas | Sales | Minimum
Derivative
Fixed price | $ / gigajoule	1.58	1.32
Period (months)	1 month	1 month
Natural gas | Sales | Maximum
Derivative
Fixed price | $ / gigajoule	7.86	6.81
Period (months)	157 months	166 months
Natural gas | Purchases
Derivative
Notional volume (GJ) | kJ	1,522,958,497	1,406,991,689
Fair Value ($)	$ (106)	$ (104)
Natural gas | Purchases | Minimum
Derivative
Fixed price | $ / gigajoule	1.58	0.22
Period (months)	1 month	1 month
Natural gas | Purchases | Maximum
Derivative
Fixed price | $ / gigajoule	6.47	6.81
Period (months)	240 months	167 months
Natural gas | Swaps
Derivative
Notional volume (GJ) | kJ	288,613,586	541,652,374
Fair Value ($)	$ 5	$ (2)
Natural gas | Swaps | Minimum
Derivative
Fixed price | $ / gigajoule	2.29	0.22
Period (months)	1 month	1 month
Natural gas | Swaps | Maximum
Derivative
Fixed price | $ / gigajoule	7.86	10.24
Period (months)	60 months	51 months
Crude oil and NGLs | Sales
Derivative
Period (months)	1 month
Notional volume (GJ) | kJ		680,000
Fair Value ($)		$ (1)
Crude oil and NGLs | Sales | Minimum
Derivative
Fixed price | $ / gigajoule	37.43
Crude oil and NGLs | Sales | Maximum
Derivative
Fixed price | $ / gigajoule	62.59
Crude oil and NGLs | Purchases
Derivative
Notional volume (GJ) | kJ		221,000
Fair Value ($)		$ 2
Crude oil and NGLs | Purchases | Minimum
Derivative
Fixed price | $ / gigajoule	19.92
Period (months)	1 month
Crude oil and NGLs | Purchases | Maximum
Derivative
Fixed price | $ / gigajoule	59.01
Period (months)	9 months
Energy exports | Propane and butane swaps
Derivative
Notional volume (Bbl) | bbl	37,425,488
Fair Value ($)	$ (31)
Energy exports | Propane
Derivative
Notional volume (Bbl) | bbl		9,374,826
Fair Value ($)		$ (75)
Energy exports | Minimum | Propane and butane swaps
Derivative
Fixed price | $ / barrel	3.57
Period (months)	1 month
Energy exports | Minimum | Propane
Derivative
Fixed price | $ / barrel	21.49
Period (months)	1 month
Energy exports | Maximum | Propane and butane swaps
Derivative
Fixed price | $ / barrel	61.46
Period (months)	36 months
Energy exports | Maximum | Propane
Derivative
Fixed price | $ / barrel	29.71
Period (months)	27 months
NGL frac spread | Propane
Derivative
Notional volume (Bbl) | bbl	1,270,350
Fair Value ($)	$ (5)
NGL frac spread | Minimum | Propane
Derivative
Fixed price | $ / barrel	28.83
Period (months)	1 month
NGL frac spread | Minimum | Butane swaps
Derivative
Fixed price | $ / barrel	32.45	73.02
Period (months)	1 month	1 month
NGL frac spread | Minimum | Crude oil swaps
Derivative
Fixed price | $ / barrel	60.08	73.02
Period (months)	1 month	1 month
NGL frac spread | Minimum | Gas purchase
Derivative
Fixed price | $ / gigajoule	1.58	1.58
Period (months)	1 month	1 month
NGL frac spread | Maximum | Propane
Derivative
Fixed price | $ / barrel	35.36
Period (months)	12 months
NGL frac spread | Maximum | Butane swaps
Derivative
Fixed price | $ / barrel	34.02	75.15
Period (months)	12 months	12 months
NGL frac spread | Maximum | Crude oil swaps
Derivative
Fixed price | $ / barrel	61.95	75.15
Period (months)	12 months	12 months
NGL frac spread | Maximum | Gas purchase
Derivative
Fixed price | $ / gigajoule	1.86	1.86
Period (months)	12 months	12 months
NGL frac spread | Swaps | Butane swaps
Derivative
Notional volume (Bbl) | bbl	307,784	346,852
Fair Value ($)	$ (1)	$ (1)
NGL frac spread | Swaps | Crude oil swaps
Derivative
Notional volume (Bbl) | bbl	123,120	212,587
Fair Value ($)	$ 0	$ (1)
NGL frac spread | Swaps | Gas purchase
Derivative
Notional volume (GJ) | kJ	7,281,570	3,883,992
Fair Value ($)	$ 0	$ 0
Power | Sales
Derivative
Notional volume (GJ) | MWh	5,482,242	8,034,024
Fair Value ($)	$ 13	$ 39
Power | Sales | Minimum
Derivative
Fixed price | $ / MWh	24.56	31.63
Period (months)	1 month	1 month
Power | Sales | Maximum
Derivative
Fixed price | $ / MWh	61.75	66.76
Period (months)	33 months	42 months
Power | Purchases
Derivative
Notional volume (GJ) | MWh	8,848,007	8,552,467
Fair Value ($)	$ (18)	$ (27)
Power | Purchases | Minimum
Derivative
Fixed price | $ / MWh	24.56	31.63
Period (months)	1 month	1 month
Power | Purchases | Maximum
Derivative
Fixed price | $ / MWh	61.88	66.76
Period (months)	63 months	60 months
Power | Swaps
Derivative
Notional volume (GJ) | MWh	24,081,519	25,058,577
Fair Value ($)	$ (24)	$ (24)
Power | Swaps | Minimum
Derivative
Fixed price | $ / MWh	(6.26)	(7.88)
Period (months)	1 month	1 month
Power | Swaps | Maximum
Derivative
Fixed price | $ / MWh	74.26	74.26
Period (months)	44 months	48 months

Financial Instruments and Fi_13

Financial Instruments and Financial Risk Management - Summary of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives (Details)	12 Months Ended
	Dec. 31, 2020CAD ($)$ / gigajoule$ / gigajoule$ / MWh$ / barrel	Dec. 31, 2019CAD ($)
Derivative
Unrealized gains (losses) on risk management contracts	$ 21,000,000	$ (85,000,000)
PJM power price
Derivative
Increase or decrease to forward prices, energy | $ / MWh	1
Unrealized gains (losses) on risk management contracts	$ 2,000,000
AECO natural gas price
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.50
Unrealized gains (losses) on risk management contracts	$ 1,000,000
NYMEX natural gas price
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.50
Unrealized gains (losses) on risk management contracts	$ 36,000,000
Energy exports
Derivative
Unrealized gains (losses) on risk management contracts	$ 10,000,000
Energy exports | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Baltic LPG Freight
Derivative
Unrealized gains (losses) on risk management contracts	$ 11,000,000
Baltic LPG Freight | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
NGL frac spread
Derivative
Unrealized gains (losses) on risk management contracts	$ (5,000,000)	$ (17,000,000)
NGL frac spread | Propane
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Unrealized gains (losses) on risk management contracts	$ 1,000,000
NGL frac spread | Natural Gas
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.50
Unrealized gains (losses) on risk management contracts	$ 4,000,000
Foreign Exchange
Derivative
Increase or decrease to forward prices, foreign exchange swap	0.01
Unrealized gains (losses) on risk management contracts	$ 1,000,000

Financial Instruments and Fi_14

Financial Instruments and Financial Risk Management - Acquired Foreign Exchange Contracts (Details) - Foreign Exchange Forward $ in Millions, $ in Millions	Dec. 31, 2020USD ($)	Dec. 31, 2020CAD ($)
Sales
Derivative
Notional Amount	$ 29
Weighted average foreign exchange rate	1.3591	1.3591
Fair Value		$ 3
Purchases
Derivative
Notional Amount	$ 356
Weighted average foreign exchange rate	1.2824	1.2824
Fair Value		$ (3)
Swaps
Derivative
Notional Amount	$ 410
Weighted average foreign exchange rate	1.3322	1.3322
Fair Value		$ 23

Financial Instruments and Fi_15

Financial Instruments and Financial Risk Management - Schedule of Accounts Receivable Past Due or Impaired (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable
AR accruals	$ 396	$ 343
Receivables impaired	0	0
Allowance for credit losses	(41)	(41)
Accounts receivable	1,444	1,222
Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	926	775
31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	52	61
61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	17	12
Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	53	31
Trade receivable
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	1,465	1,238
AR accruals	396	343
Receivables impaired	41	33
Trade receivable | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	906	758
Trade receivable | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	52	61
Trade receivable | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	17	12
Trade receivable | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	53	31
Other
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	20	17
AR accruals	0	0
Receivables impaired	0	0
Other | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	20	17
Other | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0	0
Other | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0	0
Other | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	0	0
Allowance for credit losses
Accounts, Notes, Loans and Financing Receivable
AR accruals	0	0
Allowance for credit losses	(41)	(33)
Allowance for credit losses | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0	0
Allowance for credit losses | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0	0
Allowance for credit losses | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	0	0
Allowance for credit losses | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Allowance for credit losses	$ 0	$ 0

Financial Instruments and Fi_16

Financial Instruments and Financial Risk Management - Allowance for Credit Loss (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, end of period	$ 44
Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	31
Foreign exchange translation	(1)
New allowance	32
Written off	(28)
Recoveries collected	4
Balance, end of period	40
New allowance from COVID-19	8
Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1
Recoveries collected	(1)
Balance, end of period	4
Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	2
Written off	(2)
Recoveries collected	(1)
Balance, end of period	0
Accounts receivable
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, end of period	41
Accounts receivable | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	31
Foreign exchange translation	(1)
New allowance	32
Written off	(28)
Recoveries collected	4
Balance, end of period	40
Accounts receivable | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1
Recoveries collected	0
Balance, end of period	1
Accounts receivable | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	2
Written off	(2)
Recoveries collected	0
Balance, end of period	0
Contract assets
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, end of period	1
Contract assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Foreign exchange translation	0
New allowance	0
Written off	0
Recoveries collected	0
Balance, end of period	0
Contract assets | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Recoveries collected	0
Balance, end of period	1
Contract assets | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Written off	0
Recoveries collected	0
Balance, end of period	0
Other Long-Term Investments and Other Assets
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, end of period	2
Other Long-Term Investments and Other Assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Foreign exchange translation	0
New allowance	0
Written off	0
Recoveries collected	0
Balance, end of period	0
Other Long-Term Investments and Other Assets | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Recoveries collected	(1)
Balance, end of period	2
Other Long-Term Investments and Other Assets | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Written off	0
Recoveries collected	(1)
Balance, end of period	0
Cumulative Effect, Period of Adoption, Adjustment | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	2
Cumulative Effect, Period of Adoption, Adjustment | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	4
Cumulative Effect, Period of Adoption, Adjustment | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1
Cumulative Effect, Period of Adoption, Adjustment | Accounts receivable | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	2
Cumulative Effect, Period of Adoption, Adjustment | Accounts receivable | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Accounts receivable | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Contract assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Contract assets | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1
Cumulative Effect, Period of Adoption, Adjustment | Contract assets | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Other Long-Term Investments and Other Assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Cumulative Effect, Period of Adoption, Adjustment | Other Long-Term Investments and Other Assets | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	3
Cumulative Effect, Period of Adoption, Adjustment | Other Long-Term Investments and Other Assets | Corporate/Other
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	$ 1

Financial Instruments and Fi_17

Financial Instruments and Financial Risk Management - Schedule of Contractual Maturities for Financial Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Contractual maturities by period
Total	$ 10,069	$ 8,907
Less than 1 year	2,343	2,867
1-3 years	1,822	1,523
4-5 years	1,346	935
After 5 years	4,558	3,582
Accounts payable and accrued liabilities
Contractual maturities by period
Total	1,561	1,325
Less than 1 year	1,561	1,325
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Dividends payable
Contractual maturities by period
Total	22	22
Less than 1 year	22	22
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Short-term debt
Contractual maturities by period
Total	256	460
Less than 1 year	256	460
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Other current liabilities
Contractual maturities by period
Total	37	15
Less than 1 year		15
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Risk management contract liabilities
Contractual maturities by period
Total	256	292
Less than 1 year	111	125
1-3 years	51	34
4-5 years	22	13
After 5 years	72	120
Current portion of long-term debt
Contractual maturities by period
Total	356	920
Less than 1 year	356	920
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Long-term debt
Contractual maturities by period
Total	7,581	5,873
Less than 1 year	0	0
1-3 years	1,771	1,489
4-5 years	1,324	922
After 5 years	$ 4,486	$ 3,462

Revenue - Disaggregation of Rev

Revenue - Disaggregation of Revenue by Major Sources (Details) - CAD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue
Revenue from contracts with customers		$ 5,161	$ 4,940
Other sources of revenue		426	555
Total revenue		5,587	5,495
Contract term	20 years
Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		2,436	2,225
Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		277	145
Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		2,394	2,501
Storage services
Disaggregation of Revenue
Revenue from contracts with customers		25	28
Other
Disaggregation of Revenue
Revenue from contracts with customers		29	41
Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		96	30
Leasing revenue
Disaggregation of Revenue
Other sources of revenue		240	243
Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		81	262
Risk management and trading activities | GAIL
Disaggregation of Revenue
Other sources of revenue		437	505
Other
Disaggregation of Revenue
Other sources of revenue		9	20
Utilities
Disaggregation of Revenue
Total revenue		3,817	4,044
Midstream
Disaggregation of Revenue
Total revenue		1,635	1,228
Operating Segments
Disaggregation of Revenue
Total revenue		5,588	5,527
Operating Segments | Utilities
Disaggregation of Revenue
Revenue from contracts with customers		3,766	3,966
Other sources of revenue		51	78
Total revenue		3,817	4,044
Operating Segments | Utilities | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		1,338	1,428
Operating Segments | Utilities | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Utilities | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		2,394	2,501
Operating Segments | Utilities | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		25	28
Operating Segments | Utilities | Other
Disaggregation of Revenue
Revenue from contracts with customers		9	9
Operating Segments | Utilities | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		96	30
Operating Segments | Utilities | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		1	1
Operating Segments | Utilities | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		(31)	52
Operating Segments | Utilities | Other
Disaggregation of Revenue
Other sources of revenue		(15)	(5)
Operating Segments | Midstream
Disaggregation of Revenue
Revenue from contracts with customers		1,374	894
Other sources of revenue		261	334
Total revenue		1,636	1,260
Operating Segments | Midstream | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		$ 1,097	746
Contract term		1 year
Operating Segments | Midstream | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		$ 277	145
Operating Segments | Midstream | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Midstream | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Midstream | Other
Disaggregation of Revenue
Revenue from contracts with customers		0	3
Operating Segments | Midstream | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0	0
Operating Segments | Midstream | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		139	137
Operating Segments | Midstream | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		112	188
Operating Segments | Midstream | Other
Disaggregation of Revenue
Other sources of revenue		10	9
Operating Segments | Corporate/Other
Disaggregation of Revenue
Revenue from contracts with customers		21	80
Other sources of revenue		114	143
Operating Segments | Corporate/Other | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers		1	51
Operating Segments | Corporate/Other | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate/Other | Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate/Other | Storage services
Disaggregation of Revenue
Revenue from contracts with customers		0	0
Operating Segments | Corporate/Other | Other
Disaggregation of Revenue
Revenue from contracts with customers		20	29
Operating Segments | Corporate/Other | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue		0	0
Operating Segments | Corporate/Other | Leasing revenue
Disaggregation of Revenue
Other sources of revenue		100	105
Operating Segments | Corporate/Other | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue		0	22
Operating Segments | Corporate/Other | Other
Disaggregation of Revenue
Other sources of revenue		$ 14	$ 16

Revenue - Narrative (Details)

Revenue - Narrative (Details) - CAD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue
Contract term	20 years
Contract with customer, asset, before allowance		$ 51
Contract asset, non current		50	$ 30
Contract asset, current		21	59
Contract liability		$ 0	$ 2	$ 2
Utilities | Operating Segments | Commodity sales contracts | Minimum
Disaggregation of Revenue
Contract term		1 year
Utilities | Operating Segments | Commodity sales contracts | Maximum
Disaggregation of Revenue
Contract term		5 years
Midstream | Operating Segments | Commodity sales contracts
Disaggregation of Revenue
Contract term		1 year
Corporate/Other
Disaggregation of Revenue
Purchase agreement period		20 years

Revenue - Contract Assets and L

Revenue - Contract Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Change in Contract with Customer, Asset
Balance, beginning of year	$ 89	$ 59
Additions	30	32
Transfers to accounts receivable	(49)	0
Foreign exchange translation	1	(2)
Balance, end of year	71	89
Change in Contract with Customer, Liability
Balance, beginning of year	2	2
Additions	2	2
Revenue recognized from contract liabilities	(4)	(2)
Balance, end of year	$ 0	$ 2

Revenue - Schedule of Estimated

Revenue - Schedule of Estimated Revenue Related to Performance Obligations (Details) $ in Millions	Dec. 31, 2020CAD ($)
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,956
Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	1,674
Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	258
Other
Estimated revenue expected to be recognized in the future related to performance obligations	24
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 156
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 125
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 24
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 7
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 156
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 131
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 153
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 128
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 153
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 128
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 150
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 125
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 23
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,188
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Midstream service contracts
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,037
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Storage services
Estimated revenue expected to be recognized in the future related to performance obligations	$ 142
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Other
Estimated revenue expected to be recognized in the future related to performance obligations	$ 9
Performance satisfaction period	1 year

Shareholders_ Equity - Narrativ

Shareholders’ Equity - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)planshares	Dec. 31, 2019CAD ($)
Share-based Compensation Arrangement by Share-based Payment Award
Number of dividend reinvestment plans (plan) | plan	2
Gain on redemption of preferred shares	$ 0
Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Shares reserved for issuance | shares	13,915,160
Unexpensed fair value of share option compensation cost	$ 4	$ 5
Aggregate intrinsic value of options exercisable	5	3
Intrinsic value of options outstanding	9	12
Mid-Term Incentive And Deferred Share Unit Plans
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense	16	22
Unrecognized compensation expense	$ 23	22
Minimum | Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options term	6 years
Minimum | Mid-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	36 months
Maximum | Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Options term	10 years
Vesting period	4 years
Intrinsic value of options exercised	$ 1	1
Maximum | Mid-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	44 months
Washington Gas
Share-based Compensation Arrangement by Share-based Payment Award
Gain on redemption of preferred shares		$ 4

Shareholders_ Equity - Schedule

Shareholders’ Equity - Schedule of Common Shares Issued and Outstanding (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Increase (Decrease) in Stockholders' Equity
Shares issued for cash on exercise of options (shares)		88,082	76,177
Balance, beginning of year		$ 7,215
Balance at end of year		$ 7,041	$ 7,215
Common stock
Increase (Decrease) in Stockholders' Equity
Beginning balance (shares)		279,074,685	275,224,066
Shares issued for cash on exercise of options (shares)		88,082	76,177
Shares issued under DRIP (shares)		331,532	3,774,442
Ending balance (shares)		279,500,000	279,074,685
Balance, beginning of year		$ 6,719	$ 6,654
Shares issued for cash on exercise of options		1	1
Deferred taxes on share issuance cost		(3)	(4)
Shares issued under DRIP	[1]	6	68
Balance at end of year		$ 6,723	$ 6,719
[1]	Premium Dividend™, Dividend Reinvestment and Optional Cash Purchase Plan (DRIP). The plan was suspended in December 2019, with the December dividend (paid January 2020) being the last dividend payment eligible for reinvestment by participating shareholders under the DRIP.

Shareholders' Equity - Schedule

Shareholders' Equity - Schedule of Preferred Shares Issued and Outstanding (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Class of Stock
Preferred stock, value	$ 7,041	$ 7,215
Preferred shares
Class of Stock
Preferred stock, shares	44,000,000	52,000,000
Preferred stock, value	$ 1,077	$ 1,277
Share issuance costs, net of taxes	$ (29)	$ (29)
Preferred shares | Series A
Class of Stock
Preferred stock, shares	6,746,679	5,511,220
Preferred stock, value	$ 169	$ 138
Preferred shares | Series B
Class of Stock
Preferred stock, shares	1,253,321	2,488,780
Preferred stock, value	$ 31	$ 62
Preferred shares | Series C
Class of Stock
Preferred stock, shares	8,000,000	8,000,000
Preferred stock, value	$ 206	$ 206
Preferred shares | Series E
Class of Stock
Preferred stock, shares	8,000,000	8,000,000
Preferred stock, value	$ 200	$ 200
Preferred shares | Series G
Class of Stock
Preferred stock, shares	6,885,823	6,885,823
Preferred stock, value	$ 172	$ 172
Preferred shares | Series H
Class of Stock
Preferred stock, shares	1,114,177	1,114,177
Preferred stock, value	$ 28	$ 28
Preferred shares | Series I
Class of Stock
Preferred stock, shares	0	8,000,000
Preferred stock, value	$ 0	$ 200
Preferred shares | Series K
Class of Stock
Preferred stock, shares	12,000,000	12,000,000
Preferred stock, value	$ 300	$ 300

Shareholders_ Equity - Summary

Shareholders’ Equity - Summary of Cumulative Redeemable Preferred Shares (Details)	12 Months Ended
	Dec. 31, 2020$ / sharesshares	Dec. 31, 2020$ / sharesshares	Oct. 01, 2019$ / shares	Oct. 01, 2015$ / shares
Series A
Class of Stock
Current Yield	3.06%
Annual dividend per share	$ 0.76500
Redemption price (per share)	$ 25
Series A | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	2.66%	2.66%
Series B
Class of Stock
Redemption price (per share) | (per share)	$ 25			$ 25.50
Preferred stock floating dividend rate (per share)	$ 0.17069
Series B | 90-Day government of Canada treasury bill rate
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	2.66%	2.66%
Series C
Class of Stock
Current Yield	5.29%
Annual dividend per share	$ 1.32250
Redemption price (per share)	$ 25
Series C | Five year United States government bond
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.58%	3.58%
Series E
Class of Stock
Current Yield	5.393%
Annual dividend per share	$ 1.34825
Redemption price (per share)	$ 25
Series E | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.17%	3.17%
Series G
Class of Stock
Current Yield	4.24%
Annual dividend per share	$ 1.06050
Redemption price (per share)	$ 25
Series G | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.06%	3.06%
Series H
Class of Stock
Redemption price (per share) | (per share)	$ 25		$ 25.50
Preferred stock floating dividend rate (per share)	$ 0.195349
Series H | 90-Day government of Canada treasury bill rate
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.06%	3.06%
Series K
Class of Stock
Current Yield	5.00%
Annual dividend per share	$ 1.25000
Redemption price (per share)	$ 25
Series K | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.80%	3.80%
Series K | Five year government of Canada bond yield | Minimum
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	5.00%	5.00%
Series D
Class of Stock
Redemption price (per share)		$ 25.50
Preferred stock shares authorized (shares) | shares	8,000,000	8,000,000
Series L
Class of Stock
Redemption price (per share)		$ 25.50
Series L | Maximum
Class of Stock
Preferred stock shares authorized (shares) | shares	12,000,000	12,000,000

Shareholders_ Equity - Summar_2

Shareholders’ Equity - Summary of Share Option Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Number of options
Share options outstanding, beginning of year (shares)	7,043,956	6,309,183
Granted (shares)	2,501,755	2,287,385
Exercised (shares)	(88,082)	(76,177)
Forfeited (shares)	(631,549)	(1,165,435)
Expired (in shares)	(463,869)	(311,000)
Share options outstanding, end of year (shares)	8,362,211	7,043,956
Share options exercisable, end of year (shares)	3,607,391	2,921,642,000,000
Exercise price
Share options outstanding, beginning of year (per share)	$ 22.49	$ 25.18
Granted (per share)	19.46	19.12
Exercised (per share)	14.89	14.52
Forfeited (per share)	26	27.31
Expired (per share)	27.69	36.16
Share options outstanding, end of year (per share)	21.06	22.49
Share options exercisable, end of year (per share)	$ 23.59	$ 27.70

Shareholders_ Equity - Summar_3

Shareholders’ Equity - Summary of Employee Share Option Plan (Details)	12 Months Ended
	Dec. 31, 2020$ / shares$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Number outstanding (shares) | shares	8,362,211
Options outstanding, Weighted average exercise price (per share)	$ 21.06
Options outstanding, Weighted average remaining contractual life	3 years 10 months 17 days
Options exercisable, Number exercisable (shares) | shares	3,607,391
Options exercisable, Weighted average exercise price (per share)	$ 23.59
Options exercisable, Weighted average remaining contractual life	2 years 11 months 12 days
$14.52 to $18.00
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Exercise price range, Lower limit (per share)	$ 14.52
Options outstanding, Exercise price range, Upper limit (per share)	$ 18
Options outstanding, Number outstanding (shares) | shares	2,446,392
Options outstanding, Weighted average exercise price (per share)	$ 15.24
Options outstanding, Weighted average remaining contractual life	4 years 25 days
Options exercisable, Number exercisable (shares) | shares	1,359,457
Options exercisable, Weighted average exercise price (per share)	$ 14.92
Options exercisable, Weighted average remaining contractual life	4 years
$18.01 to $25.08
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Exercise price range, Lower limit (per share)	$ 18.01
Options outstanding, Exercise price range, Upper limit (per share)	$ 25.08
Options outstanding, Number outstanding (shares) | shares	3,930,345
Options outstanding, Weighted average exercise price (per share)	$ 19.56
Options outstanding, Weighted average remaining contractual life	4 years 9 months 18 days
Options exercisable, Number exercisable (shares) | shares	528,252
Options exercisable, Weighted average exercise price (per share)	$ 19.54
Options exercisable, Weighted average remaining contractual life	4 years 5 months 19 days
$25.09 to $41.00
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Exercise price range, Lower limit (per share)	$ 25.09
Options outstanding, Exercise price range, Upper limit (per share)	$ 41
Options outstanding, Number outstanding (shares) | shares	1,985,474
Options outstanding, Weighted average exercise price (per share)	$ 31.21
Options outstanding, Weighted average remaining contractual life	1 year 9 months 25 days
Options exercisable, Number exercisable (shares) | shares	1,719,682
Options exercisable, Weighted average exercise price (per share)	$ 31.68
Options exercisable, Weighted average remaining contractual life	1 year 7 months 20 days

Shareholders_ Equity - Summar_4

Shareholders’ Equity - Summary of Fair Value Options Granted (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
Fair value per option (per share)	$ 2.61	$ 2.30
Risk-free interest rate (percent)	1.54%	1.48%
Expected life (years)	6 years	6 years
Expected volatility (percent)	25.40%	24.84%
Annual dividend per share (per share)	$ 0.96	$ 0.96
Forfeiture rate (percent)	0.00%	0.00%

Shareholders_ Equity - Schedu_2

Shareholders’ Equity - Schedule of MTIP and DSUP Activity (Details) - shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
PUs, RUs, and DSUs (number of units)
Balance, beginning of year (units)	6,484,831	9,908,154
Granted (units)	1,158,547	674,971
Vested and paid out (units)	(681,841)	(791,335)
Forfeited (units)	(1,342,832)	(3,377,962)
Units in lieu of dividends (units)	113,429	71,003
Outstanding, end of year (units)	5,732,134	6,484,831

Net Income Per Common Share - S

Net Income Per Common Share - Summary of Net Income per Common Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Numerator:
Net income applicable to controlling interests	$ 552	$ 833
Less: Preferred share dividends	(66)	(68)
Gain on redemption of preferred shares (note 25)	0
Net income applicable to common shares	$ 486	$ 769
Denominator:
Weighted average number of common shares outstanding (shares)	279.4	276.9
Dilutive equity instruments (shares)	0.3	0.5
Weighted average number of common shares outstanding - diluted (shares)	279.7	277.4
Basic net income (loss) per common share (per share)	$ 1.74	$ 2.78
Diluted net income (loss) per common share (per share)	$ 1.74	$ 2.77
Anti-dilutive share options excluded from diluted income per share (shares)	7	4.3

Other Income - Schedule of Othe

Other Income - Schedule of Other Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Other Income and Expenses [Abstract]
Gain (loss) on disposition of assets	$ 223	$ 876
Gain on re-measurement of previously held interest	22	0
Other components of net benefit cost (note 28)	52	27
Interest income and other revenue	9	9
Losses on investments	0	(4)
Total other income	$ 306	$ 908

Pension Plans and Retiree Ben_3

Pension Plans and Retiree Benefits - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)divisionageplan	Dec. 31, 2019CAD ($)
Defined Benefit Plan Disclosure
Defined contribution plan cost recorded | $	$ 21	$ 20
Rabbi trust | $	$ 28	$ 57
Minimum
Defined Benefit Plan Disclosure
Plan assets investment objective period	3 years
Assumed initial healthcare cost trend rate	2.20%
Ultimate trend rate	2.20%
Maximum
Defined Benefit Plan Disclosure
Plan assets investment objective period	5 years
Assumed initial healthcare cost trend rate	6.00%
Ultimate trend rate	4.50%
Fixed income | SEMCO
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	33.00%
Fixed income | Minimum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	50.00%
Fixed income | Maximum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	70.00%
CANADA | Minimum
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	45.00%
CANADA | Maximum
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	55.00%
Defined Benefit
Defined Benefit Plan Disclosure
Number of divisions | division	5
Defined Benefit | CANADA
Defined Benefit Plan Disclosure
Number of pension plans	1
Defined Benefit | CANADA | Fully funded
Defined Benefit Plan Disclosure
Number of divisions | division	3
Defined Benefit | Foreign Plan
Defined Benefit Plan Disclosure
Number of pension plans	6
Defined Benefit | Foreign Plan | Partially funded
Defined Benefit Plan Disclosure
Number of pension plans	1
Post-Retirement Benefits | CANADA
Defined Benefit Plan Disclosure
Number of pension plans	1
Post-Retirement Benefits | Foreign Plan
Defined Benefit Plan Disclosure
Number of pension plans	4
Medical benefit eligibility age | age	65
Post-Retirement Benefits | Foreign Plan | Fixed income | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	20.00%

Pension Plans and Retiree Ben_4

Pension Plans and Retiree Benefits - Summary of Defined Benefit Plans (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Plan assets
Plan assets, Fair value, end of year	$ 2,699
Foreign Plan
Plan assets
Plan assets, Fair value, end of year	2,683
Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1,761	$ 1,669
Actuarial loss (gain)	138	184
Current service cost	30	27
Member contributions	0	0
Interest cost	61	69
Benefits paid	(86)	(81)
Expenses paid	(1)	(1)
Settlements	(25)	(24)
Other		0
Foreign exchange translation	(41)	(82)
Balance, end of year	1,837	1,761
Plan assets
Fair value, beginning of year	1,519	1,368
Actual return on plan assets	276	285
Employer contributions	41	43
Member contributions	0	0
Benefits paid	(86)	(81)
Expenses paid	(1)	(1)
Settlements	(25)	(25)
Foreign exchange translation	(41)	(70)
Plan assets, Fair value, end of year	1,683	1,519
Funded status	(154)	(242)
Defined Benefit | CANADA
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	36	34
Actuarial loss (gain)	1	2
Current service cost	3	3
Member contributions	0	0
Interest cost	1	1
Benefits paid	(4)	(4)
Expenses paid	0	0
Settlements	0	0
Other		0
Foreign exchange translation	0	0
Balance, end of year	37	36
Plan assets
Fair value, beginning of year	15	14
Actual return on plan assets	1	1
Employer contributions	4	4
Member contributions	0	0
Benefits paid	(4)	(4)
Expenses paid	0	0
Settlements	0	0
Foreign exchange translation	0	0
Plan assets, Fair value, end of year	16	15
Funded status	(21)	(21)
Defined Benefit | Foreign Plan
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1,725	1,635
Actuarial loss (gain)	137	182
Current service cost	27	24
Member contributions	0	0
Interest cost	60	68
Benefits paid	(82)	(77)
Expenses paid	(1)	(1)
Settlements	(25)	(24)
Other		0
Foreign exchange translation	(41)	(82)
Balance, end of year	1,800	1,725
Plan assets
Fair value, beginning of year	1,504	1,354
Actual return on plan assets	275	284
Employer contributions	37	39
Member contributions	0	0
Benefits paid	(82)	(77)
Expenses paid	(1)	(1)
Settlements	(25)	(25)
Foreign exchange translation	(41)	(70)
Plan assets, Fair value, end of year	1,667	1,504
Funded status	(133)	(221)
Post-Retirement Benefits
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	430	460
Actuarial loss (gain)	32	(15)
Current service cost	9	9
Member contributions	2	2
Interest cost	15	19
Benefits paid	(24)	(24)
Expenses paid	0	0
Settlements	0	0
Other		1
Foreign exchange translation	(10)	(22)
Balance, end of year	454	430
Plan assets
Fair value, beginning of year	906	791
Actual return on plan assets	157	177
Employer contributions	0	0
Member contributions	2	2
Benefits paid	(24)	(23)
Expenses paid	0	0
Settlements	0	0
Foreign exchange translation	(25)	(41)
Plan assets, Fair value, end of year	1,016	906
Funded status	562	476
Post-Retirement Benefits | CANADA
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	2	2
Actuarial loss (gain)	0	0
Current service cost	0	0
Member contributions	0	0
Interest cost	0	0
Benefits paid	0	0
Expenses paid	0	0
Settlements	0	0
Other		0
Foreign exchange translation	0	0
Balance, end of year	2	2
Plan assets
Fair value, beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	0	0
Member contributions	0	0
Benefits paid	0	0
Expenses paid	0	0
Settlements	0	0
Foreign exchange translation	0	0
Plan assets, Fair value, end of year	0	0
Funded status	(2)	(2)
Post-Retirement Benefits | Foreign Plan
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	428	458
Actuarial loss (gain)	32	(15)
Current service cost	9	9
Member contributions	2	2
Interest cost	15	19
Benefits paid	(24)	(24)
Expenses paid	0	0
Settlements	0	0
Other		1
Foreign exchange translation	(10)	(22)
Balance, end of year	452	428
Plan assets
Fair value, beginning of year	906	791
Actual return on plan assets	157	177
Employer contributions	0	0
Member contributions	2	2
Benefits paid	(24)	(23)
Expenses paid	0	0
Settlements	0	0
Foreign exchange translation	(25)	(41)
Plan assets, Fair value, end of year	1,016	906
Funded status	$ 564	$ 478

Pension Plans and Retiree Ben_5

Pension Plans and Retiree Benefits - Schedule of Amount Included in the Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	$ 572	$ 487
Accounts payable and accrued liabilities (a)	(9)	(26)
Future employee obligations	(155)	(227)
Total amounts included in Consolidated Balance Sheets	408	234
Defined Benefit
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	0	0
Accounts payable and accrued liabilities (a)	(9)	(26)
Future employee obligations	(145)	(216)
Total amounts included in Consolidated Balance Sheets	(154)	(242)
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	572	487
Accounts payable and accrued liabilities (a)	0	0
Future employee obligations	(10)	(11)
Total amounts included in Consolidated Balance Sheets	$ 562	$ 476

Pension Plans and Retiree Ben_6

Pension Plans and Retiree Benefits - Schedule of Funded Status Based on Accumulated Benefit Obligation (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
CANADA
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ (36)	$ (35)
Foreign Plan
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ (1,704)	$ (1,616)

Pension Plans and Retiree Ben_7

Pension Plans and Retiree Benefits - Schedule of Benefit Obligation in Excess of Plan Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit
Defined Benefit Plan Disclosure
Projected benefit obligation	$ 1,824	$ 1,757
Plan assets	1,670	1,515
Accumulated benefit obligation	427	1,648
Plan assets	329	1,515
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Projected benefit obligation	14	13
Plan assets	3	3
Accumulated benefit obligation	14	13
Plan assets	$ 3	$ 3

Pension Plans and Retiree Ben_8

Pension Plans and Retiree Benefits - Summary of Amounts Recorded in Other Comprehensive Income (Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit
Defined Benefit Plan Disclosure
Past service cost	$ 0
Net actuarial gain (loss)	(3)	$ (24)
Recognized in AOCI pre-tax	(3)	(24)
Increase (decrease) by the amount included in deferred tax liabilities	0	9
Net amount in AOCI after-tax	(3)	(15)
Defined Benefit | CANADA
Defined Benefit Plan Disclosure
Past service cost	0
Net actuarial gain (loss)	(9)	(9)
Recognized in AOCI pre-tax	(9)	(9)
Increase (decrease) by the amount included in deferred tax liabilities	2	2
Net amount in AOCI after-tax	(7)	(7)
Defined Benefit | Foreign Plan
Defined Benefit Plan Disclosure
Past service cost	0
Net actuarial gain (loss)	6	(15)
Recognized in AOCI pre-tax	6	(15)
Increase (decrease) by the amount included in deferred tax liabilities	(2)	7
Net amount in AOCI after-tax	4	(8)
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost	(3)
Net actuarial gain (loss)	(9)	18
Recognized in AOCI pre-tax	(12)	18
Increase (decrease) by the amount included in deferred tax liabilities	3	(9)
Net amount in AOCI after-tax	(9)	9
Post-Retirement Benefits | CANADA
Defined Benefit Plan Disclosure
Past service cost	0
Net actuarial gain (loss)	(1)	0
Recognized in AOCI pre-tax	(1)	0
Increase (decrease) by the amount included in deferred tax liabilities	0	0
Net amount in AOCI after-tax	(1)	0
Post-Retirement Benefits | Foreign Plan
Defined Benefit Plan Disclosure
Past service cost	(3)
Net actuarial gain (loss)	(8)	18
Recognized in AOCI pre-tax	(11)	18
Increase (decrease) by the amount included in deferred tax liabilities	3	(9)
Net amount in AOCI after-tax	$ (8)	$ 9

Pension Plans and Retiree Ben_9

Pension Plans and Retiree Benefits - Summary of Amounts Recorded in A Regulatory Asset (Liability) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit
Defined Benefit Plan Disclosure
Past service credit	$ 0	$ 1
Net actuarial loss (gain)	68	127
Recognized in regulatory asset (liability)	68	128
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit	(94)	(105)
Net actuarial loss (gain)	(241)	(156)
Recognized in regulatory asset (liability)	(335)	(261)
CANADA | Defined Benefit
Defined Benefit Plan Disclosure
Past service credit	0	0
Net actuarial loss (gain)	0	0
Recognized in regulatory asset (liability)	0	0
CANADA | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit	0	0
Net actuarial loss (gain)	0	0
Recognized in regulatory asset (liability)	0	0
Foreign Plan | Defined Benefit
Defined Benefit Plan Disclosure
Past service credit	0	1
Net actuarial loss (gain)	68	127
Recognized in regulatory asset (liability)	68	128
Foreign Plan | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit	(94)	(105)
Net actuarial loss (gain)	(241)	(156)
Recognized in regulatory asset (liability)	$ (335)	$ (261)

Pension Plans and Retiree Be_10

Pension Plans and Retiree Benefits - Schedule of Net Periodic Benefit Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	$ 30	$ 27
Interest cost	61	69
Expected return on plan assets	(82)	(76)
Amortization of past service cost (credit)	0	0
Amortization of net actuarial loss	11	13
Plan settlements	7	4
Other		0
Net benefit cost (income) recognized	27	37
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	9	9
Interest cost	15	19
Expected return on plan assets	(40)	(37)
Amortization of past service cost (credit)	(19)	(22)
Amortization of net actuarial loss	(5)	0
Plan settlements	0	0
Other		1
Net benefit cost (income) recognized	(40)	(30)
CANADA | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	3	3
Interest cost	1	1
Expected return on plan assets	(1)	(1)
Amortization of past service cost (credit)	0	0
Amortization of net actuarial loss	1	1
Plan settlements	0	0
Other		0
Net benefit cost (income) recognized	4	4
CANADA | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	0	0
Interest cost	0	0
Expected return on plan assets	0	0
Amortization of past service cost (credit)	0	0
Amortization of net actuarial loss	0	0
Plan settlements	0	0
Other		0
Net benefit cost (income) recognized	0	0
Foreign Plan | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	27	24
Interest cost	60	68
Expected return on plan assets	(81)	(75)
Amortization of past service cost (credit)	0	0
Amortization of net actuarial loss	10	12
Plan settlements	7	4
Other		0
Net benefit cost (income) recognized	23	33
Foreign Plan | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	9	9
Interest cost	15	19
Expected return on plan assets	(40)	(37)
Amortization of past service cost (credit)	(19)	(22)
Amortization of net actuarial loss	(5)	0
Plan settlements	0	0
Other		1
Net benefit cost (income) recognized	$ (40)	$ (30)

Pension Plans and Retiree Be_11

Pension Plans and Retiree Benefits - Schedule of Collective Investment Mixes for Plan Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2,705
Fair value of Plan Assets	$ 2,699
Percentage of Plan Assets	100.00%
Percentage of Plan Asset before net payable	100.00%
Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,683	$ 1,519	$ 1,368
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,016	906	791
Fixed income | SEMCO
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	33.00%
Fixed income | Minimum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	50.00%
Fixed income | Maximum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	70.00%
Commingled funds and pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 728
Percentage of Plan Asset before net payable	27.00%
Private Equity/Limited Partnership
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 56
Percentage of Plan Asset before net payable	2.00%
Pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment		$ 32
Percentage of Plan Asset before net payable		1.00%
Collective trust fund
Defined Benefit Plan Disclosure
Total fair value of plan investment		$ 476
Percentage of Plan Asset before net payable		18.00%
Net payable
Defined Benefit Plan Disclosure
Net payable	$ (6)
Percentage of Plan Assets payable	0.00%
Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,413
Percentage of Plan Assets	52.00%
Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 16
Percentage of Plan Assets	1.00%
Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 4
Percentage of Plan Assets	0.00%
Fair value | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 361
Percentage of Plan Assets	13.00%
Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,008
Percentage of Plan Assets	37.00%
Fair value | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1
Percentage of Plan Assets	0.00%
Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 23
Percentage of Plan Assets	1.00%
Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 516
Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	16
Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	4
Level 1 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	361
Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	135
Level 1 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	897
Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	873
Level 2 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 23
CANADA
Defined Benefit Plan Disclosure
Percentage of Plan Assets	100.00%
CANADA | Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 16	$ 15	14
CANADA | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 0	0	0
CANADA | Minimum
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	45.00%
CANADA | Maximum
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	55.00%
CANADA | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Percentage of Plan Assets	13.00%
CANADA | Equities | Canada
Defined Benefit Plan Disclosure
Percentage of Plan Assets	19.00%
CANADA | Equities | Foreign
Defined Benefit Plan Disclosure
Percentage of Plan Assets	25.00%
CANADA | Fixed income
Defined Benefit Plan Disclosure
Percentage of Plan Assets	38.00%
CANADA | Real estate
Defined Benefit Plan Disclosure
Percentage of Plan Assets	5.00%
CANADA | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 16
CANADA | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	2
CANADA | Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	3
CANADA | Fair value | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	4
CANADA | Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	6
CANADA | Fair value | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
CANADA | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	15
CANADA | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	2
CANADA | Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	3
CANADA | Level 1 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	4
CANADA | Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	6
CANADA | Level 1 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
CANADA | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
CANADA | Level 2 | Real estate
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
Foreign Plan
Defined Benefit Plan Disclosure
Total fair value of plan investment	2,689
Fair value of Plan Assets	$ 2,683
Percentage of Plan Assets	100.00%
Percentage of Plan Asset before net payable	100.00%
Foreign Plan | Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,667	1,504	1,354
Foreign Plan | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,016	$ 906	$ 791
Foreign Plan | Fixed income | WGL Holdings | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	20.00%
Foreign Plan | Commingled funds and pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 728
Percentage of Plan Asset before net payable	27.00%
Foreign Plan | Private Equity/Limited Partnership
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 56
Percentage of Plan Asset before net payable	2.00%
Foreign Plan | Pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 32
Percentage of Plan Asset before net payable	1.00%
Foreign Plan | Collective trust fund
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 476
Percentage of Plan Asset before net payable	18.00%
Foreign Plan | Collective trust fund | Common stock large cap
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	90.00%
Foreign Plan | Collective trust fund | Income producing property
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	7.00%
Foreign Plan | Collective trust fund | Short term money market
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	3.00%
Foreign Plan | Common stock large cap | WGL Holdings | Defined Benefit
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	50.00%
Foreign Plan | Corporate bonds | WGL Holdings | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	30.00%
Foreign Plan | Net payable
Defined Benefit Plan Disclosure
Net payable	$ (6)
Percentage of Plan Assets payable	0.00%
Foreign Plan | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,397
Percentage of Plan Assets	52.00%
Foreign Plan | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 14
Percentage of Plan Assets	1.00%
Foreign Plan | Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1
Percentage of Plan Assets	0.00%
Foreign Plan | Fair value | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 357
Percentage of Plan Assets	13.00%
Foreign Plan | Fair value | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,002
Percentage of Plan Assets	37.00%
Foreign Plan | Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 23
Percentage of Plan Assets	1.00%
Foreign Plan | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 501
Foreign Plan | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	14
Foreign Plan | Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	1
Foreign Plan | Level 1 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	357
Foreign Plan | Level 1 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	129
Foreign Plan | Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Foreign Plan | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	896
Foreign Plan | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Foreign Plan | Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Foreign Plan | Level 2 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	0
Foreign Plan | Level 2 | Fixed income
Defined Benefit Plan Disclosure
Total fair value of plan investment	873
Foreign Plan | Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 23

Pension Plans and Retiree Be_12

Pension Plans and Retiree Benefits - Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit
Significant actuarial assumptions used in measuring net benefit plan costs
Average remaining service life of active employees	10 years 2 months 12 days	9 years
Defined Benefit | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	2.30%	2.90%
Expected long-term rate of return on plan assets (percent)	5.25%	5.75%
Rate of compensation increase (percent)	2.75%	2.75%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	1.90%	2.90%
Rate of compensation increase (percent)	1.73%	2.75%
Defined Benefit | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	3.50%	4.40%
Expected long-term rate of return on plan assets (percent)	7.05%	7.15%
Rate of compensation increase (percent)	4.00%	4.10%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	2.80%	3.50%
Rate of compensation increase (percent)	3.93%	4.00%
Post-Retirement Benefits
Significant actuarial assumptions used in measuring net benefit plan costs
Rate of compensation increase (percent)	350.00%	410.00%
Average remaining service life of active employees	13 years	13 years 2 months 12 days
Significant actuarial assumptions used in measuring benefit obligations
Rate of compensation increase (percent)		3.50%
Post-Retirement Benefits | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	3.10%	3.90%
Expected long-term rate of return on plan assets (percent)	4.03%	4.66%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	2.50%	3.10%
Rate of compensation increase (percent)	2.50%
Post-Retirement Benefits | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	3.60%	4.50%
Expected long-term rate of return on plan assets (percent)	7.05%	7.15%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	2.90%	3.60%
Rate of compensation increase (percent)	3.00%

Pension Plans and Retiree Be_13

Pension Plans and Retiree Benefits - Schedule of Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Plans (Details) $ in Millions	Dec. 31, 2020CAD ($)
Defined Benefit
Defined Benefit Plan Disclosure
Expected employer contributions, 2021	$ 16
Expected benefit payments:
2021	90
2022	91
2023	88
2024	89
2025	90
2026 - 2030	466
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Expected employer contributions, 2021	0
Expected benefit payments:
2021	25
2022	22
2023	22
2024	21
2025	21
2026 - 2030	$ 110

Commitments, Guarantees, and _3

Commitments, Guarantees, and Contingencies - Summary of Future Payment Commitments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2015hour	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2016
Other Commitments
Operating leases, 2021			$ 96
Operating leases, 2022			81
Operating leases, 2023			58
Operating leases, 2024			50
Operating leases, 2025			40
Operating leases, 2026 and beyond			125
Total lease payments			450
Commitments, 2021			3,885
Commitments, 2022			3,333
Commitments, 2023			2,834
Commitments, 2024			2,645
Commitments, 2025			2,585
Commitments, 2026 and beyond			21,415
Commitments			36,697
Service agreement payable			153
Service agreement payable in five years			44
Capital projects
Other Commitments
Other commitments, 2021			20
Other commitments, 2022			1
Other commitments, 2023			1
Other commitments, 2024			1
Other commitments, 2025			1
Other commitments, 2026 and beyond			1
Other commitments			25
Environmental
Other Commitments
Other commitments, 2021			7
Other commitments, 2022			3
Other commitments, 2023			1
Other commitments, 2024			1
Other commitments, 2025			1
Other commitments, 2026 and beyond			0
Other commitments			13
Merger commitments
Other Commitments
Other commitments, 2021			5
Other commitments, 2022			2
Other commitments, 2023			2
Other commitments, 2024			2
Other commitments, 2025			1
Other commitments, 2026 and beyond			3
Other commitments			15
Cumulative expenses incurred but not yet paid				$ 12
Land Purchase Commitment
Other Commitments
Other commitments, 2021			20
Other commitments, 2022			0
Other commitments, 2023			0
Other commitments, 2024			0
Other commitments, 2025			0
Other commitments, 2026 and beyond			0
Other commitments			20
Post Acquisition Contingent Payments
Other Commitments
Other commitments, 2021			0
Other commitments, 2022			16
Other commitments, 2023			0
Other commitments, 2024			0
Other commitments, 2025			0
Other commitments, 2026 and beyond			0
Other commitments			16
Contingent payments			16
Natural Gas
Other Commitments
Purchase obligations, 2021			1,974
Purchase obligations, 2022			2,075
Purchase obligations, 2023			1,858
Purchase obligations, 2024			1,863
Purchase obligations, 2025			1,901
Purchase obligations, 2026 and beyond			17,612
Purchase obligations			27,283
Natural Gas | Merger commitments
Other Commitments
Other commitments				70
Propane
Other Commitments
Purchase obligations, 2021			407
Purchase obligations, 2022			199
Purchase obligations, 2023			161
Purchase obligations, 2024			108
Purchase obligations, 2025			83
Purchase obligations, 2026 and beyond			258
Purchase obligations			1,216
Crude Oil and Condensate Purchase
Other Commitments
Purchase obligations, 2021			184
Purchase obligations, 2022			0
Purchase obligations, 2023			0
Purchase obligations, 2024			0
Purchase obligations, 2025			0
Purchase obligations, 2026 and beyond			0
Purchase obligations			184
Electricity purchase
Other Commitments
Purchase obligations, 2021			463
Purchase obligations, 2022			287
Purchase obligations, 2023			106
Purchase obligations, 2024			29
Purchase obligations, 2025			3
Purchase obligations, 2026 and beyond			0
Purchase obligations			888
Service agreements
Other Commitments
Purchase obligations, 2021			48
Purchase obligations, 2022			32
Purchase obligations, 2023			26
Purchase obligations, 2024			27
Purchase obligations, 2025			27
Purchase obligations, 2026 and beyond			282
Purchase obligations			442
Service agreement term, (EOH/CT) | hour		124,000
Service agreement term		25 years
Service agreement payment period	12 years
Service agreements | Ridley Terminals Inc.
Other Commitments
Lease term (years)					20 years
Pipeline and storage services
Other Commitments
Purchase obligations, 2021			661
Purchase obligations, 2022			637
Purchase obligations, 2023			621
Purchase obligations, 2024			564
Purchase obligations, 2025			528
Purchase obligations, 2026 and beyond			3,134
Purchase obligations			6,145
Electricity, renewable energy credits
Other Commitments
Purchase obligations			$ 21
Leak mitigation | Merger commitments
Other Commitments
Other commitments, 2023				8
Other commitments, 2025				$ 2

Commitments, Guarantees, and _4

Commitments, Guarantees, and Contingencies - Narrative (Details) $ in Thousands	1 Months Ended
	Jan. 31, 2021USD ($)	Jun. 30, 2019USD ($)	Dec. 31, 2020CAD ($)	Dec. 18, 2020USD ($)	Dec. 31, 2019CAD ($)
Commitments, Contingencies And Guaranteed [Line Items]
Guarantee obligations			$ 0
Other long term receivables			18,000,000		$ 33,000,000
Regulatory assets			15,000,000		18,000,000
Restricted cash included in accounts receivable (note 29)			9,000,000		$ 0
Antero Contract
Commitments, Contingencies And Guaranteed [Line Items]
Damages awarded		$ 96,000
Regulatory assets			7,000,000
Restricted cash included in accounts receivable (note 29)			$ 9,000,000
Antero Contract | WGL Holdings
Commitments, Contingencies And Guaranteed [Line Items]
Adjustments to working capital		45,000
Antero Contract | Washington Gas
Commitments, Contingencies And Guaranteed [Line Items]
Damages awarded		$ 11,000
Maryland Show-Cause Order | Washington Gas
Commitments, Contingencies And Guaranteed [Line Items]
Estimated penalties				$ 750
Maryland Show-Cause Order | Washington Gas | Subsequent Event
Commitments, Contingencies And Guaranteed [Line Items]
Penalty paid	$ 750

Related Party Transactions - Su

Related Party Transactions - Summary of Related Party Amounts Included in Balance Sheets (Details) - CAD ($)	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction
Due from related parties, Accounts receivable	$ 5,000,000	$ 18,000,000
Due from related parties, Long-term investments and other assets	0	45,000,000
Due from related parties	5,000,000	63,000,000
Due to related parties, Accounts payable	3,000,000	$ 3,000,000
Petrogas | AltaGas
Related Party Transaction
Credit facility maximum borrowing capacity	100,000,000
Committed amount	$ 50,000,000

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Related Party Transactions [Abstract]
Revenue	$ 92	$ 115
Cost of sales	12	13
Operating and administrative recoveries	1	(2)
Other income	$ 3	$ 3

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Schedule of Changes in Operating Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Accounts receivable	$ 21	$ 168
Inventory	32	(2)
Other current assets	1	(85)
Regulatory assets - current	(33)	7
Accounts payable and accrued liabilities	(41)	(280)
Customer deposits	(2)	(17)
Regulatory liabilities - current	(55)	34
Risk management liabilities - current	(1)	1
Other current liabilities	4	(6)
Other operating assets and liabilities	(129)	(52)
Changes in operating assets and liabilities	$ (203)	$ (232)

Supplemental Cash Flow Inform_4

Supplemental Cash Flow Information - Changes in Non-Cash Activities and Supplemental Cash Payments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Common shares issued under DRIP	$ (6)	$ (68)
Net right-of-use assets obtained in exchange for new operating lease liabilities	(227)	(50)
Net right-of-use assets obtained in exchange for new finance lease liabilities	(6)	(5)
Capital expenditures included in accounts payable and accrued liabilities	(33)	(7)
Interest paid (net of capitalized interest)	276	352
Income taxes paid	$ 23	$ 67

Supplemental Cash Flow Inform_5

Supplemental Cash Flow Information - Reconciliation of Cash and Restricted Cash Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Cash Flow Elements [Abstract]
Cash and cash equivalents	$ 32	$ 57
Restricted cash holdings from customers - current	3	4
Restricted cash holdings from customers - non-current	2	4
Restricted cash included in prepaid expenses and other current assets	9	25
Restricted cash included in long-term investments and other assets	19	32
Restricted cash included in accounts receivable (note 29)	9	0
Cash, cash equivalents and restricted cash per consolidated statement of cash flow	$ 74	$ 122	$ 201

Segmented Information - Narrati

Segmented Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2020segment
Segment Reporting [Abstract]
Number of segments	2

Segmented Information - Reconci

Segmented Information - Reconciliation Of Segment Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues	$ 5,587	$ 5,495
Utilities
Revenues	3,817	4,044
Midstream
Revenues	1,635	1,228
Corporate/Other
Revenues	135	223
Intersegment revenue
Revenues	1	32
Intersegment revenue | Utilities
Revenues	0	0
Intersegment revenue | Midstream
Revenues	1	32
Intersegment revenue | Corporate/Other
Revenues	0	0
Operating Segments
Revenues	5,588	5,527
Operating Segments | Utilities
Revenues	3,817	4,044
Operating Segments | Midstream
Revenues	1,636	1,260
Operating Segments | Corporate/Other
Revenues	$ 135	$ 223

Segmented Information - Geograp

Segmented Information - Geographic Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues from External Customers and Long-Lived Assets
Revenues	$ 5,565	$ 5,570
Property, plant and equipment	10,888	10,125
Operating right-of-use assets	372	170
CANADA
Revenues from External Customers and Long-Lived Assets
Revenues	1,512	1,245
Property, plant and equipment	3,149	2,682
Operating right-of-use assets	293	85
United States
Revenues from External Customers and Long-Lived Assets
Revenues	4,053	4,325
Property, plant and equipment	7,739	7,443
Operating right-of-use assets	$ 79	$ 85

Segmented Information - Schedul

Segmented Information - Schedule of Segment Composition (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information
Revenues	$ 5,587	$ 5,495
Cost of sales	(3,178)	(3,227)
Operating and administrative	(1,267)	(1,299)
Accretion expenses	(5)	(5)
Depreciation and amortization	(414)	(438)
Provision on assets (note 6)	(109)	(416)
Income from equity investments	49	141
Other income (loss)	306	908
Foreign exchange gains (losses)	4	(1)
Interest expense	(274)	(346)
Income before income taxes	699	812
Net additions (reductions) to property, plant and equipment	825	(1,089)
Net additions (reductions) to intangible assets	10	37
Utilities
Segment Reporting Information
Revenues	3,817	4,044
Midstream
Segment Reporting Information
Revenues	1,635	1,228
Provision on assets (note 6)	(106)	(34)
Corporate/Other
Segment Reporting Information
Revenues	135	223
Provision on assets (note 6)		(382)
Operating Segments
Segment Reporting Information
Revenues	5,588	5,527
Operating Segments | Utilities
Segment Reporting Information
Revenues	3,817	4,044
Cost of sales	(2,156)	(2,448)
Operating and administrative	(942)	(960)
Accretion expenses	0	0
Depreciation and amortization	(295)	(276)
Provision on assets (note 6)	(1)	0
Income from equity investments	5	19
Other income (loss)	259	29
Foreign exchange gains (losses)	0	0
Interest expense	0	0
Income before income taxes	687	408
Net additions (reductions) to property, plant and equipment	740	840
Net additions (reductions) to intangible assets	3	23
Operating Segments | Midstream
Segment Reporting Information
Revenues	1,636	1,260
Cost of sales	(994)	(760)
Operating and administrative	(254)	(213)
Accretion expenses	(4)	(4)
Depreciation and amortization	(86)	(89)
Provision on assets (note 6)	(105)	(34)
Income from equity investments	44	122
Other income (loss)	24	28
Foreign exchange gains (losses)	(26)	(5)
Interest expense	0	0
Income before income taxes	235	305
Net additions (reductions) to property, plant and equipment	136	351
Net additions (reductions) to intangible assets	3	5
Operating Segments | Corporate/Other
Segment Reporting Information
Revenues	135	223
Cost of sales	(29)	(51)
Operating and administrative	(71)	(126)
Accretion expenses	(1)	(1)
Depreciation and amortization	(33)	(73)
Provision on assets (note 6)	(3)	(382)
Income from equity investments	0	0
Other income (loss)	23	851
Foreign exchange gains (losses)	30	4
Interest expense	(274)	(346)
Income before income taxes	(223)	99
Net additions (reductions) to property, plant and equipment	(51)	(2,280)
Net additions (reductions) to intangible assets	4	9
Intersegment Elimination
Segment Reporting Information
Revenues	1	32
Cost of sales	1	32
Operating and administrative	0	0
Accretion expenses	0	0
Depreciation and amortization	0	0
Provision on assets (note 6)	0	0
Income from equity investments	0	0
Other income (loss)	0	0
Foreign exchange gains (losses)	0	0
Interest expense	0	0
Income before income taxes	0	0
Net additions (reductions) to property, plant and equipment	0	0
Net additions (reductions) to intangible assets	0	0
Intersegment Elimination | Utilities
Segment Reporting Information
Revenues	0	0
Intersegment Elimination | Midstream
Segment Reporting Information
Revenues	1	32
Intersegment Elimination | Corporate/Other
Segment Reporting Information
Revenues	$ 0	$ 0

Segmented Information - Sched_2

Segmented Information - Schedule of Goodwill and Total Assets by Segment (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information
Goodwill (note 11)	$ 5,039	$ 3,942	$ 4,068
Segmented assets	21,532	19,795
Operating Segments | Utilities
Segment Reporting Information
Goodwill (note 11)	3,706	3,781
Segmented assets	13,675	13,719
Operating Segments | Midstream
Segment Reporting Information
Goodwill (note 11)	1,333	161
Segmented assets	7,320	5,265
Operating Segments | Corporate/Other
Segment Reporting Information
Goodwill (note 11)	0	0
Segmented assets	$ 537	$ 811