AltaGas (ATGFF) 40-F 2 Mar 23 2022 FY Annual report (Canada) Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2022
Document Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2022
Entity File Number	333-225606
Entity Registrant Name	ALTAGAS LTD.
Entity Incorporation, State or Country Code	Z4
Entity Primary SIC Number	1311
Entity Address, Address Line One	1700, 355-4th Avenue S.W
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Postal Zip Code	T2P 0J1, Canada
City Area Code	403
Local Phone Number	691-7575
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Central Index Key	0001695519
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.

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	Calgary, AB, Canada
Auditor Firm ID	1263

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents (note 32)	$ 53	$ 63
Accounts receivable (net of credit losses of $41 million) (notes 10 and 24)	2,091	1,427
Inventory (note 7)	1,060	782
Restricted cash holdings from customers (note 32)	0	3
Regulatory assets (note 22)	38	48
Risk management assets (note 24)	140	113
Prepaid expenses and other current assets (notes 29 and 32)	169	188
Assets held for sale (note 5)	1,087	0
Total current assets	4,638	2,624
Property, plant and equipment (note 8)	11,686	11,323
Intangible assets (note 9)	120	171
Operating right-of-use assets (note 10)	281	311
Goodwill (note 11)	5,250	5,153
Regulatory assets (note 22)	448	436
Risk management assets (note 24)	77	51
Prepaid post-retirement benefits (note 29)	538	674
Long-term investments and other assets (net of credit losses of $1 million) (notes 12, 29, and 32)	273	227
Investments accounted for by the equity method (note 14)	654	623
Total assets	23,965	21,593
Current liabilities
Accounts payable and accrued liabilities	1,902	1,544
Short-term debt (notes 15 and 24)	293	169
Current portion of long-term debt (notes 16 and 24)	334	511
Customer deposits	79	74
Regulatory liabilities (note 22)	183	79
Risk management liabilities (note 24)	172	128
Operating lease liabilities (note 10)	92	91
Other current liabilities (note 24)	57	61
Liabilities associated with assets held for sale (note 5)	295	0
Total current liabilities	3,407	2,657
Long-term debt (notes 16 and 24)	8,694	7,684
Asset retirement obligations (note 18)	451	429
Unamortized investment tax credits (note 21)	2	2
Deferred income taxes (note 21)	1,369	1,158
Subordinated hybrid notes (notes 17 and 24)	544	0
Regulatory liabilities (note 22)	1,201	1,424
Risk management liabilities (note 24)	298	165
Operating lease liabilities (note 10)	215	253
Other long-term liabilities (notes 20 and 24)	122	134
Future employee obligations (note 29)	44	86
Total liabilities	16,347	13,992
Shareholders' equity
Common shares, no par values, unlimited shares authorized;    2022 - 281.5 million and 2021 - 280.3 million issued and outstanding (note 26)	6,761	6,735
Preferred shares (note 26)	586	1,076
Contributed surplus	625	388
Accumulated deficit	(1,142)	(1,243)
Accumulated other comprehensive income (AOCI) (note 23)	626	(7)
Total shareholders' equity	7,456	6,949
Non-controlling interests	162	652
Total equity	7,618	7,601
Total liabilities and shareholders' equity	$ 23,965	$ 21,593

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Accounts receivable, allowance for credit loss, current	$ 41	$ 41
Long-term investments and other assets, credit losses	$ 1	$ 1
Common shares (note 26)
Common shares outstanding (in shares)	281,531,833	280,269,038
Common shares issued (shares)	281,500,000	280,300,000

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Statement [Abstract]
REVENUE (note 25)	$ 14,087	$ 10,573
EXPENSES
Cost of sales, exclusive of items shown separately	11,138	7,708
Operating and administrative	1,568	1,476
Accretion expenses (note 18)	7	6
Depreciation and amortization (notes 8 and 9)	439	422
Provisions on assets (note 6)	6	64
Total expenses	13,158	9,676
Income (loss) from equity investments (note 14)	13	(261)
Other income (note 28)	94	81
Foreign exchange gains	10	4
Interest expense	(330)	(275)
Income before income taxes	716	446
Income tax expense (note 21)
Current	23	59
Deferred	120	47
Net income after taxes	573	340
Net income applicable to non-controlling interests	50	57
Net income applicable to controlling interests	523	283
Preferred share dividends	(40)	(53)
Loss on redemption of preferred shares (note 26)	(84)
Net income applicable to common shares	$ 399	$ 230
Net income per common share (note 27)
Basic (in shares)	$ 1.42	$ 0.82
Diluted (in shares)	$ 1.41	$ 0.82
Weighted average number of common shares    outstanding (millions) (note 27)
Basic (in shares)	281	279.9
Diluted (in shares)	283.3	281.7

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net income after taxes	$ 573	$ 340
Other comprehensive income (loss), net of taxes
Gain (loss) on foreign currency translation	643	(61)
Unrealized loss on net investment hedge (note 24)	(15)	0
Actuarial gain on pension plans and post-retirement benefit (PRB) plans (note 29)	3	2
Reclassification of actuarial gains and prior service credits on defined benefit (DB) and post-retirement benefit plans (PRB) to net income (note 29)	0	2
Total other comprehensive income (loss) (OCI), net of taxes	631	(57)
Comprehensive income attributable to controlling interests and non-controlling interests, net of taxes	1,204	283
Comprehensive income attributable to:
Non-controlling interests	53	56
Controlling interests	$ 1,151	$ 227

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - CAD ($) $ in Millions	Total	Total shareholders' equity	Common shares (note 26)	Preferred shares (note 26)	Contributed surplus	Accumulated deficit	AOCI (note 23)	Non-controlling interests
Balance, beginning of year at Dec. 31, 2020			$ 6,723	$ 1,077	$ 383	$ (1,192)	$ 50	$ 620
Increase (Decrease) in Stockholders' Equity
Exercise of share options			15		(2)
Deferred taxes on share issuance costs			(3)	(1)
Redemption of preferred shares (note 26)				0
Share options expense					7
Net income applicable to controlling interests	$ 283					283
Common share dividends						(281)
Preferred share dividends						(53)
Loss on redemption of preferred shares (note 26)						0
Other comprehensive income (loss)	(57)						(57)
Purchase of remaining non-controlling interest in subsidiaries (note 3)							0
Net income applicable to non-controlling interests	57							57
Foreign currency translation adjustments								6
Contributions from non-controlling interests to subsidiaries								1
Distributions by subsidiaries to non-controlling interests								(32)
Purchase of remaining non-controlling interest in subsidiaries (note 3)					0
Acquisition of non-controlling interests through Petrogas Acquisition (note 3)								0
Balance, end of year at Dec. 31, 2021	7,601	$ 6,949	6,735	1,076	388	(1,243)	(7)	652
Increase (Decrease) in Stockholders' Equity
Exercise of share options			28		(3)
Deferred taxes on share issuance costs			(2)	0
Redemption of preferred shares (note 26)				(490)
Share options expense					3
Net income applicable to controlling interests	523					523
Common share dividends						(298)
Preferred share dividends						(40)
Loss on redemption of preferred shares (note 26)	(84)					(84)
Other comprehensive income (loss)	631						628
Purchase of remaining non-controlling interest in subsidiaries (note 3)							5
Net income applicable to non-controlling interests	50							50
Foreign currency translation adjustments								3
Contributions from non-controlling interests to subsidiaries								0
Distributions by subsidiaries to non-controlling interests								(21)
Acquisition of non-controlling interests through Petrogas Acquisition (note 3)								(522)
Balance, end of year at Dec. 31, 2022	$ 7,618	$ 7,456	$ 6,761	$ 586	$ 625	$ (1,142)	$ 626	$ 162

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cash from operations
Net income after taxes	$ 573	$ 340
Items not involving cash:
Depreciation and amortization (notes 8 and 9)	439	422
Provisions on assets (note 6)	6	64
Accretion expenses (note 18)	7	6
Share-based compensation (note 26)	3	7
Deferred income tax expense (note 21)	120	47
Gains on sale of assets (notes 4 and 28)	(3)	(6)
Loss (income) from equity investments (note 14)	(13)	261
Unrealized losses (gains) on risk management contracts (note 24)	49	(18)
Amortization of deferred financing costs	6	5
Allowance for credit losses	26	14
Change in pension and other post-retirement benefits (note 29)	(46)	(25)
Other	18	28
Asset retirement obligations settled (note 18)	(10)	(10)
Distributions from equity investments	14	13
Changes in operating assets and liabilities (note 32)	(650)	(410)
Net cash provided (required) by operating activities	539	738
Investing activities
Capital expenditures - property, plant and equipment	(945)	(805)
Capital expenditures - intangible assets	(13)	(9)
Distributions from (contributions to) equity investments	1
Distributions from (contributions to) equity investments		(11)
Proceeds from disposition of equity investments (note 14)	0	3
Proceeds from disposition of assets, net of transaction costs (note 4)	245	346
Purchase of remaining non-controlling interest in a subsidiary (note 3)	(285)	0
Other changes in investing activities	0	(7)
Net cash provided (required) by investing activities	(997)	(483)
Financing activities
Net issuance (repayment) of short-term debt	128
Net issuance (repayment) of short-term debt		(78)
Issuance of long-term debt, net of debt issuance costs	718	446
Repayment of long-term debt	(513)	(11)
Net borrowing (repayment) under credit facilities	466	(229)
Issuance of subordinated hybrid notes (note 17)	544	0
Dividends - common shares	(298)	(303)
Dividends - preferred shares	(40)	(53)
Distributions to non-controlling interest	(21)	(32)
Contributions from non-controlling interests	0	1
Net proceeds from shares issued on exercise of options	25	14
Redemption of preferred shares (note 26)	(574)	0
Net cash provided (required) by financing activities	435	(245)
Change in cash, cash equivalents, and restricted cash	(23)	10
Effect of exchange rate changes on cash, cash equivalents, and restricted cash	4	0
Net change in cash classified within assets held for sale	(1)	0
Cash, cash equivalents, and restricted cash beginning of year	84	74
Cash, cash equivalents, and restricted cash end of year (note 32)	$ 64	$ 84

Organization and Overview of th

Organization and Overview of the Business	12 Months Ended
	Dec. 31, 2022
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 Corp., 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); and 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, AltaGas Pacific Partnership, AltaGas LPG Limited Partnership, Petrogas Energy Corporation (Petrogas), Petrogas Holdings Partnership, and Petrogas, Inc. In the Corporate/Other segment, subsidiaries include 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). Prior to the close of the Alaska Utilities Disposition, it operated 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). AltaGas is a leading energy infrastructure company that connects natural gas and NGLs to domestic and global markets. The Company operates a diversified, lower-risk, high-growth energy infrastructure business that is focused on delivering resilient and durable value for its stakeholders. AltaGas' operating segments include the following: § Utilities, which owns and operates franchised, cost-of-service, rate regulated natural gas distribution and storage utilities focused on providing safe, reliable, and affordable energy to its customers. Prior to the sale of ENSTAR and AltaGas' interest in Cook Inlet Natural Gas Storage Alaska (CINGSA) on March 1, 2023 (the Alaska Utilities Disposition), AltaGas' Utilities provided energy to approximately 1.7 million residential and commercial customers in 2022 and had an average 2022 rate base of approximately US$5.2 billion. 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 sells natural gas and electricity directly to residential, commercial, and industrial customers located in Maryland, Virginia, Delaware, Pennsylvania, Ohio, and the District of Columbia; and § Midstream, which is a leading North American platform that connects customers and markets from wellhead to tidewater and beyond. The three pillars of the Midstream business include: 1) global exports, which includes AltaGas' two LPG export terminals; 2) natural gas gathering and extraction; and 3) fractionation and liquids handling. AltaGas' Midstream segment also includes its natural gas and NGL marketing business, domestic logistics, trucking and rail terminals, and liquid storage capability. The Corporate/Other segment consists of AltaGas' corporate activities and a small portfolio of gas-fired power generation and distribution assets capable of generating 508 MW of power primarily in the state of California.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
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 February 22, 2021, 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 required to file reports under section 15(d) of the Securities Exchange Act of 1934 with the United States Securities and Exchange Commission. In addition, AltaGas sought and obtained exemptive relief by the securities regulators in Alberta and Ontario to permit it to prepare its financial statements in accordance with U.S. GAAP. The Alberta Securities Commission exemption will terminate on or after the earlier of January 1, 2024, the date to which AltaGas ceases to have activities subject to rate regulation, or the effective date prescribed by the International Accounting Standards Board for the mandatory application of a standard within the International Financial Reporting Standard for entities with activities subject to rate‑regulated accounting. This exemptive relieve would apply should AltaGas cease to become an SEC issuer. 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 AltaGas' investment in Mountain Valley Pipeline (MVP) This methodology is used 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. 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, Washington Gas, Hampshire Gas, and, prior to the Alaska Utilities Disposition, ENSTAR (collectively the Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas is regulated by the Michigan Public Service Commission (MPSC). 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, 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, 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. Accounts Receivable Receivables 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 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. 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 1 to 43 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 Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 7 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 HDDs falls above or below the contractual HDDs 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 24 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 outstanding loans to hedge against the currency translation effect of its foreign investments. 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 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 recognized using a 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 25. 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 certain outstanding loans to hedge against the currency translation effect of its foreign investments. Accordingly, foreign exchange gains and losses, from the dates of designation, on the translation of these loans 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) for eligible employees, officers, and directors, which includes two types of awards: restricted units (RUs) and performance units (PUs). 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. All PUs are also subject to a performance multiplier ranging from 0 to 2 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. Forfeitures are recognized when they occur instead of estimating the number of awards that are expected to vest. In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers, and eligible employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers, and eligible 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. Forfeitures are recognized when they occur instead of estimating the number of awards that are expected to vest. 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. 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 believ

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2022
Business Combinations [Abstract]
Acquisitions	Acquisitions On July 5, 2022, AltaGas acquired the remaining 25.97 percent equity ownership of Petrogas from Idemitsu Canada Corporation, a wholly owned subsidiary of Idemitsu Kosan Co., Ltd. (Idemitsu) for total cash consideration of approximately $285 million. Subsequent to this transaction, AltaGas now owns 100 percent of Petrogas. Due to the acquisition of the remaining equity ownership, AltaGas' accumulated other comprehensive income increased by $5 million and contributed surplus increased by $237 million.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2022
Discontinued Operations and Disposal Groups [Abstract]
Dispositions	Dispositions Energy Storage Development Project In the first quarter of 2022, AltaGas completed the sale of a 60 MW stand-alone energy storage development project in Goleta, California for total proceeds of approximately $20 million (US$15 million), subject to certain contingencies. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $7 million in the Consolidated Statements of Income under the line item "other income" for the year ended December 31, 2022. In February 2023, the parties reached an agreement on outstanding contingencies and as a result, the buyer paid AltaGas an additional US$8 million. Midstream Processing Facilities On April 12, 2022, AltaGas completed the sale of its interest in the Aitken Creek processing facilities for total proceeds of approximately $224 million, net of closing adjustments. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $1 million in the Consolidated Statements of Income under the line item "other income" for the year ended December 31, 2022. Brush II As at December 31, 2022 December 31, 2021 Assets held for sale Accounts receivable (net of credit losses of $1 million) (note 24) $ 93 $ — Inventory 86 — Restricted cash holdings from customers 1 — Prepaid expenses and other current assets 6 — Property, plant and equipment 646 — Intangible assets 5 — Operating right-of-use assets 1 — Goodwill 226 — Regulatory assets - non-current 14 — Post retirement benefits 8 — Long-term investments and other assets 1 — $ 1,087 $ — Liabilities associated with assets held for sale Accounts payable and accrued liabilities $ 59 $ — Current portion of long-term debt 7 — Customer deposits 13 — Long-term debt 56 — Asset retirement obligations 4 — Regulatory liabilities - non-current 96 — Operating lease liabilities - non-current 1 — Other long-term liabilities 53 — Future employee obligations 6 — $ 295 $ — Alaskan Utilities On May 26, 2022, AltaGas entered into an agreement for the Alaska Utilities Disposition for consideration of approximately US$800 million (approximately CAD $1.1 billion) prior to closing adjustments. As such, the carrying value of the assets and liabilities related to this business were classified as held for sale at December 31, 2022, which resulted in the reclassification of $1,087 million of assets to assets held for sale and $295 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. The transaction closed on March 1, 2023. Refer to Note 34 for additional details.

Assets Held For Sale

Assets Held For Sale	12 Months Ended
	Dec. 31, 2022
Discontinued Operations and Disposal Groups [Abstract]
Assets Held For Sale	Dispositions Energy Storage Development Project In the first quarter of 2022, AltaGas completed the sale of a 60 MW stand-alone energy storage development project in Goleta, California for total proceeds of approximately $20 million (US$15 million), subject to certain contingencies. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $7 million in the Consolidated Statements of Income under the line item "other income" for the year ended December 31, 2022. In February 2023, the parties reached an agreement on outstanding contingencies and as a result, the buyer paid AltaGas an additional US$8 million. Midstream Processing Facilities On April 12, 2022, AltaGas completed the sale of its interest in the Aitken Creek processing facilities for total proceeds of approximately $224 million, net of closing adjustments. As a result, AltaGas recognized a pre-tax gain on disposition of approximately $1 million in the Consolidated Statements of Income under the line item "other income" for the year ended December 31, 2022. Brush II As at December 31, 2022 December 31, 2021 Assets held for sale Accounts receivable (net of credit losses of $1 million) (note 24) $ 93 $ — Inventory 86 — Restricted cash holdings from customers 1 — Prepaid expenses and other current assets 6 — Property, plant and equipment 646 — Intangible assets 5 — Operating right-of-use assets 1 — Goodwill 226 — Regulatory assets - non-current 14 — Post retirement benefits 8 — Long-term investments and other assets 1 — $ 1,087 $ — Liabilities associated with assets held for sale Accounts payable and accrued liabilities $ 59 $ — Current portion of long-term debt 7 — Customer deposits 13 — Long-term debt 56 — Asset retirement obligations 4 — Regulatory liabilities - non-current 96 — Operating lease liabilities - non-current 1 — Other long-term liabilities 53 — Future employee obligations 6 — $ 295 $ — Alaskan Utilities On May 26, 2022, AltaGas entered into an agreement for the Alaska Utilities Disposition for consideration of approximately US$800 million (approximately CAD $1.1 billion) prior to closing adjustments. As such, the carrying value of the assets and liabilities related to this business were classified as held for sale at December 31, 2022, which resulted in the reclassification of $1,087 million of assets to assets held for sale and $295 million of liabilities to liabilities associated with assets held for sale on the Consolidated Balance Sheets. The transaction closed on March 1, 2023. Refer to Note 34 for additional details.

Provisions on Assets

Provisions on Assets	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Provisions on Assets	Provisions on Assets Year Ended December 31 2022 2021 Midstream $ 6 $ 59 Corporate/Other — 5 $ 6 $ 64 Midstream In 2022, AltaGas recorded a pre-tax provision of $6 million related to the Alton Natural Gas Storage Project as a result of updated reclamation cost estimates. Since AltaGas has abandoned this project, the resulting property, plant and equipment associated with the estimated reclamation costs was impaired. The pre-tax provisions were primarily recorded against property, plant and equipment. In 2021, AltaGas recorded pre-tax provisions of $59 million primarily related to the sale of the U.S. transportation and storage business as well as certain non-core development stage Midstream projects that are no longer being developed. The pre-tax provisions were primarily recorded against intangible assets. Corporate/Other

Inventory

Inventory	12 Months Ended
	Dec. 31, 2022
Inventory Disclosure [Abstract]
Inventory	Inventory As at December 31 2022 2021 Natural gas held in storage (a) (b) $ 588 $ 341 Natural gas liquids 197 175 Materials and supplies 76 70 Renewable energy credits and emission compliance instruments 127 82 Crude oil and condensate 152 109 Processed finished products 6 5 $ 1,146 $ 782 Less: inventory reclassified to assets held for sale (note 5) (c) (86) — $ 1,060 $ 782 (a) As at December 31, 2022, $520 million of the natural gas held in storage was held by rate-regulated utilities (2021 - $304 million). (b) In 2022, a write-down of $5 million was recorded relating to the revaluation of the Company's natural gas storage inventory in the Midstream business to its net realizable value. (c) Pursuant to the May 26, 2022 announcement of the sale of the Alaska Utilities Disposition, $72 million of the natural gas held in storage that was held by rate-regulated utilities was reclassified to "assets held for sale" on the Consolidated Balance Sheets at December 31, 2022. The transaction closed on March 1, 2023. Refer to Notes 5 and 34 for more details.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment As at December 31, 2022 December 31, 2021 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value Utilities $ 9,806 $ (614) $ 9,192 $ 8,432 $ (437) $ 7,995 Midstream 3,810 (884) 2,926 3,898 (793) 3,105 Corporate/Other 879 (665) 214 840 (617) 223 Reclassified to assets held for sale ( note 5) (1,124) 478 (646) — — — $ 13,371 $ (1,685) $ 11,686 $ 13,170 $ (1,847) $ 11,323 Interest capitalized on long-term capital construction projects for the year ended December 31, 2022 was less than $1 million (2021 - $1 million). As at December 31, 2022, the Corporation had approximately $571 million (December 31, 2021 - $570 million) of capital projects under construction that were not yet subject to amortization. Depreciation expense related to property, plant and equipment (including assets under capital leases) for the year ended December 31, 2022 was $375 million

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets	Intangible Assets As at December 31, 2022 December 31, 2021 Cost Accumulated Net book Cost Accumulated Net book E&T contracts $ 26 $ (18) $ 8 $ 26 $ (17) $ 9 Energy services relationships 96 (86) 10 90 (63) 27 Software 359 (255) 104 331 (203) 128 Land rights 1 — 1 1 — 1 Commodity contracts 8 (6) 2 7 (1) 6 Reclassified to assets held for sale (note 5) (30) 25 (5) — — $ — $ 460 $ (340) $ 120 $ 455 $ (284) $ 171 Amortization expense related to intangible assets for the year ended December 31, 2022 was $64 million (2021 - $57 million). As at December 31, 2022, the Corporation excluded $6 million (December 31, 2021 - $7 million) from the asset base subject to amortization. Items excluded relate to 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: 2023 $ 46 2024 $ 33 2025 $ 29 2026 $ 1 2027 $ 1 Thereafter $ 4

Leases

Leases	12 Months Ended
	Dec. 31, 2022
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) $ 100 $ 96 Finance lease cost Amortization of right-of-use assets 7 6 Interest on lease liabilities 1 — Total finance lease cost $ 8 $ 6 Total lease cost $ 108 $ 102 Supplemental cash flow information related to leases was as follows: Year Ended December 31 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows used by operating leases $ (111) $ (96) Financing cash flows used by finance leases (a) $ (8) $ (6) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 56 $ 38 Finance leases $ 14 $ 10 (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 2022 2021 Operating Leases Operating lease right-of-use assets Long-term $ 281 $ 311 Included in assets held for sale (note 5) 1 — Total operating lease right-of-use assets $ 282 $ 311 Operating lease liabilities Current $ (92) $ (91) Long-term (215) (253) Included in liabilities associated with assets held for sale (note 5) (1) — Total operating lease liabilities $ (308) $ (344) Finance Leases Property and equipment, gross $ 46 $ 29 Accumulated depreciation (21) (12) Total property and equipment, net $ 25 $ 17 Less: finance lease property and equipment reclassified to assets held for sale (note 5) (3) — Property and equipment, net $ 22 $ 17 Current portion of long-term debt $ (8) $ (6) Long-term debt (17) (11) Total finance lease liabilities $ (25) $ (17) Less: finance lease liabilities reclassified to liabilities associated with assets held for sale (note 5) 3 — Finance lease liabilities $ (22) $ (17) As at December 31, December 31, Weighted average remaining lease term (years) Operating leases 6.4 6.9 Finance leases 4.5 4.3 Weighted average discount rate (%) Operating leases 2.91 2.45 Finance leases 3.29 2.23 Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2023 $ 95 $ 8 2024 65 7 2025 50 5 2026 41 4 2027 25 2 Thereafter 73 2 Total lease payments $ 349 $ 28 Less: imputed interest (41) (3) Total $ 308 $ 25 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 2023 $ 73 2024 2 2025 2 2026 2 2027 1 Thereafter 76 Total $ 156 The carrying value of property, plant, and equipment associated with these leases was approximately $203 million as at December 31, 2022.
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) $ 100 $ 96 Finance lease cost Amortization of right-of-use assets 7 6 Interest on lease liabilities 1 — Total finance lease cost $ 8 $ 6 Total lease cost $ 108 $ 102 Supplemental cash flow information related to leases was as follows: Year Ended December 31 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows used by operating leases $ (111) $ (96) Financing cash flows used by finance leases (a) $ (8) $ (6) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 56 $ 38 Finance leases $ 14 $ 10 (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 2022 2021 Operating Leases Operating lease right-of-use assets Long-term $ 281 $ 311 Included in assets held for sale (note 5) 1 — Total operating lease right-of-use assets $ 282 $ 311 Operating lease liabilities Current $ (92) $ (91) Long-term (215) (253) Included in liabilities associated with assets held for sale (note 5) (1) — Total operating lease liabilities $ (308) $ (344) Finance Leases Property and equipment, gross $ 46 $ 29 Accumulated depreciation (21) (12) Total property and equipment, net $ 25 $ 17 Less: finance lease property and equipment reclassified to assets held for sale (note 5) (3) — Property and equipment, net $ 22 $ 17 Current portion of long-term debt $ (8) $ (6) Long-term debt (17) (11) Total finance lease liabilities $ (25) $ (17) Less: finance lease liabilities reclassified to liabilities associated with assets held for sale (note 5) 3 — Finance lease liabilities $ (22) $ (17) As at December 31, December 31, Weighted average remaining lease term (years) Operating leases 6.4 6.9 Finance leases 4.5 4.3 Weighted average discount rate (%) Operating leases 2.91 2.45 Finance leases 3.29 2.23 Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2023 $ 95 $ 8 2024 65 7 2025 50 5 2026 41 4 2027 25 2 Thereafter 73 2 Total lease payments $ 349 $ 28 Less: imputed interest (41) (3) Total $ 308 $ 25 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 2023 $ 73 2024 2 2025 2 2026 2 2027 1 Thereafter 76 Total $ 156 The carrying value of property, plant, and equipment associated with these leases was approximately $203 million as at December 31, 2022.
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) $ 100 $ 96 Finance lease cost Amortization of right-of-use assets 7 6 Interest on lease liabilities 1 — Total finance lease cost $ 8 $ 6 Total lease cost $ 108 $ 102 Supplemental cash flow information related to leases was as follows: Year Ended December 31 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows used by operating leases $ (111) $ (96) Financing cash flows used by finance leases (a) $ (8) $ (6) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 56 $ 38 Finance leases $ 14 $ 10 (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 2022 2021 Operating Leases Operating lease right-of-use assets Long-term $ 281 $ 311 Included in assets held for sale (note 5) 1 — Total operating lease right-of-use assets $ 282 $ 311 Operating lease liabilities Current $ (92) $ (91) Long-term (215) (253) Included in liabilities associated with assets held for sale (note 5) (1) — Total operating lease liabilities $ (308) $ (344) Finance Leases Property and equipment, gross $ 46 $ 29 Accumulated depreciation (21) (12) Total property and equipment, net $ 25 $ 17 Less: finance lease property and equipment reclassified to assets held for sale (note 5) (3) — Property and equipment, net $ 22 $ 17 Current portion of long-term debt $ (8) $ (6) Long-term debt (17) (11) Total finance lease liabilities $ (25) $ (17) Less: finance lease liabilities reclassified to liabilities associated with assets held for sale (note 5) 3 — Finance lease liabilities $ (22) $ (17) As at December 31, December 31, Weighted average remaining lease term (years) Operating leases 6.4 6.9 Finance leases 4.5 4.3 Weighted average discount rate (%) Operating leases 2.91 2.45 Finance leases 3.29 2.23 Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2023 $ 95 $ 8 2024 65 7 2025 50 5 2026 41 4 2027 25 2 Thereafter 73 2 Total lease payments $ 349 $ 28 Less: imputed interest (41) (3) Total $ 308 $ 25 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 2023 $ 73 2024 2 2025 2 2026 2 2027 1 Thereafter 76 Total $ 156 The carrying value of property, plant, and equipment associated with these leases was approximately $203 million as at December 31, 2022.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill As at December 31, December 31, Balance, beginning of year $ 5,153 $ 5,039 Adjustment to goodwill on business acquisition — 147 Goodwill included in dispositions — (13) Reclassified to assets held for sale (note 5) (226) — Foreign exchange translation 323 (20) Balance, end of year $ 5,250 $ 5,153

Long-Term Investments and Other

Long-Term Investments and Other Assets	12 Months Ended
	Dec. 31, 2022
Investments, All Other Investments [Abstract]
Long-Term Investments and Other Assets	Long-Term Investments and Other Assets As at December 31, December 31, Deferred lease receivable $ 17 $ 15 Debt issuance costs associated with credit facilities 7 8 Refundable deposits 10 9 Prepayment on long-term service agreements 79 72 Deferred information technology costs 24 6 Cash calls from joint venture partners 21 23 Contract asset (net of credit losses of $1 million) (notes 24 and 25) 37 41 Rabbi trust (notes 29 and 32) 8 10 Capitalized contract costs 5 5 Financial transmission rights 39 17 Other 27 21 $ 274 $ 227 Less: long-term investments and other assets reclassified to assets held for sale (note 5) (1) — $ 273 $ 227

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2022
VARIABLE INTEREST ENTITIES [Abstract]
Variable Interest Entities	Variable Interest Entities Consolidated VIEs AltaGas consolidates a variable interest entity (VIE) 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, 2022 December 31, 2021 Current assets $ 12 $ 6 Property, plant and equipment 353 357 Long-term investments and other assets 45 47 Current liabilities (16) (8) Asset retirement obligations (4) (3) Net assets $ 390 $ 399 AltaGas Hybrid Trust On January 11, 2022, AltaGas closed its offering of $300 million of 5.25 percent Fixed-to-Fixed Rate Subordinated Notes, Series 1 (Note 17). In conjunction with the debt offering, AltaGas issued $300 million in Preferred Shares, Series 2022-A, to be held in the AltaGas Hybrid Trust with Computershare Trust Company of Canada acting as trustee. The Preferred Shares were issued to satisfy the obligations under the indenture governing the associated Series 1 Subordinated Notes. Following the occurrence of certain bankruptcy or insolvency events in respect of AltaGas, subject to certain exceptions, the Series 2022-A Preferred Shares would be delivered to the holders of the Series 1 Subordinated Notes. Upon delivery of the Series 2022-A Preferred Shares, the Series 1 Subordinated Notes would be immediately and automatically surrendered and cancelled and all rights of any Series 1 Subordinated Notes will automatically cease. On August 17, 2022, AltaGas closed its offering of $250 million of 7.35 percent Fixed-to-Fixed Subordinated Notes, Series 2 (Note 17). In conjunction with the debt offering, AltaGas issued $250 million in Preferred Shares, Series 2022-B, to be held in the AltaGas Hybrid Trust with Computershare Trust Company of Canada acting as trustee. The Preferred Shares were issued to satisfy the obligations under the indenture governing the associated Series 2 Subordinated Notes. Following the occurrence of certain bankruptcy or insolvency events in respect of AltaGas, subject to certain exceptions, the Series 2022-B Preferred Shares would be delivered to the holders of the Series 2 Subordinated Notes. Upon delivery of the Series 2022-B Preferred Shares, the Series 2 Subordinated Notes would be immediately and automatically surrendered and cancelled and all rights of any Series 2 Subordinated Notes will automatically cease. The only assets held by the holding trust are the Series 2022-A and Series 2022-B Preferred Shares. AltaGas has determined that AltaGas Hybrid Trust 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 its role as the sole administrative agent. In addition, AltaGas has the obligation to absorb the administrative expenses that are significant to the trust through the associated administrative agreement. As such, AltaGas has consolidated the AltaGas Hybrid Trust. 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, Alberta. The facility currently has five underground NGL storage salt caverns. Construction of the fifth cavern was completed in the third quarter of 2022 and is currently storing customer product. On July 5, 2022, AltaGas acquired the remaining 25.97 percent equity ownership in Petrogas which resulted in an increase in AltaGas' ownership in SSLP from 30 percent to 40 percent. As at December 31, 2022, AltaGas' carrying value in SSLP was $130 million (2021 - $131 million). SSLP is not consolidated by AltaGas and instead is accounted for by the equity method of accounting. AltaGas is not the primary beneficiary of SSLP and it does not have the power to direct the activities most significant to the economic performance of SSLP. The maximum financial exposure to loss as a result of the involvement with this VIE is equal to AltaGas' net investment in SSLP.

Investments Accounted for by th

Investments Accounted for by the Equity Method	12 Months Ended
	Dec. 31, 2022
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 2022 2021 2022 2021 Constitution Pipeline, LLC (Constitution) (a) United States 10 $ — $ — $ 3 $ — Eaton Rapids Gas Storage System United States 50 28 27 3 2 Mountain Valley Pipeline, LLC (MVP) (b) United States 10 478 447 — (271) Sarnia Airport Storage Pool LP Canada 50 17 17 1 1 Petrogas Terminals Penn LLC (c) United States 50 1 1 — — Strathcona Storage LP (c) Canada 40 130 131 6 7 $ 654 $ 623 $ 13 $ (261) (a) In the third quarter of 2022, AltaGas received a payment for the return of certain costs associated with the Constitution pipeline project as a result of its cancellation in February 2020. (b) The equity method is considered appropriate because MVP is an LLC with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream (now WGL Sustainable Energy LLC) exercising a more than minor influence over the investee's operating and financing policies. In 2021, a provision was recorded against the equity investment in MVP due to ongoing legal and regulatory issues. Management has continued to assess the equity investment in MVP for further impairment and determined that no further provisions were required in 2022. (c) On July 5, 2022, AltaGas acquired the remaining 25.97 percent equity ownership of Petrogas which resulted in an increase in AltaGas' ownership in Petrogas Terminals Penn LLC from 37 percent to 50 percent and in Strathcona Storage LP from 30 percent to 40 percent. Refer to Note 3 for more details. 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 MVP. Summarized combined financial information, assuming a 100 percent ownership interest in AltaGas’ equity investments listed above, is as follows: Year Ended December 31 2022 2021 Revenues $ 50 $ 97 Expenses (26) (23) $ 24 $ 74 As at December 31 2022 2021 Current assets $ 136 $ 206 Property, plant and equipment $ 9,544 $ 8,571 Long-term investments and other assets $ 12 $ 3 Current liabilities $ (166) $ (214) Other long-term liabilities $ (14) $ (12)

Short-term Debt

Short-term Debt	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Short-term Debt	Short-term Debt As at (a) December 31, December 31, Commercial paper $ 293 $ 161 Project financing — 8 $ 293 $ 169 (a) As at December 31, 2022, AltaGas' weighted average interest rate on short-term borrowings outstanding was 4.8 percent (December 31, 202 1 - 0.3 percent ). Credit Facilities As at December 31, 2022, AltaGas held a $70 million (December 31, 2021 - $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. As at December 31, 2022, there were no letters of credit outstanding under this facility (December 31, 2021 - $34 million). As at December 31, 2022, AltaGas held a US$300 million (December 31, 2021 - US$200 million) unsecured bilateral letter of credit demand facility, amended in July 2022, 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, 2022 were $181 million (December 31, 2021 - $139 million). As at December 31, 2021, AltaGas held a US$125 million demand letter of credit facility. Letters of credit outstanding under this facility as at December 31, 2021 were $99 million. The facility was terminated in November 2022. 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, 2022, commercial paper outstanding classified as short-term debt totaled $293 million (December 31, 2021 - $161 million). As at December 31, 2022, Petrogas held a $30 million (December 31, 2021 - $30 million) unsecured bilateral letter of credit demand facility. Letters of credit outstanding under this facility as at December 31, 2022 were $16 million (December 31, 2021 - $7 million). As at December 31, 2022, Petrogas held an unsecured bilateral letter of credit demand facility of $25 million (December 31, 2021 - $25 million). As at December 31, 2022, there were no letters of credit outstanding under this facility (December 31, 2021 - $nil).

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt As at Maturity date December 31, December 31, Credit facilities $2 billion unsecured extendible revolving facility (a) 20-May-2027 $ 860 $ 375 US$150 million unsecured extendible revolving facility 20-Dec-2026 188 120 Commercial paper (b) Various 386 469 $450 million term loan 25-Aug-2024 450 — AltaGas Ltd. medium-term notes (MTNs) $500 million Senior unsecured - 2.61 percent 16-Dec-2022 — 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 $350 million Senior unsecured - 1.23 percent 18-Mar-2024 350 350 $300 million Senior unsecured - 3.84 percent 15-Jan-2025 300 300 $500 million Senior unsecured - 2.16 percent 10-Jun-2025 500 500 $350 million Senior unsecured - 4.12 percent 7-Apr-2026 350 350 $200 million Senior unsecured - 2.17 percent 16-Mar-2027 200 200 $200 million Senior unsecured - 3.98 percent 4-Oct-2027 200 200 $500 million Senior unsecured - 2.08 percent 30-May-2028 500 500 $200 million Senior unsecured - 2.48 percent 30-Nov-2030 200 200 $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 and private placement notes US$20 million Senior unsecured - 6.65 percent 20-Mar-2023 27 25 US$41 million Senior unsecured - 5.44 percent 11-Aug-2025 55 51 US$53 million Senior unsecured - 6.62 to 6.82 percent Oct 2026 72 67 US$72 million Senior unsecured - 6.40 to 6.57 percent Feb - Sep 2027 98 91 US$52 million Senior unsecured - 6.57 to 6.85 percent Jan - Mar 2028 70 66 US$9 million Senior unsecured - 7.50 percent 1-Apr-2030 12 11 US$50 million Senior unsecured - 5.70 to 5.78 percent Jan - Mar 2036 68 63 US$75 million Senior unsecured - 5.21 percent 3-Dec-2040 102 95 US$75 million Senior unsecured - 5.00 percent 15-Dec-2043 102 95 US$300 million Senior unsecured - 4.22 to 4.60 percent Sep - Nov 2044 405 380 US$450 million Senior unsecured - 3.80 percent 15-Sep-2046 608 572 US$400 million Senior unsecured - 3.65 percent (c) 15-Sep-2049 563 528 US$200 million Senior unsecured - 2.98 percent 15-Dec-2051 271 254 US$25 million Senior unsecured - 5.25 percent 29-Dec-2042 34 — US$175 million Senior unsecured - 5.33 percent 29-Dec-2052 237 — SEMCO long-term debt US$82 million CINGSA Senior secured - 4.48 percent (d) 2-Mar-2032 60 63 US$225 million First Mortgage Bonds - 2.45 percent 21-Apr-2030 305 285 US$225 million First Mortgage Bonds - 3.15 percent 21-Apr-2050 305 285 Fair value adjustment on WGL acquisition 79 77 Finance lease liabilities (note 10) 25 17 $ 9,132 $ 8,239 Less: debt issuance costs (41) (44) $ 9,091 $ 8,195 Less: current portion (334) (511) Less: liabilities associated with assets held for sale (note 5) (e) (63) — $ 8,694 $ 7,684 (a) Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, SOFR 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. During the fourth quarter of 2022, AltaGas completed an amendment of the Petrogas $200 million Revolving Credit Facility in which AltaGas has replaced Petrogas as the borrower, which is in addition to the AltaGas $2 billion five-year extendable committed revolving tranche, and the $300 million two-year extendable side car liquidity revolving facility. (b) Commercial paper is supported by the availability of long-term committed credit facilities maturing in 2024. Commercial paper intended to be repaid within the next year is recorded as short-term debt (Note 15). (c) The outstanding balance includes a US$15 million premium which will be amortized as a reduction to interest expense over the term of the note. (d) 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. (e) Pursuant to the May 26, 2022 announcement of the Alaska Utilities Disposition, related long-term debt balances totaling $63 million, including the CINGSA Senior secured loan net of issuance costs as well as certain finance lease liabilities, were reclassified to "liabilities associated with assets held for sale" on the Consolidated Balance Sheets at December 31, 2022. The transaction closed on March 1, 2023. Refer to Notes 5 and 34 for more details. Credit Facilities During the fourth quarter of 2022, AltaGas closed an amendment on the Petrogas $200 million unsecured extendible revolving credit facility in which AltaGas has replaced Petrogas as the borrower. As at December 31, 2022, AltaGas held $2.5 billion (December 31, 2021 - $2.3 billion) of unsecured revolving credit facilities. These facilities include a $2 billion five-year extendable committed revolving tranche, a $300 million two-year extendable side car revolving tranche, and a $200 million three-year revolving credit facility (previously at Petrogas). Draws on the facilities can be by way of prime loans, U.S. base-rate loans, SOFR loans, bankers' acceptances, or letters of credit. Outstanding bank loans under this facility as at December 31, 2022 were $860 million (December 31, 2021 - $375 million). As at December 31, 2022, AltaGas held a $450 million unsecured two-year term credit facility which was initiated on August 25, 2022. Draws on the facility can be by way of prime loans, U.S. base-rate loans, SOFR loans, bankers' acceptances, or letters of credit. Outstanding bank loans under this facility as at December 31, 2022 were $450 million. As at December 31, 2022, WGL held a US$300 million (December 31, 2021 - 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, bankers’ acceptances, or letters of credit. There were no outstanding bank loans under this facility as at December 31, 2022 or December 31, 2021. As at December 31, 2022, Washington Gas held a US$450 million (December 31, 2021 - 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, 2022 or December 31, 2021. 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, 2022, outstanding commercial paper classified as long-term debt totaled $386 million (December 31, 2021 - $469 million). As at December 31, 2022, SEMCO held a US$150 million (December 31, 2021 - US$150 million) unsecured extendible revolving facility. Draws on the facility can be by way of letters of credit, Alternate Base Rate or Eurodollar loans. There were US$140 million outstanding bank loans under this facility as at December 31, 2022 (December 31, 2021 - US$95 million). As at December 31, 2021, Petrogas held a $25 million swingline facility. There were no outstanding bank loans under this facility as at December 31, 2021. The facility was terminated in December 2022.

Subordinated Hybrid Notes

Subordinated Hybrid Notes	12 Months Ended
	Dec. 31, 2022
Restructuring and Related Activities [Abstract]
Subordinated Hybrid Notes	Subordinated Hybrid Notes As at Maturity date December 31, December 31, $300 million subordinated notes, Series 1 11-Jan-2082 $ 300 $ — $250 million subordinated notes, Series 2 17-Aug-2082 250 — $ 550 $ — Less: debt issuance costs (6) — $ 544 $ — On January 11, 2022, AltaGas closed its offering of $300 million of 5.25 percent Fixed-to-Fixed Rate Subordinated Notes, Series 1, due January 11, 2082. The subordinated notes were offered under AltaGas' short form base shelf prospectus dated February 22, 2021, as supplemented by a prospectus supplement dated January 5, 2022. On August 17, 2022, AltaGas closed its offering of $250 million of 7.35 percent Fixed-to-Fixed Rate Subordinated Notes, Series 2, due August 17, 2082. The subordinated notes were offered under AltaGas' short form base shelf prospectus dated February 22, 2021, as supplemented by a prospectus supplement dated August 4, 2022.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations As at December 31 2022 2021 Balance, beginning of year $ 429 $ 379 Obligations acquired — 5 New obligations 3 4 Obligations settled (a) (10) (10) Disposals (1) — Revision in estimated cash flow (2) 40 Accretion expense (b) 20 19 Foreign exchange translation 23 (1) Reclassified to liabilities associated with assets held for sale (note 5) (4) — Total $ 458 $ 436 Less: current portion (included in accounts payable and accrued liabilities) (7) (7) Balance, end of year $ 451 $ 429 (a) During the year ended December 31, 2022, approximately $7 million of asset retirement obligations included in accounts payable and accrued liabilities were settled (December 31, 2021 - $7 million). (b) 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, 2022 was $877 million (December 31, 2021 - $892 million). The asset retirement obligations have been recorded in the Consolidated Financial Statements at estimated values discounted at rates between 2.0 and 8.4 percent (December 31, 2021 - between 2.0 to 8.5 percent) and are expected to be incurred

Environmental Matters

Environmental Matters	12 Months Ended
	Dec. 31, 2022
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, 2022, a liability of $13 million has been recorded on an undiscounted basis related to future environmental response costs (December 31, 2021 - $18 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, 2022, AltaGas estimated the maximum liability associated with all of its sites to be approximately $50 million (December 31, 2021 - $50 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, 2022, AltaGas reported a regulatory asset of $15 million (December 31, 2021 - $16 million) for the portion of environmental response costs that are expected to be recoverable in future rates (Note 22).

Other Long-term Liabilities

Other Long-term Liabilities	12 Months Ended
	Dec. 31, 2022
Other Liabilities Disclosure [Abstract]
Other Long-term Liabilities	Other Long-term Liabilities As at December 31, December 31, Deferred revenue $ 11 $ 13 Customer advances for construction 69 59 Merger commitments 5 7 Non-retirement employee benefits (a) 51 19 Uncertain tax positions (note 21) 20 20 Other 19 16 $ 175 $ 134 Less: liabilities associated with assets held for sale (note 5) (53) — $ 122 $ 134 (a) Consists of long-term portion of liabilities relating to employee incentive plans and other non-retirement related employee benefits.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Year Ended December 31 2022 2021 Income before income taxes - consolidated $ 716 $ 446 Statutory income tax rate (%) 23.0 23.0 Expected taxes at statutory rates $ 165 $ 103 Add (deduct) the tax effect of: Permanent differences $ 2 $ 3 Statutory and other rate differences 1 25 Deferred income tax recovery on regulated assets (21) (18) Tax differences on divestitures and transactions (3) (4) Other (1) (3) $ 143 $ 106 Income tax provision Current $ 23 $ 59 Deferred 120 47 $ 143 $ 106 Effective income tax rate (%) 20.0 23.8 Net deferred income tax liabilities were composed of the following: As at December 31, December 31, PP&E and intangible assets $ 1,862 $ 1,709 Regulatory assets (187) (233) Tax pools, deferred financing, and compensation (238) (236) Other (69) (84) Valuation allowance 1 2 $ 1,369 $ 1,158 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. As at December 31, 2022, the Corporation had tax-effected non-capital losses of approximately $338 million, which will be available to offset future taxable income. If not used, these losses will expire between 2027 and 2042. 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 2021 remain subject to examination by taxation authorities. In the United States, both the federal and state tax returns for the years 2018 to 2021 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 2022 2021 Balance, beginning of year $ 20 $ 21 Settlement — (1) Balance, end of year $ 20 $ 20

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2022
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, 2022 and 2021, over which the Corporation expects to realize or settle the assets or liabilities: As at December 31 2022 2021 Recovery Regulatory assets - current Deferred cost of gas (a) $ 15 $ 20 Less than one year Accelerated replacement recovery mechanisms (b) 11 7 Less than one year Energy optimization costs 4 5 Less than one year Virginia and Maryland revenue normalization (c) 8 16 Less than one year $ 38 $ 48 Regulatory assets - non-current Deferred regulatory costs (c) (d) $ 254 $ 199 1 - 53 years Future recovery of pension and other retirement benefits (c) 1 33 2 - 20 years Future recovery of non-retirement employee benefits (c) (e) 16 19 Various Deferred environmental costs (c) (f) 15 16 Various Deferred loss on debt transactions and derivative instruments (c) (g) 91 89 Various Deferred future income taxes (c) (h) 42 43 Various Energy efficiency program - Maryland (i) 31 23 Various COVID-19 costs (j) 4 6 Various Other 8 8 Various $ 462 $ 436 Less: non-current regulatory assets reclassified to assets held for sale (note 5) (14) — $ 448 $ 436 Regulatory liabilities - current Deferred cost of gas (a) $ 164 $ 71 Less than one year Refundable tax credit — 2 n/a Federal income tax rate change (k) 1 1 Less than one year Virginia rate refund (m) 5 — Less than one year Interruptible sharing (c) 3 4 Less than one year Virginia and Maryland revenue normalization (a) 2 — Less than one year Virginia Coronavirus Relief Fund (n) — 1 n/a Other 8 — Less than one year $ 183 $ 79 Regulatory liabilities - non-current Future expense of pension and other retirement benefits (c) $ 235 $ 425 Various Future removal and site restoration costs (l) 490 453 Various Deferred gain on debt transactions and derivative instruments (c) (g) 1 1 Various Federal income tax rate change (k) 568 543 Various Other 3 2 Various $ 1,297 $ 1,424 Less: non-current regulatory liabilities associated with assets held for sale (note 5) (96) — $ 1,201 $ 1,424 (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) Washington Gas is not entitled to a rate of return on these assets. (d) Includes deferred gas costs and fair value of derivatives, which are not included in customer bills until settled. (e) 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. (f) This balance represents allowed environmental remediation expenditures at SEMCO and Washington Gas sites to be recovered through rates. (g) 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, 2022, this also includes a fair value adjustment of $74 million (December 31, 2021 - $72 million) recorded on the WGL Acquisition in 2018. (h) 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. (i) Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland. (j) Regulatory assets established to capture and track incremental COVID-19 related costs. (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) This amount and timing of draw down is dependent upon the cost of removal of the underlying utility property, plant and equipment and its useful life. (m) This amount represents estimated refunds related to customers billed at a higher rate during the interim period as part of the 2022 Virginia rate case. (n) The Virginia Coronavirus Relief Fund was received by WGL to provide direct assistance to Virginia customers with balances over 60 days in arrears.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2022
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) ($ millions) Defined benefit pension and PRB plans Hedge net investments Translation foreign operations Total Opening balance, January 1, 2022 $ (8) $ (158) $ 159 $ (7) OCI before reclassification 4 (17) 640 627 Current period OCI (pre-tax) $ 4 $ (17) $ 640 $ 627 Income tax on amounts retained in AOCI (1) 2 — 1 Net current period OCI $ 3 $ (15) $ 640 $ 628 Purchase of remaining non-controlling interest in subsidiaries (note 3) — — 5 5 Ending balance, December 31, 2022 $ (5) $ (173) $ 804 $ 626 Opening balance, January 1, 2021 $ (12) $ (158) $ 220 $ 50 OCI before reclassification 3 — (61) (58) Amounts reclassified from OCI 3 — — 3 Current period OCI (pre-tax) $ 6 $ — $ (61) $ (55) Income tax on amounts retained in AOCI (1) — — (1) Income tax on amounts reclassified to earnings (1) — — (1) Net current period OCI $ 4 $ — $ (61) $ (57) Ending balance, December 31, 2021 $ (8) $ (158) $ 159 $ (7) Reclassification From Accumulated Other Comprehensive Income AOCI components reclassified Income statement line item Year Ended December 31, 2022 Year Ended Defined benefit pension and PRB plans Other income $ — $ 3 Deferred income taxes Income tax expense – deferred — (1) $ — $ 2

Financial Instruments and Finan

Financial Instruments and Financial Risk Management	12 Months Ended
	Dec. 31, 2022
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 crude 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. 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 (including debt classified as held for sale), Subordinated hybrid notes, 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, NGL, and crude 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. 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, 2022 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income (a) Risk management assets - current $ 132 $ — $ 96 $ 36 $ 132 Risk management assets - non-current 77 — 52 25 77 Fair value through regulatory assets (a) Risk management assets - current 8 — 6 2 8 217 $ — $ 154 $ 63 $ 217 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 133 $ — $ 11 $ 122 $ 133 Risk management liabilities - non-current 170 — 4 166 170 Fair value through regulatory liabilities (a) Risk management liabilities - current 39 — — 39 39 Risk management liabilities - non-current 128 — — 128 128 Amortized cost Current portion of long-term debt 334 — 334 — 334 Long-term debt 8,694 — 7,721 — 7,721 Subordinated hybrid notes 544 — 480 — 480 Debt classified as held for sale (note 5) 63 — 60 — 60 Other current liabilities (b) 52 — 52 — 52 $ 10,157 $ — $ 8,662 $ 455 $ 9,117 (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, 2021 Carrying Level 1 Level 2 Level 3 Total Financial assets Fair value through net income (a) Risk management assets - current $ 112 $ — $ 73 $ 39 $ 112 Risk management assets - non-current 50 — 22 28 50 Fair value through regulatory assets (a) Risk management assets - current 1 — — 1 1 Risk management assets - non-current 1 — — 1 1 $ 164 $ — $ 95 $ 69 $ 164 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 113 $ — $ 58 $ 55 $ 113 Risk management liabilities - non-current 90 — 11 79 90 Fair value through regulatory liabilities (a) Risk management liabilities - current 15 — — 15 15 Risk management liabilities - non-current 75 — — 75 75 Amortized cost Current portion of long-term debt 511 — 511 — 511 Long-term debt 7,684 — 7,898 — 7,898 Other current liabilities (b) 43 — 43 — 43 $ 8,531 $ — $ 8,521 $ 224 $ 8,745 (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. Financial assets and liabilities not included in the fair value hierarchy table include money market funds, short term debt, and commercial paper. 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, 2022: Net Fair Value Valuation Technique Unobservable Inputs Range Weighted Average (a) Natural gas $ (222) Discounted Cash Flow Natural Gas Basis Price (per Dth) $ (2.59) - $ 14.00 $ (0.50) Natural gas $ (4) Option Model Natural Gas Basis Price (per Dth) $ (2.06) - $ 7.30 $ 0.73 Annualized Volatility of Spot Market Natural Gas 22 % - 292 % 91 % Electricity $ (166) Discounted Cash Flow Electricity Congestion Price (per MWh) $ (10.86) - $ 185.54 $ 23.20 (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 2022 2021 Natural Electricity Total Natural Electricity Total Balance, beginning of year $ (107) $ (48) $ (155) $ (74) $ (19) $ (93) Net realized and unrealized losses: Recorded in income (43) (213) (256) (15) (25) (40) Recorded in regulatory assets (100) — (100) (28) — (28) Transfers out of Level 3 2 (30) (28) (1) — (1) Purchases — 16 16 — 4 4 Settlements 35 118 153 14 (8) 6 Foreign exchange translation (13) (9) (22) (3) — (3) Balance, end of year $ (226) $ (166) $ (392) $ (107) $ (48) $ (155) 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, 2022 were due to an increase in valuations using observable market inputs. Realized and Unrealized Gains (Losses) Recorded to Income for Level 3 Measurements Year Ended December 31 2022 2021 Recorded to revenue $ (258) $ (79) Recorded to cost of sales 2 39 $ (256) $ (40) Summary of Unrealized Gains (Losses) on Risk Management Contracts Recognized in Net Income Year Ended December 31 2022 2021 Natural gas $ (57) $ 6 Energy exports 21 38 Crude oil and NGLs 2 1 NGL frac spread 16 (13) Power (31) 9 Foreign exchange — (23) $ (49) $ 18 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, 2022 Gross amounts of recognized Gross amounts Netting Net amounts Risk management assets (a) Natural gas $ 174 $ (80) $ (17) $ 77 Energy exports 105 (112) 34 27 Crude oil and NGLs 6 (4) 2 4 NGL frac spread 6 (6) — — Power 153 (44) — 109 $ 444 $ (246) $ 19 $ 217 Risk management liabilities (b) Natural gas $ 360 $ (80) $ — $ 280 Energy exports 112 (112) — — Crude oil and NGLs 4 (4) — — NGL frac spread 9 (6) — 3 Power 231 (44) — 187 $ 716 $ (246) $ — $ 470 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $140 million and risk management assets (non‑current) balance of $77 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $172 million and risk management liabilities (non‑current) balance of $298 million. As at December 31, 2021 Gross amounts of Gross amounts Netting Net amounts Risk management assets (a) Natural gas $ 94 $ (22) $ (25) $ 47 Energy exports 61 (60) 37 38 NGL frac spread 4 — — 4 Power 101 (25) (1) 75 $ 260 $ (107) $ 11 $ 164 Risk management liabilities (b) Natural gas $ 164 $ (22) $ (4) $ 138 Energy exports 81 (60) 2 23 Crude oil and NGLs 6 — 2 8 NGL frac spread 23 — — 23 Power 126 (25) — 101 $ 400 $ (107) $ — $ 293 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $113 million and risk management assets (non‑current) balance of $51 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $128 million and risk management liabilities (non‑current) balance of $165 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 $ 2 $ 9 Cash collateral held representing an obligation $ 4 $ 2 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, 2022 and December 31, 2021, AltaGas has not posted any 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 $ 145 $ 42 Maximum potential collateral requirements $ 68 $ 21 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 2033. 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, 2022 and 2021: December 31, 2022 Fixed price Period Notional volume (GJ) Fair Value ($ millions) Sales 1.75 to 20.38 1-130 244,060,786 $ (54) Purchases (a) 1.75 to 20.38 1-98 521,045,852 $ (169) Swaps 3.28 to 17.02 1-57 147,565,012 $ 20 December 31, 2021 Fixed price Period Notional volume (GJ) Fair Value ($ millions) Sales 1.75 to 10.8 1-142 259,750,059 $ (8) Purchases 1.75 to 10.8 1-143 606,923,548 $ (102) Swaps 2.95 to 7.42 1-55 201,266,412 $ 19 (a) Excludes approximately 191,071,366 GJ of natural gas purchases through 2033 that are contingent on the in-service date of the Mountain Valley Pipeline. Crude Oil and NGLs In the normal course of business, AltaGas utilizes financial swaps to manage the impact of timing between when product is purchased and sold in addition to differing indices on purchase and sales. December 31, 2022 Fixed price Period Notional volume (Bbl) Fair Value ($ millions) Swaps 44.19 to 120.45 1-12 1,597,173 $ 4 December 31, 2021 Fixed price Period Notional volume (Bbl) Fair Value ($ millions) Swaps 41.18 to 97.12 1-12 864,000 $ (8) 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, 2022: December 31, 2022 Fixed price Period Notional volume Fair Value ($ millions) Purchases 9.45 1-3 90,646 Less than $1 million Propane and butane swaps 4.8 to 118.69 1-12 89,433,941 $ 27 December 31, 2021 Fixed price Period Notional volume Fair Value ($ millions) Propane and butane swaps 5.2 to 115.54 1-15 38,860,780 $ 15 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, 2022 and 2021: December 31, 2022 Fixed price Period Notional volume Fair Value ($ millions) Propane swaps 48.94 to 50.79/Bbl 1-12 1,075,194 Bbl $ 5 Crude oil swaps 108.65 to 113.88/Bbl 1-12 214,255 Bbl $ 1 Natural gas swaps 4.5 to 4.98/GJ 1-12 6,139,191 GJ $ (9) December 31, 2021 Fixed price Period Notional volume Fair Value ($ millions) Propane swaps 33.14 to 59.75/Bbl 1-12 2,099,243 Bbl $ (15) Butane swaps 36.19 to 36.20/Bbl 1-3 18,967 Bbl $ (1) Crude oil swaps 63.25 to 89.86/Bbl 1-12 369,495 Bbl $ (4) Natural gas swaps 2.54 to 3.89/GJ 1-12 11,873,390 GJ $ 1 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 2026. As at December 31, 2022, 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, 2022 and 2021: December 31, 2022 Fixed price Period Notional volume Fair Value ($ millions) Power sales 37.18 to 167.07 1-42 5,276,832 $ (96) Power purchases 37.18 to 167.07 1-42 6,341,582 $ 99 Swap purchases (10.86) to 185.54 1-41 23,888,348 $ (81) December 31, 2021 Fixed price Period Notional volume Fair Value ($ millions) Power sales 27.19 to 93.94 1-42 4,938,045 $ (60) Power purchases 27.19 to 93.94 1-53 6,393,003 $ 69 Swap purchases (8.13) to 86.84 1-41 22,845,569 $ (35) 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, 2022: Factor Increase or decrease to forward prices Increase or decrease to income before tax ($ millions) PJM power price US$1/MWh 43 NYMEX natural gas price US$0.50/GJ 30 Energy Exports: Propane Far East Index to domestic supply $1/Bbl (3) Baltic LPG Freight $1/Bbl 12 NGL frac spread: Propane $1/Bbl (1) Natural gas $0.50/GJ 3 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 external U.S. dollar-denominated debt or certain U.S. dollar-denominated loans that may give rise to a foreign currency transaction gain or loss as a net investment hedge of its U.S. subsidiaries. As at December 31, 2022, AltaGas has designated US$281 million of outstanding loans as a net investment hedge (December 31, 2021 - US$122 million). For the year ended December 31, 2022, a $15 million after-tax unrealized loss on the net investment hedge was recorded in OCI (2021 ‑ $nil). As at December 31, 2022, AltaGas did not have any outstanding foreign exchange forward contracts. The following foreign exchange forward contracts were outstanding as at December 31, 2021: Foreign exchange forward contract Notional Amount (US$ millions) Duration Weighted average foreign exchange rate Fair Value Foreign exchange swaps (purchases) US$10 Less than one year 1.2640 Less than $1 million For the year ended December 31, 2022, AltaGas recorded an after-tax realized gain of less than $1 million on all foreign exchange forward contracts (2021 - after-tax realized gain of $19 million). 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, 2022, approximately 78 percent of AltaGas’ total outstanding short-term and long-term debt was at fixed rates (December 31, 2021 - 87 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, 2022. 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, 2022, 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, 2022, a pre-tax loss of less than $1 million was recorded related to these instruments (2021 - pre-tax loss of less than $1 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 receivable (AR) as at December 31, 2022: As at December 31, 2022 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 2,067 $ 1,078 $ 41 $ 751 $ 87 $ 26 $ 84 Other 65 — — 65 — — — Allowance for credit losses (41) — (41) — — — $ 2,091 $ 1,078 $ — $ 816 $ 87 $ 26 $ 84 As at December 31, 2021 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 1,431 $ 560 $ 39 $ 703 $ 52 $ 24 $ 53 Other 35 — — 35 — — — Allowance for credit losses (39) — (39) — — — — $ 1,427 $ 560 $ — $ 738 $ 52 $ 24 $ 53 The following table provides a summary of changes to the allowance for credit losses by segment and major type: Year Ended December 31, 2022 Accounts Receivable Contract Assets (a) Total Utilities Balance, beginning of period $ 38 $ — $ 38 Foreign exchange translation 2 — $ 2 Adjustments to allowance (b) 26 — 26 Written off (29) — (29) Recoveries collected 4 — 4 Reclassified to assets held for sale (note 5) (1) — (1) Balance, end of period $ 40 $ — $ 40 Midstream Balance, beginning of period $ 1 $ 1 $ 2 Adjustments to allowance — — — Balance, end of period $ 1 $ 1 $ 2 Total $ 41 $ 1 $ 42 (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 $2 million recorded to a regulatory asset relating to the impact of COVID-19 on uncollectible accounts. Year Ended December 31, 2021 Accounts Receivable Contract Assets (a) Other long-term investments and other assets (b) Total Utilities Balance, beginning of period $ 40 $ — $ — $ 40 Adjustments to allowance (b) 15 — — 15 Written off (22) — — (22) Recoveries collected 5 — — 5 Balance, end of period $ 38 $ — $ — $ 38 Midstream Balance, beginning of period $ 1 $ 1 $ 2 $ 4 New allowance — — (2) (2) Balance, end of period $ 1 $ 1 $ — $ 2 Total $ 39 $ 1 $ — $ 40 (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 $5 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, 2022 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,902 $ 1,902 $ — $ — $ — Short-term debt 293 293 — — — Other current liabilities (a) 52 52 — — — Risk management contract liabilities 470 172 183 57 58 Current portion of long-term debt (b) 327 327 — — — Long-term debt (b) 8,641 — 2,241 1,968 4,432 Debt classified as held for sale (60) (7) (12) (12) (29) Subordinated hybrid notes 550 — — — 550 $ 12,175 $ 2,739 $ 2,412 $ 2,013 $ 5,011 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, the fair value adjustment on the WGL Acquisition, and debt classified as held for sale. Contractual maturities by period As at December 31, 2021 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,544 $ 1,544 $ — $ — $ — Short-term debt 169 169 — — — Other current liabilities (a) 43 43 — — — Risk management contract liabilities 293 128 85 25 55 Current portion of long-term debt (b) 506 506 — — — Long-term debt (b) 7,639 — 1,356 1,775 4,508 $ 10,194 $ 2,390 $ 1,441 $ 1,800 $ 4,563 (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, 2022
Revenue from Contract with Customer [Abstract]
Revenue	Revenue The following tables disaggregate revenue by major sources for the year: Year Ended December 31, 2022 Utilities Midstream Corporate/Other Total Revenue from contracts with customers Commodity sales contracts $ 1,715 $ 6,260 $ — $ 7,975 Midstream service contracts — 2,411 — 2,411 Gas sales and transportation services 3,179 — — 3,179 Storage services 24 — — 24 Other 9 — 1 10 Total revenue from contracts with customers $ 4,927 $ 8,671 $ 1 $ 13,599 Other sources of revenue Revenue from alternative revenue programs (a) $ 94 $ — $ — $ 94 Leasing revenue (b) — 232 99 331 Risk management and trading activities (c) (28) 76 (3) 45 Other (13) 31 — 18 Total revenue from other sources $ 53 $ 339 $ 96 $ 488 Total revenue $ 4,980 $ 9,010 $ 97 $ 14,087 (a) 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. (b) 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. (c) 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. Year Ended December 31, 2021 Utilities Midstream Corporate/Other Total Revenue from contracts with customers Commodity sales contracts $ 1,316 $ 4,667 $ 1 $ 5,984 Midstream service contracts — 1,664 — 1,664 Gas sales and transportation services 2,582 — — 2,582 Storage services 24 — — 24 Other 8 — 4 12 Total revenue from contracts with customers $ 3,930 $ 6,331 $ 5 $ 10,266 Other sources of revenue Revenue from alternative revenue programs (a) $ 92 $ — $ — $ 92 Leasing revenue (b) — 168 102 270 Risk management and trading activities (c) (d) (74) 12 (4) (66) Other (12) 22 1 11 Total revenue from other sources $ 6 $ 202 $ 99 $ 307 Total revenue $ 3,936 $ 6,533 $ 104 $ 10,573 (a) 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. (b) 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. (c) 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. (d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. Prior to the sale of the U.S. transportation and storage business in the second quarter of 2021, WGL Midstream entered 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 of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2021 of $172 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. While the GAIL contract and AMA are individually not accounted for as derivatives, they are inseparable from the overall trading portfolio. 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 had 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. AltaGas completed the sale of the U.S. transportation and storage business, including the GAIL contract and the AMA, in April 2021. 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 states where WGL Energy Services is authorized as a competitive service provider. These commodity sales contracts have varying terms that generally range from one to five years. Customers are billed monthly based on the amount of gas delivered to the customer. Revenue is recognized based on the amount the Corporation is entitled to invoice the customer. 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. AltaGas' 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. 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. Contract Balances As at December 31, 2022, a contract asset of $41 million (December 31, 2021 - $54 million) has been recorded on the Consolidated balance Sheets, of which $38 million ($37 million net of credit losses) is included within long-term investments and other assets (December 31, 2021 – $41 million net of credit losses) and $4 million within prepaid expenses and other current assets (December 31, 2021 - $13 million). This contract asset represents the difference in revenue recognized under a new rate in a blend-and-extend modification with a customer. Revenue from this contract modification was recognized at a pre-modification rate until December 31, 2020, with the excess revenue recorded as a contract asset. The contract asset is now being drawn down over the remaining term of the modified contract. At December 31, 2022, contract liabilities of $ nil (December 31, 2021 - $1 million) have been recorded within other current liabilities on the Consolidated Balance Sheets. 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 $ 54 $ 71 Additions 1 — Amortization (a) (4) (4) Transfers to accounts receivable (b) (10) (13) Balance, end of year $ 41 $ 54 (a) Represents the drawdown of a contract asset under a blend-and-extend contract modification. (b) Amounts included in contract assets are transferred to accounts receivable when AltaGas’ right to consideration becomes unconditional. Contract Liabilities As at December 31, December 31, Balance, beginning of year $ 1 $ — Additions — 1 Revenue recognized from contract liabilities (a) (1) — Balance, end of year $ — $ 1 (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, 2022: 2023 2024 2025 2026 2027 2028 & beyond Total Midstream service contracts $ 120 $ 120 $ 116 $ 113 $ 112 $ 784 $ 1,365 Storage services 25 25 25 25 25 106 231 Other 2 2 2 2 2 5 15 $ 147 $ 147 $ 143 $ 140 $ 139 $ 895 $ 1,611

Shareholders_ Equity

Shareholders’ Equity	12 Months Ended
	Dec. 31, 2022
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. Common Shares Issued and Outstanding (a) Number of Amount January 1, 2021 279,494,299 $ 6,723 Shares issued for cash on exercise of options 774,739 15 Deferred taxes on share issuance cost — (3) December 31, 2021 280,269,038 $ 6,735 Shares issued for cash on exercise of options 1,262,795 28 Deferred taxes on share issuance cost — (2) Issued and outstanding at December 31, 2022 281,531,833 $ 6,761 (a) Dividends declared per share for the year ended December 31, 2022 was $1.06 (December 31, 2021 - $1.00). Preferred Shares As at December 31, 2022 December 31, 2021 Issued and Outstanding (a) (b) Number of shares Amount Number of shares Amount Series A 6,746,679 $ 169 6,746,679 $ 169 Series B 1,253,321 31 1,253,321 31 Series C (c) — — 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 K (d) — — 12,000,000 300 Share issuance costs, net of taxes (14) (30) 24,000,000 $ 586 44,000,000 $ 1,076 (a) On January 11, 2022, in connection with the offering of the Subordinated Notes, Series 1, AltaGas issued $300 million in Preferred Shares, Series 2022-A, to be held in the AltaGas Hybrid Trust with Computershare Trust Company of Canada acting as a trustee. Refer to Notes 13 and 17 for more details. (b) On August 17, 2022, in connection with the offering of the Subordinated Notes, Series 2, AltaGas issued $250 million in Preferred Shares, Series 2022-B, to be held in the AltaGas Hybrid Trust with Computershare Trust Company of Canada acting as a trustee. Refer to Notes 13 and 17 for more details. (c) On September 30, 2022, AltaGas redeemed all of its outstanding U.S. dollar denominated Series C Preferred Shares. A loss of $74 million was recognized upon redemption, which was comprised of a $69 million foreign exchange loss and a $5 million loss related to share issuance costs for the preferred shares. (d) On March 31, 2022, AltaGas redeemed all of its outstanding Series K Preferred Shares. A loss of $10 million was recognized upon redemption related to share issuance costs for the preferred shares. The following table outlines the characteristics of the cumulative redeemable preferred shares (a) (h) (i) : Current yield Annual dividend per share (b) Redemption price per share (g) Redemption and conversion option date (c)(g) 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 E (e) 5.393 % $1.34825 $25 December 31, 2023 Series F Series G (e) 4.242 % $1.06050 $25 September 30, 2024 Series H Series H (f) (g) Floating Floating $25 September 30, 2024 Series G (a) The Corporation is authorized to issue up to 8,000,000 of Series F 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 are also redeemable for $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 E Shares, and Series G 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 F 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, 2022, the floating quarterly dividend rate is $0.41875 per share for Series B Shares and $0.44340 per share for Series H Shares for the period starting December 31, 2022 to, but excluding, March 31, 2023. (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) The Series 2022-A Shares were issued to Computershare Trust Company of Canada to be held in trust to satisfy AltaGas’ obligations under the Series 1 Indenture, in connection with the issuance of the Subordinated Notes, Series 1. Holders of the Series 2022-A Shares shall not be entitled to receive any dividends, nor shall any dividends accumulate or accrue, on the Series 2022-A Shares prior to delivery to the holders of the Subordinated Notes, Series 1 following the occurrence of certain bankruptcy or insolvency events in respect of AltaGas. If at any time, AltaGas redeems, purchases for cancellation or repays the Subordinated Notes, Series 1 such number of Series 2022-A Shares with an aggregate issue price equal to the principal amount of Subordinated Notes, Series 1 redeemed, purchased for cancellation or repaid by AltaGas will be redeemed in accordance with the terms of the Series 2022-A Shares. (i) The Series 2022-B Shares were issued to Computershare Trust Company of Canada to be held in trust to satisfy AltaGas’ obligations under the Series 2 Indenture, in connection with the issuance of the Subordinated Notes, Series 2. Holders of the Series 2022-B Shares shall not be entitled to receive any dividends, nor shall any dividends accumulate or accrue, on the Series 2022-B Shares prior to delivery to the holders of the Subordinated Notes, Series 2 following the occurrence of certain bankruptcy or insolvency events in respect of AltaGas. If at any time, AltaGas redeems, purchases for cancellation or repays the Subordinated Notes, Series 2 such number of Series 2022-B Shares with an aggregate issue price equal to the principal amount of Subordinated Notes, Series 2 redeemed, purchased for cancellation or repaid by AltaGas will be redeemed in accordance with the terms of the Series 2022-B Shares. 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, 2022, 11,713,367 shares were reserved for issuance under the plan. As at December 31, 2022, share options granted under the plan have a term between six As at December 31, 2022, the unexpensed fair value of share option compensation cost associated with future periods was $1 million (December 31, 2021 ‑ $3 million). The following table summarizes information about the Corporation’s share options: December 31, 2022 December 31, 2021 As at Options outstanding Options outstanding Number of Exercise price (a) Number of Exercise price (a) Share options outstanding, beginning of year 8,679,508 $ 19.98 8,362,211 $ 21.06 Granted — — 1,878,670 18.77 Exercised (1,262,795) 19.94 (774,739) 17.44 Forfeited (107,799) 26.24 (214,259) 25.24 Expired (350,775) 32.19 (572,375) 33.26 Share options outstanding, end of year 6,958,139 $ 19.28 8,679,508 $ 19.98 Share options exercisable, end of year 4,960,341 $ 19.38 4,435,287 $ 20.72 (a) Weighted average. As at December 31, 2022, the aggregate intrinsic value of the total share options exercisable was $24 million (December 31, 2021 - $33 million), the total intrinsic value of share options outstanding was $33 million (December 31, 2021 - $68 million) and the total intrinsic value of share options exercised was $11 million (December 31, 2021 - $5 million). The following table summarizes the employee share option plan as at December 31, 2022: 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 1,739,186 $ 15.41 2.07 1,712,333 $ 15.40 2.04 $18.01 to $25.08 4,570,158 19.27 3.25 2,601,089 19.43 2.96 $25.09 to $37.86 648,795 29.70 0.72 646,919 29.71 0.71 6,958,139 $ 19.28 2.72 4,960,341 $ 19.38 2.35 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 (a) 2022 2021 Fair value per options ($) — 3.37 Risk-free interest rate (%) — 0.42 Expected life (years) — 6 Expected volatility (%) (b) — 35.70 Annual dividend per share ($) (c) — 1.00 Forfeiture rate (%) — — (a) No options were granted in 2022. (b) Expected volatility assumptions are based on the historic daily share price volatility. (c) 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, executive officers, and directors, which includes restricted units (RUs) and performance units (PUs) with vesting periods of 36 months from the grant date. In addition, AltaGas has a DSUP, pursuant to which directors receive deferred share units (DSUs). 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) 2022 2021 Balance, beginning of year 3,877,843 5,920,300 Granted 1,413,790 1,611,727 Vested and paid out (1,784,293) (3,495,702) Forfeited (140,150) (313,621) Units in lieu of dividends 172,563 126,250 Additional units added by performance factor 792,309 28,889 Outstanding, end of year 4,332,062 3,877,843 For the year ended December 31, 2022, the compensation expense recorded for the Phantom Plan and DSUP was $50 million (2021 – $66 million). As at December 31, 2022, the unrecognized compensation expense relating to the remaining vesting period for the Phantom Plan was $14 million (December 31, 2021 ‑ $16 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, 2022
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 2022 2021 Numerator: Net income applicable to controlling interests $ 523 $ 283 Less: Preferred share dividends (40) (53) Loss on redemption of preferred shares (note 26) (84) — Net income applicable to common shares $ 399 $ 230 Denominator: (millions of shares) Weighted average number of common shares outstanding 281.0 279.9 Dilutive equity instruments (a) 2.3 1.8 Weighted average number of common shares outstanding - diluted 283.3 281.7 Basic net income per common share $ 1.42 $ 0.82 Diluted net income per common share $ 1.41 $ 0.82 (a) Determined using the treasury stock method.

Other Income

Other Income	12 Months Ended
	Dec. 31, 2022
Other Income and Expenses [Abstract]
Other Income	Other Income Year Ended December 31 2022 2021 Gains on asset sales (note 4) $ 3 $ 6 Other components of net benefit cost (note 29) 74 64 Interest income and other revenue 17 11 Total $ 94 $ 81

Pension Plans and Retiree Benef

Pension Plans and Retiree Benefits	12 Months Ended
	Dec. 31, 2022
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. Defined Contribution Plan AltaGas has a defined contribution (DC) pension plan for substantially all employees. The pension cost recorded for the DC plan was $25 million for the year ended December 31, 2022 (2021 - $22 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 five 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 fully funded ex cept for two o f the divisions in Canada, which are partially funded. In 2021, AltaGas made the decision to wind-up the Canadian defined benefit pension plan effective March 31, 2022. As the decision to wind-up the plan was made in 2021, a curtailment of less than $1 million was recorded to AOCI for the year ended December 31, 2021. In October 2022, approval of the wind-up was received from the Alberta Superintendent of Pensions. AltaGas’ most recent actuarial valuation of the Canadian defined benefit plan for funding purposes was completed for the year ended December 31, 2019. As the Canadian defined benefit plan is in the process of being wound up, no further actuarial valuations for this plan are required. 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, i ncluding one in Canada and five 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, three are fully funded, and one is not funded. Rabbi Trusts Rabbi trusts of $11 million as at December 31, 2022 have been funded to satisfy the employee benefit obligations associated with WGL’s various pension plans (December 31, 2021 - $18 million). These balances are included in the "prepaid expenses and other current assets" and "long-term investments and other assets" line items on 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, 2022 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 $ 1,743 $ 430 $ 1,777 $ 432 Actuarial gain (6) — (473) (118) (479) (118) Current service cost 3 — 22 10 25 10 Member contributions — — — 3 — 3 Interest cost 1 — 52 13 53 13 Benefits paid (4) — (83) (23) (87) (23) Expenses paid — — (1) — (1) — Settlements — — (5) — (5) — Other — — — 1 — 1 Foreign exchange translation — — 98 25 98 25 $ 28 $ 2 $ 1,353 $ 341 $ 1,381 $ 343 Less: projected benefit obligation reclassified to liabilities associated with assets held for sale ( note 5) (b) — — (85) (9) (85) (9) Balance, end of year $ 28 $ 2 $ 1,268 $ 332 $ 1,296 $ 334 Plan assets Fair value, beginning of year $ 16 $ — $ 1,715 $ 1,058 $ 1,731 $ 1,058 Actual return on plan assets (3) — (374) (254) (377) (254) Employer contributions 4 — 8 — 12 — Member contributions — — — 3 — 3 Benefits paid (4) — (83) (23) (87) (23) Expenses paid — — (1) — (1) — Settlements — — (5) — (5) — Other — — — 1 — 1 Foreign exchange translation — — 99 60 99 60 $ 13 $ — $ 1,359 $ 845 $ 1,372 $ 845 Less: plan assets reclassified to assets held for sale ( note 5) (b) — — (93) (3) (93) (3) Fair value, end of year $ 13 $ — $ 1,266 $ 842 $ 1,279 $ 842 Funded status (c) $ (15) $ (2) $ 6 $ 504 $ (9) $ 502 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation. (b) Presented on a net basis in Note 5. See below for specific amounts included in the Consolidated Balance Sheets. (c) Calculation includes plan assets and liabilities classified as held for sale. Year Ended December 31, 2021 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 $ 37 $ 2 $ 1,800 $ 452 $ 1,837 $ 454 Actuarial gain (4) — (39) (19) (43) (19) Current service cost 4 — 23 10 27 10 Member contributions — — — 2 — 2 Interest cost 1 — 49 12 50 12 Benefits paid (4) — (74) (25) (78) (25) Expenses paid — — (1) — (1) — Settlements — — (7) — (7) — Plan amendments — — — (1) — (1) Foreign exchange translation — — (8) (1) (8) (1) Balance, end of year $ 34 $ 2 $ 1,743 $ 430 $ 1,777 $ 432 Plan assets Fair value, beginning of year $ 16 $ — $ 1,667 $ 1,016 $ 1,683 $ 1,016 Actual return on plan assets — — 125 67 125 67 Employer contributions 4 — 11 — 15 — Member contributions — — — 2 — 2 Benefits paid (4) — (74) (23) (78) (23) Expenses paid — — (1) — (1) — Settlements — — (7) — (7) — Foreign exchange translation — — (6) (4) (6) (4) Fair value, end of year $ 16 $ — $ 1,715 $ 1,058 $ 1,731 $ 1,058 Funded status $ (18) $ (2) $ (28) $ 628 $ (46) $ 626 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation. For the year ended December 31, 2022 and year ended December 31, 2021, AltaGas' defined benefit and post-retirement benefit pension plans incurred actuarial gains primarily due to the increase in discount rates, which were the result of an increase in high-quality corporate bond yield curves in the Canadian and U.S. markets. The following amounts were included in the Consolidated Balance Sheets: December 31, 2022 December 31, 2021 Defined Benefit Post- Retirement Benefits Total Defined Benefit Post-Retirement Benefits Total Prepaid post-retirement benefits $ 28 $ 510 $ 538 $ 37 $ 637 $ 674 Assets held for sale ( note 5) 8 — 8 — — — Accounts payable and accrued liabilities (a) (3) — (3) (8) — (8) Future employee obligations (42) (2) (44) (75) (11) (86) Liabilities associated with assets held for sale ( note 5) — (6) (6) — — — $ (9) $ 502 $ 493 $ (46) $ 626 $ 580 (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, 2022 December 31, 2021 Canada United States Canada United States Accumulated benefit obligation (a) $ 27 $ 1,307 $ 33 $ 1,659 (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, 2022, the cumulative obligation and asset balances were: As at December 31, 2022 December 31, 2021 Defined Benefit Post-Retirement Benefits Defined Post-Retirement Benefits Projected benefit obligation $ 49 $ 11 $ 375 $ 14 Plan assets $ 3 $ 3 $ 289 $ 3 For those pension plans where the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2022, the cumulative obligation and asset balances were: As at December 31, 2022 December 31, 2021 Defined Benefit Post-Retirement Benefits Defined Post-Retirement Benefits Accumulated benefit obligation $ 48 $ 11 $ 221 $ 14 Plan assets $ 3 $ 3 $ 158 $ 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, 2022 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Past service cost $ — $ — $ — $ (1) $ — $ (1) Net actuarial loss (2) — — (3) (2) (3) Recognized in AOCI pre-tax $ (2) $ — $ — $ (4) $ (2) $ (4) Increase by the amount — — — 1 — 1 Net amount in AOCI after-tax $ (2) $ — $ — $ (3) $ (2) $ (3) Year Ended December 31, 2021 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service cost $ — $ — $ — $ (2) $ — $ (2) Net actuarial gain (loss) (5) (1) 4 (6) (1) (7) Recognized in AOCI pre-tax $ (5) $ (1) $ 4 $ (8) $ (1) $ (9) Increase (decrease) by the amount 1 — (1) 2 — 2 Net amount in AOCI after-tax $ (4) $ (1) $ 3 $ (6) $ (1) $ (7) 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, 2022 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit $ — $ — $ — $ (64) $ — $ (64) Net actuarial gain — — (47) (123) (47) (123) $ — $ — $ (47) $ (187) $ (47) $ (187) Less: regulatory asset (liability) reclassified to assets (liabilities associated with assets) held for sale — — (3) 3 (3) 3 Recognized in regulatory liability $ — $ — $ (50) $ (184) $ (50) $ (184) Year Ended December 31, 2021 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit $ — $ — $ — $ (77) $ — $ (77) Net actuarial gain — — (26) (289) (26) (289) Recognized in regulatory liability $ — $ — $ (26) $ (366) $ (26) $ (366) 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, 2022 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 3 $ — $ 22 $ 10 $ 25 $ 10 Interest cost (b) 1 — 52 13 53 13 Expected return on plan assets (b) — — (79) (38) (79) (38) Amortization of past service credit (b) — — — (18) — (18) Amortization of net actuarial loss (gain) (b) — — 2 (7) 2 (7) Net benefit cost (income) recognized $ 4 $ — $ (3) $ (40) $ 1 $ (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. Year Ended December 31, 2021 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 4 $ — $ 23 $ 10 $ 27 $ 10 Interest cost (b) 1 — 49 12 50 12 Expected return on plan assets (b) (1) — (76) (34) (77) (34) Amortization of past service credit (b) — — — (18) — (18) Amortization of net actuarial loss (gain) (b) 1 — 6 (6) 7 (6) Plan settlements (b) — — 2 — 2 — Net benefit cost (income) recognized $ 5 $ — $ 4 $ (36) $ 9 $ (36) (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 for the Canadian defined benefit pension plan is a liability-matching fixed income portfolio that is constructed to have similar characteristics as the liabilities of the pension plan. The liability-matching fixed income portfolio is determined as the combination of fixed income indices that exhibit the same sensitivity to real and nominal interest rate changes as the liabilities of the pension plan. The objective for fund returns for the pension plans in the United States, over three three 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 defined benefit plan is 100 percent fixed income assets. The target asset mix for SEMCO plans is 33 percent fixed income assets, 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 defined benefit plans are as follows as at December 31, 2022 and December 31, 2021: Year Ended December 31, 2022 Canada Fair value Level 1 Level 2 Percentage of Plan Assets (%) December 31, 2022 Cash and short-term equivalents $ 2 $ 2 $ — 15 Fixed income Canadian bonds 11 $ 11 $ — 85 $ 13 $ 13 $ — 100 December 31, 2021 Cash and short-term equivalents $ 2 $ 2 $ — 13 Fixed income Canadian bonds 14 14 — 87 $ 16 $ 16 $ — 100 Year Ended December 31, 2022 United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) December 31, 2022 Cash and short-term equivalents $ 2 $ 2 $ — — Canadian equities 2 2 — — Foreign equities (a) 247 247 — 20 Fixed income Government debt 413 80 333 33 Corporate debt 355 30 325 28 Derivatives 2 — 2 — Other (b) 11 — 11 1 Total investments in the fair value hierarchy $ 1,032 $ 361 $ 671 82 Investments measured at net asset value using the NAV practical expedient (c) Pooled separate accounts (d) $ 43 3 Collective trust funds (e) 279 22 Total fair value of plan investments $ 1,354 107 Net receivable (f) 5 — $ 1,359 107 Less: investments reclassified to assets held for sale (93) (7) $ 1,266 100 December 31, 2021 Cash and short-term equivalents $ 2 $ 2 $ — — Canadian equities 2 2 — — Foreign equities (a) 290 290 — 17 Fixed income Government debt 346 39 307 20 Corporate debt 502 79 423 30 Derivatives 6 — 6 — Other (b) 11 — 11 1 Total investments in the fair value hierarchy $ 1,159 $ 412 $ 747 68 Investments measured at net asset value using the NAV practical expedient (c) Private equity/limited partnership (g) $ 46 3 Pooled separate accounts (d) 38 2 Collective trust funds (e) 467 27 Total fair value of plan investments $ 1,710 100 Net receivable (f) 5 — $ 1,715 100 (a) Consists of investments in foreign equities include U.S. and international securities. (b) As at December 31, 2022 and December 31, 2021, these investments consisted primarily of non-U.S. government bonds and asset-backed securities. (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, 2022, investments in pooled separate accounts consisted of 100 percent income producing properties located in the United States (December 31, 2021 - 100 percent). (e) As at December 31, 2022, investments in collective trust funds consisted primarily of 79 percent common stock of U.S. companies (December 31, 2021 - 91 percent), 16 percent income producing properties located in the United States (December 31, 2021 - 9 percent), and 5 percent of short-term money market investments (December 31, 2021 - nil). (f) As at December 31, 2022 and December 31, 2021, this net receivable primarily represents pending trades for investments sold and interest receivable net of pending trades for investments purchased. (g) As at December 31, 2021, investments in a private equity/limited partnership consisted of common stock of international companies. The collective investment mixes for the post-retirement benefit plans are as follows as at December 31, 2022 and December 31, 2021: United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) December 31, 2022 Cash and short-term equivalents $ 8 $ 8 $ — 1 Foreign equities (a) 50 50 — 6 Fixed income Government debt 101 21 80 12 Corporate debt 85 8 77 10 Other (b) 5 — 5 1 Total investments in the fair value hierarchy $ 249 $ 87 $ 162 30 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 596 71 Total fair value of plan investments $ 845 101 Less: investments reclassified to assets held for sale (3) (1) $ 842 100 December 31, 2021 Cash and short-term equivalents $ 6 $ 6 $ — 1 Foreign equities (a) 60 60 — 6 Fixed income Government debt 104 10 94 10 Corporate debt 122 20 102 11 Other (b) 6 — 6 1 Total investments in the fair value hierarchy $ 298 $ 96 $ 202 29 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 760 71 $ 1,058 100 (a) Consists of investments in foreign equities include U.S. and international securities. (b) As at December 31, 2022 and December 31, 2021, 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, 2022, investments in commingled funds consisted of approximately 49 percent common stock of large-cap U.S. companies (December 31, 2021 - 51 percent), 23 percent U.S. Government fixed income securities (December 31, 2021 - 21 percent), and 28 percent corporate bonds for WGL’s post-retirement benefit plans (December 31, 2021 - 28 percent). Year Ended December 31 2022 2021 Significant actuarial assumptions used in measuring net benefit plan costs Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 2.50 - 5.05 3.10 1.90 - 2.85 2.50 - 3.10 Expected long-term rate of return on plan assets (%) (a) 2.83 - 6.50 3.00 - 6.50 4.75 - 7.00 3.37 - 7.00 Rate of compensation increase (%) 2.50 - 4.00 3.00 1.00 - 4.00 2.50 - 3.00 (a) Only applicable for funded plans As at December 31 2022 2021 Significant actuarial assumptions used in measuring benefit obligations Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 5.05 - 5.60 5.30 - 5.70 2.50 - 3.10 3.10 Rate of compensation increase (%) 2.50 - 4.00 3.00 2.50 - 4.00 3.00 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 2.8 and 6.5 percent. The health care cost trend rates were assumed to decline to between 2.6 and 5.0 percent by 2030. The following table shows the expected cash flows for defined benefit pension and other post-retirement plans: Defined Post-Retirement Expected employer contributions: 2023 $ 8 $ — Expected benefit payments: 2023 $ 95 $ 23 2024 $ 94 $ 22 2025 $ 96 $ 22 2026 $ 97 $ 23 2027 $ 98 $ 23 2028 - 2032 $ 501 $ 119

Commitments, Guarantees, and Co

Commitments, Guarantees, and Contingencies	12 Months Ended
	Dec. 31, 2022
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, 2022 are estimated as follows: 2023 2024 2025 2026 2027 2028 & beyond Total Gas purchase (a) (b) $ 1,433 $ 1,209 $ 1,088 $ 1,014 $ 1,004 $ 3,406 $ 9,154 Pipeline and storage services (b) (c) 474 428 392 347 303 749 2,693 LPG purchase (d) 431 336 251 173 150 194 1,535 Electricity purchase (e) 869 616 231 56 16 2 1,790 Operating leases (f) 101 96 81 72 56 156 562 Service agreements (g) (h) (i) 76 53 47 38 29 251 494 Environmental (j) 10 1 1 1 — — 13 Post-acquisition contingent payments (k) 5 — — — — — 5 Crude oil and condensate purchase (l) 14 — — — — — 14 Merger commitments (m) 5 2 1 1 1 — 10 Capital projects (n) 32 — — — — — 32 $ 3,450 $ 2,741 $ 2,092 $ 1,702 $ 1,559 $ 4,758 $ 16,302 (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. Pursuant to the May 26, 2022 announcement of the Alaska Utilities Disposition, $2.6 billion of the gas purchase commitments are associated with the assets held for sale at December 31, 2022. The transaction closed on March 1, 2023. Refer to Notes 5 and 34 for more details. (b) Excludes an estimated US$7.6 billion of natural gas purchases through 2033 and US$1 billion of pipeline contracts through 2043 that are contingent on the in-service date of the Mountain Valley Pipeline. (c) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044. (d) 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. (e) 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$78 million of commitments related to renewable energy credits. (f) 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. Operating leases also include $203 million in future undiscounted cash flows associated with leasing arrangements for the use of Very Large Gas Carriers (VLGCs) that are anticipated to commence between 2023 and 2024 and $11 million in future discounted cash flows associated with leasing arrangements for rail cars commencing in 2023. (g) 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, 2022, the total commitment was $148 million payable over the next 13 years, of which $53 million is expected to be paid over the next 5 years. (h) In 2017, AltaGas entered into a 12-year service agreement commencing in 2019 for tug services to support the marine operations of RIPET. (i) In 2015, AltaGas entered into a Project Agreement that contemplated the sublease of lands from Ridley Terminals Inc. (RTI, now Trigon Pacific Terminals Ltd. (Trigon)), provision of certain terminal services, and access to Trigon's terminal facilities to support RIPET's operations for an initial term of 20 years ending in 2039. In 2019, RILE LP and Trigon executed a Terminal Services Agreement that formalized the concepts outlined in the Project Agreement. (j) Environmental commitments include committed payments related to certain environmental response costs. (k) Relating to certain air-related violations at the Ferndale terminal. The penalty was paid in full in February 2023. (l) AltaGas enters into 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. (m) Represents the estimated future payments of WGL merger commitments that have been accrued but not paid. Among other things, these commitments include rate credits distributable to both residential and non-residential customers to partially offset rate increases resulting from gas expansion, extension of natural gas service over a 10-year period and other programs, various public interest commitments, and safety programs. As at December 31, 2022, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$8 million. Additionally, there are a number of operational commitments with various timeframes, including the funding of leak mitigation and reducing leak backlogs, the funding of damage prevention efforts, developing projects to extend natural gas service, maintaining pre-merger quality of service standards including odor call response times, increasing supplier diversity, achieving synergy savings benefits, as well as reporting and tracking related to certain commitments, and causing the development of 15 MW of either electric grid energy storage or tier one renewable resources. (n) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs. Guarantees AltaGas has guaranteed payments primarily for certain commitments on behalf of some of its subsidiaries. As at December 31, 2022, AltaGas has no guarantees issued on behalf of external parties. Contingencies

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
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, 2022 December 31, 2021 Due from related parties Accounts receivable (a) $ 1 $ 7 Due to related parties Accounts payable (b) $ 1 $ 7 (a) Receivables from affiliates. (b) Payables to affiliates. The following transactions with related parties have been recorded on the Consolidated Statements of Income for the years ended December 31, 2022 and 2021: Year Ended December 31 2022 2021 Cost of sales (a) $ 7 $ 6

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2022
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 2022 2021 Source (use) of cash: Accounts receivable $ (691) $ (206) Inventory (324) (232) Risk management assets - current 4 4 Other current assets (1) 4 Regulatory assets - current 13 (3) Accounts payable and accrued liabilities 377 92 Customer deposits 14 27 Regulatory liabilities - current 98 (12) Risk management liabilities - current (6) (1) Other current liabilities (12) 21 Other operating assets and liabilities (122) (104) Changes in operating assets and liabilities $ (650) $ (410) The following table details the changes in non-cash investing and financing activities: Year Ended 2022 2021 Decrease (increase) of balance: Exercise of stock options $ 3 $ 2 Common share dividends payable $ — $ 22 Net right-of-use assets obtained in exchange for new operating lease liabilities $ (56) $ (38) Net right-of-use assets obtained in exchange for new finance lease liabilities $ (14) $ (10) Capital expenditures included in accounts payable and accrued liabilities $ 6 $ 33 The following cash payments have been included in the determination of earnings: Year Ended 2022 2021 Interest paid (net of capitalized interest) $ 304 $ 279 Income taxes paid $ 17 $ 69 The following table is a reconciliation of cash and restricted cash balances: As at December 31 2022 2021 Cash and cash equivalents $ 53 $ 63 Restricted cash holdings from customers - current — 3 Restricted cash included in prepaid expenses and other current assets (a) 3 8 Restricted cash included in long-term investments and other assets (note 12) (a) 8 10 Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows $ 64 $ 84 (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 29).

Segmented Information

Segmented Information	12 Months Ended
	Dec. 31, 2022
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. 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. The sale of the Alaskan Utilities closed on March 1, 2023; n rate-regulated natural gas storage in the United States, of which certain storage facilities in Alaska were sold on March 1, 2023, pursuant to the Alaska Utilities Disposition; and n sale of energy 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) export terminals; n transmission pipelines to transport natural gas and NGLs; 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, 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. The following table provides a reconciliation of segment revenue to the disaggregated revenue table disclosed in Note 25: Year Ended December 31, 2022 Utilities Midstream Corporate/Other Total External revenue (note 25) $ 4,980 $ 9,010 $ 97 $ 14,087 Segment revenue $ 4,980 $ 9,010 $ 97 $ 14,087 Year Ended December 31, 2021 Utilities Midstream Corporate/Other Total External revenue (note 25) $ 3,936 $ 6,533 $ 104 $ 10,573 Intersegment revenue — 2 — 2 Segment revenue $ 3,936 $ 6,535 $ 104 $ 10,575 Geographic Information Year Ended December 31 2022 2021 Revenue (a) Canada $ 8,915 $ 6,420 United States 5,155 4,304 Total $ 14,070 $ 10,724 (a) Operating revenue from external customers, excluding unrealized gains or losses on risk management contracts. As at December 31 2022 2021 Property, plant and equipment Canada $ 2,930 $ 3,109 United States 8,756 8,214 Total $ 11,686 $ 11,323 Operating right-of-use assets Canada $ 212 $ 239 United States 69 72 Total $ 281 $ 311 The following tables show the composition by segment: Year Ended December 31, 2022 Utilities Midstream Corporate/Other Intersegment Elimination Total Segment revenue (note 25) $ 4,980 $ 9,010 $ 97 $ — $ 14,087 Cost of sales (3,197) (7,915) (26) — (11,138) Operating and administrative (1,023) (461) (84) — (1,568) Accretion expenses (1) (6) — — (7) Depreciation and amortization (290) (116) (33) — (439) Provisions on assets (note 6) — (6) — — (6) Income from equity investments 2 11 — — 13 Other income 77 9 8 — 94 Foreign exchange gains — — 10 — 10 Interest expense — — (330) — (330) Income (loss) before income taxes $ 548 $ 526 $ (358) $ — $ 716 Net additions (reductions) to: Property, plant and equipment (a) $ 822 $ (117) $ (10) $ — $ 695 Intangible assets $ 2 $ 6 $ 1 $ — $ 9 (a) 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, 2021 Utilities Midstream Corporate/Other Intersegment Elimination Total Segment revenue (note 25) $ 3,936 $ 6,535 $ 104 $ (2) $ 10,573 Cost of sales (2,273) (5,412) (25) 2 (7,708) Operating and administrative (906) (475) (95) — (1,476) Accretion expenses (1) (6) 1 — (6) Depreciation and amortization (285) (104) (33) — (422) Provision on assets (note 6) — (59) (5) — (64) Income (loss) from equity investments 2 (263) — — (261) Other income 65 16 — — 81 Foreign exchange gains (losses) — 10 (6) — 4 Interest expense — — (275) — (275) Income (loss) before income taxes $ 538 $ 242 $ (334) $ — $ 446 Net additions (reductions) to: Property, plant and equipment (a) $ 705 $ (284) $ 8 $ — $ 429 Intangible assets $ 2 $ 2 $ 2 $ — $ 6 (a) 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, 2022 Goodwill $ 3,718 $ 1,532 $ — $ 5,250 Segmented assets $ 16,782 $ 6,728 $ 455 $ 23,965 As at December 31, 2021 Goodwill $ 3,691 $ 1,462 $ — $ 5,153 Segmented assets $ 14,603 $ 6,415 $ 575 $ 21,593

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On March 1, 2023, AltaGas closed the sale of its 100 percent interest in ENSTAR and 65 percent indirect interest in CINGSA and other ancillary operations to TriSummit Utilities for consideration of approximately US$800 million (approximately CAD$1.1 billion) prior to closing adjustments. Subsequent events have been reviewed through March 1, 2023, 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, 2022
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).
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 AltaGas' investment in Mountain Valley Pipeline (MVP) This methodology is used 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. 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, Washington Gas, Hampshire Gas, and, prior to the Alaska Utilities Disposition, ENSTAR (collectively the Utilities) engage in the delivery, sale, and storage of natural gas. SEMCO Gas is regulated by the Michigan Public Service Commission (MPSC). 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, 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, 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.
Accounts Receivable	Accounts Receivable Receivables 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 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. 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 1 to 43 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 Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 7 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 outstanding loans to hedge against the currency translation effect of its foreign investments. 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 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 recognized using a 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 long-term revolving committed credit facilities in an amount equal to or greater than the expected maximum short-term obligation.
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) for eligible employees, officers, and directors, which includes two types of awards: restricted units (RUs) and performance units (PUs). 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. All PUs are also subject to a performance multiplier ranging from 0 to 2 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. Forfeitures are recognized when they occur instead of estimating the number of awards that are expected to vest. In addition, AltaGas has a deferred share unit plan (DSUP) for directors, officers, and eligible employees as an additional form of long-term variable compensation incentive. Although the DSUP is available to directors, officers, and eligible 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. Forfeitures are recognized when they occur instead of estimating the number of awards that are expected to vest.
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. 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.
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. The rate-regulated natural gas distribution subsidiaries recognize a separate regulatory asset or liability for the amount of deferred income taxes expected to be recovered from, or paid to, customers in the future. Any tax related interest and/or penalty incurred is included in interest expense.
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. Variable lease payments are based on a rate. 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.
ADOPTION OF NEW ACCOUNTING STANDARDS AND FUTURE CHANGES IN ACCOUNTING PRINCIPLES	ADOPTION OF NEW ACCOUNTING STANDARDS Effective January 1, 2022, AltaGas adopted the following Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU): § In August 2020, FASB issued ASU No. 2020-06 "Debt with Conversion and Other Options and Topic 815-40 - Derivatives and Hedging - Contracts in Entity's Own Equity: Accounting for Convertible Instruments and Contract in an Entity's Own Equity". The amendments in this ASU simplify the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. The adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements; and § In July 2021, FASB issued ASU No. 2021-05 "Leases (Topic 842): Lessors - Certain Leases with Variable Lease Payments". The amendments in this ASU affect lessors with lease contracts that have variable lease payments that do not depend on a reference index or a rate as an operating lease that and would have resulted in the recognition of a selling loss at lease commencement if classified as sales-type or direct financing. The adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements. Effective December 31, 2022, AltaGas adopted the following FASB issued ASU: § In November 2021, FASB issued ASU No. 2021-10 "Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance". The amendments in this ASU require annual disclosure about transactions with a government entity, including the nature of the transactions, the method applied to account for the government assistance, impacted line items on the financial statements, and significant terms and conditions of the agreement. The adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements; and § In December 2022, FASB issued ASU 2022-06 "Topic 848 - Reference Rate Reform: Deferral of the Sunset Date of Topic 848". The amendments in this ASU defer the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. The adoption of this ASU did not have a material impact on AltaGas' consolidated financial statements. FUTURE CHANGES IN ACCOUNTING PRINCIPLES In October 2021, FASB issued ASU 2021-08 "Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers". The amendments in this ASU require an entity to recognize and measure contract assets and liabilities acquired in a business combination in accordance with Topic 606. The amendments in this ASU are effective for fiscal years beginning after December 15, 2022 and should be applied prospectively to business combinations occurring on or after the effective date of the amendment. The adoption of this ASU is not expected to have a material impact on AltaGas' consolidated financial statements. In March 2022, FASB issued ASU No. 2022-01 "Derivatives and Hedging (Topic 815): Fair Value Hedging - Portfolio Layer Method". The amendments in this ASU will allow non-prepayable financial assets to be included in a closed portfolio hedged using the portfolio layer method and promote consistency in single and multiple hedged layers. The amendments in this ASU are effective for fiscal years beginning after December 15, 2022 and should be applied on a modified retrospective basis. Early adoption is permitted. The adoption of this ASU is not expected to have a material impact on AltaGas' consolidated financial statements. In March 2022, FASB issued ASU No. 2022-02 "Financial Instruments - Credit Losses (Topic 326): Troubled Debt Restructurings and Vintage Disclosures". The amendments in this ASU will eliminate the accounting guidance for troubled debt restructurings (TDRs) by creditors while enhancing disclosure requirements for certain loan refinancings and restructurings by creditors when a borrower is experiencing financial difficulty, as well as require disclosure of current-period write offs by year of origination for financing receivables and net investments in leases. The amendments in this ASU are effective for fiscal years beginning after December 15, 2022 and should be applied prospectively with an option to apply on a modified retrospective basis for the transition method related to the recognition and measurement of TDRs. The adoption of this ASU is not expected to have a material impact on AltaGas' consolidated financial statements. In June 2022, FASB issued ASU No. 2022-03 "Fair Value Measurement (Topic 820): Fair Value Measurement of Equity Securities Subject to Contractual Sale Restrictions". The amendments in this ASU clarify that a contractual restriction on the sale of an equity security is not considered part of the unit of account of the equity security, and therefore, is not considered in measuring fair value. In addition, an entity cannot, as a separate unit of account, recognize a contractual sale restriction. Equity securities subject to contractual sale restrictions also require certain additional disclosures. The amendments in this ASU are effective for fiscal years beginning after December 15, 2023 and should be applied prospectively with adjustments as a result of adopting this ASU being recognized in earnings. The adoption of this ASU is not expected to have a material impact on AltaGas' consolidated financial statements. In September 2022, FASB issued ASU No. 2022-04 "Liabilities (Subtopic 405-50) - Supplier Finance Programs". The amendments in this ASU will require a buyer in a supplier finance program to disclose the key terms of the program, the amount outstanding at the end of the period, a roll forward of that obligation during the period, and where the obligation is presented on the balance sheet. The amendments in this ASU are effective for fiscal years beginning after December 15, 2022, except for the amendment on the roll forward information, which is effective for fiscal years beginning after December 15, 2023. The amendments in this ASU should be applied retrospectively, except for the amendment on the roll forward information, which is applied prospectively. The adoption of this ASU is not expected to have a material impact on AltaGas' consolidated financial statements.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Schedule 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 1 to 43 years Corporate/Other assets 3 to 46 years As at December 31, 2022 December 31, 2021 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value Utilities $ 9,806 $ (614) $ 9,192 $ 8,432 $ (437) $ 7,995 Midstream 3,810 (884) 2,926 3,898 (793) 3,105 Corporate/Other 879 (665) 214 840 (617) 223 Reclassified to assets held for sale ( note 5) (1,124) 478 (646) — — — $ 13,371 $ (1,685) $ 11,686 $ 13,170 $ (1,847) $ 11,323
Schedule 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 Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 7 years As at December 31, 2022 December 31, 2021 Cost Accumulated Net book Cost Accumulated Net book E&T contracts $ 26 $ (18) $ 8 $ 26 $ (17) $ 9 Energy services relationships 96 (86) 10 90 (63) 27 Software 359 (255) 104 331 (203) 128 Land rights 1 — 1 1 — 1 Commodity contracts 8 (6) 2 7 (1) 6 Reclassified to assets held for sale (note 5) (30) 25 (5) — — $ — $ 460 $ (340) $ 120 $ 455 $ (284) $ 171

Assets Held For Sale (Tables)

Assets Held For Sale (Tables)	12 Months Ended
	Dec. 31, 2022
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Assets Held for Sale	As at December 31, 2022 December 31, 2021 Assets held for sale Accounts receivable (net of credit losses of $1 million) (note 24) $ 93 $ — Inventory 86 — Restricted cash holdings from customers 1 — Prepaid expenses and other current assets 6 — Property, plant and equipment 646 — Intangible assets 5 — Operating right-of-use assets 1 — Goodwill 226 — Regulatory assets - non-current 14 — Post retirement benefits 8 — Long-term investments and other assets 1 — $ 1,087 $ — Liabilities associated with assets held for sale Accounts payable and accrued liabilities $ 59 $ — Current portion of long-term debt 7 — Customer deposits 13 — Long-term debt 56 — Asset retirement obligations 4 — Regulatory liabilities - non-current 96 — Operating lease liabilities - non-current 1 — Other long-term liabilities 53 — Future employee obligations 6 — $ 295 $ —

Provisions on Assets (Tables)

Provisions on Assets (Tables)	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Provisions on Assets	Year Ended December 31 2022 2021 Midstream $ 6 $ 59 Corporate/Other — 5 $ 6 $ 64

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2022
Inventory Disclosure [Abstract]
Schedule of Inventory	As at December 31 2022 2021 Natural gas held in storage (a) (b) $ 588 $ 341 Natural gas liquids 197 175 Materials and supplies 76 70 Renewable energy credits and emission compliance instruments 127 82 Crude oil and condensate 152 109 Processed finished products 6 5 $ 1,146 $ 782 Less: inventory reclassified to assets held for sale (note 5) (c) (86) — $ 1,060 $ 782 (a) As at December 31, 2022, $520 million of the natural gas held in storage was held by rate-regulated utilities (2021 - $304 million). (b) In 2022, a write-down of $5 million was recorded relating to the revaluation of the Company's natural gas storage inventory in the Midstream business to its net realizable value. (c) Pursuant to the May 26, 2022 announcement of the sale of the Alaska Utilities Disposition, $72 million of the natural gas held in storage that was held by rate-regulated utilities was reclassified to "assets held for sale" on the Consolidated Balance Sheets at December 31, 2022. The transaction closed on March 1, 2023. Refer to Notes 5 and 34 for more details.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
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 1 to 43 years Corporate/Other assets 3 to 46 years As at December 31, 2022 December 31, 2021 Cost Accumulated amortization Net book value Cost Accumulated amortization Net book value Utilities $ 9,806 $ (614) $ 9,192 $ 8,432 $ (437) $ 7,995 Midstream 3,810 (884) 2,926 3,898 (793) 3,105 Corporate/Other 879 (665) 214 840 (617) 223 Reclassified to assets held for sale ( note 5) (1,124) 478 (646) — — — $ 13,371 $ (1,685) $ 11,686 $ 13,170 $ (1,847) $ 11,323

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule 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 Extraction and Transmission (E&T) Contracts 25 years Commodity contracts 7 years As at December 31, 2022 December 31, 2021 Cost Accumulated Net book Cost Accumulated Net book E&T contracts $ 26 $ (18) $ 8 $ 26 $ (17) $ 9 Energy services relationships 96 (86) 10 90 (63) 27 Software 359 (255) 104 331 (203) 128 Land rights 1 — 1 1 — 1 Commodity contracts 8 (6) 2 7 (1) 6 Reclassified to assets held for sale (note 5) (30) 25 (5) — — $ — $ 460 $ (340) $ 120 $ 455 $ (284) $ 171
Schedule 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: 2023 $ 46 2024 $ 33 2025 $ 29 2026 $ 1 2027 $ 1 Thereafter $ 4

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Schedule of Components of Lease cost	The components of lease expense were as follows: Year Ended Year Ended Operating lease cost (includes variable lease payments) $ 100 $ 96 Finance lease cost Amortization of right-of-use assets 7 6 Interest on lease liabilities 1 — Total finance lease cost $ 8 $ 6 Total lease cost $ 108 $ 102 Supplemental cash flow information related to leases was as follows: Year Ended December 31 2022 2021 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows used by operating leases $ (111) $ (96) Financing cash flows used by finance leases (a) $ (8) $ (6) Right-of-use assets obtained in exchange for new lease liabilities Operating leases $ 56 $ 38 Finance leases $ 14 $ 10 (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 6.4 6.9 Finance leases 4.5 4.3 Weighted average discount rate (%) Operating leases 2.91 2.45 Finance leases 3.29 2.23
Schedule of Supplemental Balance Sheet Location	Supplemental balance sheet information related to leases was as follows: As at December 31 2022 2021 Operating Leases Operating lease right-of-use assets Long-term $ 281 $ 311 Included in assets held for sale (note 5) 1 — Total operating lease right-of-use assets $ 282 $ 311 Operating lease liabilities Current $ (92) $ (91) Long-term (215) (253) Included in liabilities associated with assets held for sale (note 5) (1) — Total operating lease liabilities $ (308) $ (344) Finance Leases Property and equipment, gross $ 46 $ 29 Accumulated depreciation (21) (12) Total property and equipment, net $ 25 $ 17 Less: finance lease property and equipment reclassified to assets held for sale (note 5) (3) — Property and equipment, net $ 22 $ 17 Current portion of long-term debt $ (8) $ (6) Long-term debt (17) (11) Total finance lease liabilities $ (25) $ (17) Less: finance lease liabilities reclassified to liabilities associated with assets held for sale (note 5) 3 — Finance lease liabilities $ (22) $ (17)
Schedule of Operating Lease Liability, Maturity Analysis	Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2023 $ 95 $ 8 2024 65 7 2025 50 5 2026 41 4 2027 25 2 Thereafter 73 2 Total lease payments $ 349 $ 28 Less: imputed interest (41) (3) Total $ 308 $ 25
Schedule of Finance Lease Liability, Maturity Analysis	Maturity analysis of lease liabilities was as follows: Operating Leases Finance 2023 $ 95 $ 8 2024 65 7 2025 50 5 2026 41 4 2027 25 2 Thereafter 73 2 Total lease payments $ 349 $ 28 Less: imputed interest (41) (3) Total $ 308 $ 25
Schedule of Maturity Analysis of Lease Receivables	Maturity analysis of lease receivables was as follows: Operating 2023 $ 73 2024 2 2025 2 2026 2 2027 1 Thereafter 76 Total $ 156

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	As at December 31, December 31, Balance, beginning of year $ 5,153 $ 5,039 Adjustment to goodwill on business acquisition — 147 Goodwill included in dispositions — (13) Reclassified to assets held for sale (note 5) (226) — Foreign exchange translation 323 (20) Balance, end of year $ 5,250 $ 5,153

Long-Term Investments and Oth_2

Long-Term Investments and Other Assets (Tables)	12 Months Ended
	Dec. 31, 2022
Investments, All Other Investments [Abstract]
Schedule of Long-Term and Other Investments	As at December 31, December 31, Deferred lease receivable $ 17 $ 15 Debt issuance costs associated with credit facilities 7 8 Refundable deposits 10 9 Prepayment on long-term service agreements 79 72 Deferred information technology costs 24 6 Cash calls from joint venture partners 21 23 Contract asset (net of credit losses of $1 million) (notes 24 and 25) 37 41 Rabbi trust (notes 29 and 32) 8 10 Capitalized contract costs 5 5 Financial transmission rights 39 17 Other 27 21 $ 274 $ 227 Less: long-term investments and other assets reclassified to assets held for sale (note 5) (1) — $ 273 $ 227

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 December 31, 2021 Current assets $ 12 $ 6 Property, plant and equipment 353 357 Long-term investments and other assets 45 47 Current liabilities (16) (8) Asset retirement obligations (4) (3) Net assets $ 390 $ 399

Investments Accounted for by _2

Investments Accounted for by the Equity Method (Tables)	12 Months Ended
	Dec. 31, 2022
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 2022 2021 2022 2021 Constitution Pipeline, LLC (Constitution) (a) United States 10 $ — $ — $ 3 $ — Eaton Rapids Gas Storage System United States 50 28 27 3 2 Mountain Valley Pipeline, LLC (MVP) (b) United States 10 478 447 — (271) Sarnia Airport Storage Pool LP Canada 50 17 17 1 1 Petrogas Terminals Penn LLC (c) United States 50 1 1 — — Strathcona Storage LP (c) Canada 40 130 131 6 7 $ 654 $ 623 $ 13 $ (261) (a) In the third quarter of 2022, AltaGas received a payment for the return of certain costs associated with the Constitution pipeline project as a result of its cancellation in February 2020. (b) The equity method is considered appropriate because MVP is an LLC with specific ownership accounts and ownership between five and fifty percent, resulting in WGL Midstream (now WGL Sustainable Energy LLC) exercising a more than minor influence over the investee's operating and financing policies. In 2021, a provision was recorded against the equity investment in MVP due to ongoing legal and regulatory issues. Management has continued to assess the equity investment in MVP for further impairment and determined that no further provisions were required in 2022. (c) On July 5, 2022, AltaGas acquired the remaining 25.97 percent equity ownership of Petrogas which resulted in an increase in AltaGas' ownership in Petrogas Terminals Penn LLC from 37 percent to 50 percent and in Strathcona Storage LP from 30 percent to 40 percent. Refer to Note 3 for more details.
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 2022 2021 Revenues $ 50 $ 97 Expenses (26) (23) $ 24 $ 74 As at December 31 2022 2021 Current assets $ 136 $ 206 Property, plant and equipment $ 9,544 $ 8,571 Long-term investments and other assets $ 12 $ 3 Current liabilities $ (166) $ (214) Other long-term liabilities $ (14) $ (12)

Short-term Debt (Tables)

Short-term Debt (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Short-Term Debt	As at (a) December 31, December 31, Commercial paper $ 293 $ 161 Project financing — 8 $ 293 $ 169 (a) As at December 31, 2022, AltaGas' weighted average interest rate on short-term borrowings outstanding was 4.8 percent (December 31, 202 1 - 0.3 percent ).

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	As at Maturity date December 31, December 31, Credit facilities $2 billion unsecured extendible revolving facility (a) 20-May-2027 $ 860 $ 375 US$150 million unsecured extendible revolving facility 20-Dec-2026 188 120 Commercial paper (b) Various 386 469 $450 million term loan 25-Aug-2024 450 — AltaGas Ltd. medium-term notes (MTNs) $500 million Senior unsecured - 2.61 percent 16-Dec-2022 — 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 $350 million Senior unsecured - 1.23 percent 18-Mar-2024 350 350 $300 million Senior unsecured - 3.84 percent 15-Jan-2025 300 300 $500 million Senior unsecured - 2.16 percent 10-Jun-2025 500 500 $350 million Senior unsecured - 4.12 percent 7-Apr-2026 350 350 $200 million Senior unsecured - 2.17 percent 16-Mar-2027 200 200 $200 million Senior unsecured - 3.98 percent 4-Oct-2027 200 200 $500 million Senior unsecured - 2.08 percent 30-May-2028 500 500 $200 million Senior unsecured - 2.48 percent 30-Nov-2030 200 200 $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 and private placement notes US$20 million Senior unsecured - 6.65 percent 20-Mar-2023 27 25 US$41 million Senior unsecured - 5.44 percent 11-Aug-2025 55 51 US$53 million Senior unsecured - 6.62 to 6.82 percent Oct 2026 72 67 US$72 million Senior unsecured - 6.40 to 6.57 percent Feb - Sep 2027 98 91 US$52 million Senior unsecured - 6.57 to 6.85 percent Jan - Mar 2028 70 66 US$9 million Senior unsecured - 7.50 percent 1-Apr-2030 12 11 US$50 million Senior unsecured - 5.70 to 5.78 percent Jan - Mar 2036 68 63 US$75 million Senior unsecured - 5.21 percent 3-Dec-2040 102 95 US$75 million Senior unsecured - 5.00 percent 15-Dec-2043 102 95 US$300 million Senior unsecured - 4.22 to 4.60 percent Sep - Nov 2044 405 380 US$450 million Senior unsecured - 3.80 percent 15-Sep-2046 608 572 US$400 million Senior unsecured - 3.65 percent (c) 15-Sep-2049 563 528 US$200 million Senior unsecured - 2.98 percent 15-Dec-2051 271 254 US$25 million Senior unsecured - 5.25 percent 29-Dec-2042 34 — US$175 million Senior unsecured - 5.33 percent 29-Dec-2052 237 — SEMCO long-term debt US$82 million CINGSA Senior secured - 4.48 percent (d) 2-Mar-2032 60 63 US$225 million First Mortgage Bonds - 2.45 percent 21-Apr-2030 305 285 US$225 million First Mortgage Bonds - 3.15 percent 21-Apr-2050 305 285 Fair value adjustment on WGL acquisition 79 77 Finance lease liabilities (note 10) 25 17 $ 9,132 $ 8,239 Less: debt issuance costs (41) (44) $ 9,091 $ 8,195 Less: current portion (334) (511) Less: liabilities associated with assets held for sale (note 5) (e) (63) — $ 8,694 $ 7,684 (a) Borrowings on the facility can be by way of prime loans, U.S. base-rate loans, SOFR 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. During the fourth quarter of 2022, AltaGas completed an amendment of the Petrogas $200 million Revolving Credit Facility in which AltaGas has replaced Petrogas as the borrower, which is in addition to the AltaGas $2 billion five-year extendable committed revolving tranche, and the $300 million two-year extendable side car liquidity revolving facility. (b) Commercial paper is supported by the availability of long-term committed credit facilities maturing in 2024. Commercial paper intended to be repaid within the next year is recorded as short-term debt (Note 15). (c) The outstanding balance includes a US$15 million premium which will be amortized as a reduction to interest expense over the term of the note. (d) 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.

Subordinated Hybrid Notes (Tabl

Subordinated Hybrid Notes (Tables)	12 Months Ended
	Dec. 31, 2022
Restructuring and Related Activities [Abstract]
Schedule of Subordinated Borrowing	As at Maturity date December 31, December 31, $300 million subordinated notes, Series 1 11-Jan-2082 $ 300 $ — $250 million subordinated notes, Series 2 17-Aug-2082 250 — $ 550 $ — Less: debt issuance costs (6) — $ 544 $ —

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes in Asset Retirement Obligations	As at December 31 2022 2021 Balance, beginning of year $ 429 $ 379 Obligations acquired — 5 New obligations 3 4 Obligations settled (a) (10) (10) Disposals (1) — Revision in estimated cash flow (2) 40 Accretion expense (b) 20 19 Foreign exchange translation 23 (1) Reclassified to liabilities associated with assets held for sale (note 5) (4) — Total $ 458 $ 436 Less: current portion (included in accounts payable and accrued liabilities) (7) (7) Balance, end of year $ 451 $ 429 (a) During the year ended December 31, 2022, approximately $7 million of asset retirement obligations included in accounts payable and accrued liabilities were settled (December 31, 2021 - $7 million).

Other Long-term Liabilities (Ta

Other Long-term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Other Liabilities Disclosure [Abstract]
Schedule of Other Long-Term Liabilities	As at December 31, December 31, Deferred revenue $ 11 $ 13 Customer advances for construction 69 59 Merger commitments 5 7 Non-retirement employee benefits (a) 51 19 Uncertain tax positions (note 21) 20 20 Other 19 16 $ 175 $ 134 Less: liabilities associated with assets held for sale (note 5) (53) — $ 122 $ 134 (a) Consists of long-term portion of liabilities relating to employee incentive plans and other non-retirement related employee benefits.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of Income Tax Provision	Year Ended December 31 2022 2021 Income before income taxes - consolidated $ 716 $ 446 Statutory income tax rate (%) 23.0 23.0 Expected taxes at statutory rates $ 165 $ 103 Add (deduct) the tax effect of: Permanent differences $ 2 $ 3 Statutory and other rate differences 1 25 Deferred income tax recovery on regulated assets (21) (18) Tax differences on divestitures and transactions (3) (4) Other (1) (3) $ 143 $ 106 Income tax provision Current $ 23 $ 59 Deferred 120 47 $ 143 $ 106 Effective income tax rate (%) 20.0 23.8
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 $ 1,862 $ 1,709 Regulatory assets (187) (233) Tax pools, deferred financing, and compensation (238) (236) Other (69) (84) Valuation allowance 1 2 $ 1,369 $ 1,158
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 2022 2021 Balance, beginning of year $ 20 $ 21 Settlement — (1) Balance, end of year $ 20 $ 20

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 and 2021, over which the Corporation expects to realize or settle the assets or liabilities: As at December 31 2022 2021 Recovery Regulatory assets - current Deferred cost of gas (a) $ 15 $ 20 Less than one year Accelerated replacement recovery mechanisms (b) 11 7 Less than one year Energy optimization costs 4 5 Less than one year Virginia and Maryland revenue normalization (c) 8 16 Less than one year $ 38 $ 48 Regulatory assets - non-current Deferred regulatory costs (c) (d) $ 254 $ 199 1 - 53 years Future recovery of pension and other retirement benefits (c) 1 33 2 - 20 years Future recovery of non-retirement employee benefits (c) (e) 16 19 Various Deferred environmental costs (c) (f) 15 16 Various Deferred loss on debt transactions and derivative instruments (c) (g) 91 89 Various Deferred future income taxes (c) (h) 42 43 Various Energy efficiency program - Maryland (i) 31 23 Various COVID-19 costs (j) 4 6 Various Other 8 8 Various $ 462 $ 436 Less: non-current regulatory assets reclassified to assets held for sale (note 5) (14) — $ 448 $ 436 Regulatory liabilities - current Deferred cost of gas (a) $ 164 $ 71 Less than one year Refundable tax credit — 2 n/a Federal income tax rate change (k) 1 1 Less than one year Virginia rate refund (m) 5 — Less than one year Interruptible sharing (c) 3 4 Less than one year Virginia and Maryland revenue normalization (a) 2 — Less than one year Virginia Coronavirus Relief Fund (n) — 1 n/a Other 8 — Less than one year $ 183 $ 79 Regulatory liabilities - non-current Future expense of pension and other retirement benefits (c) $ 235 $ 425 Various Future removal and site restoration costs (l) 490 453 Various Deferred gain on debt transactions and derivative instruments (c) (g) 1 1 Various Federal income tax rate change (k) 568 543 Various Other 3 2 Various $ 1,297 $ 1,424 Less: non-current regulatory liabilities associated with assets held for sale (note 5) (96) — $ 1,201 $ 1,424 (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) Washington Gas is not entitled to a rate of return on these assets. (d) Includes deferred gas costs and fair value of derivatives, which are not included in customer bills until settled. (e) 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. (f) This balance represents allowed environmental remediation expenditures at SEMCO and Washington Gas sites to be recovered through rates. (g) 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, 2022, this also includes a fair value adjustment of $74 million (December 31, 2021 - $72 million) recorded on the WGL Acquisition in 2018. (h) 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. (i) Represents amounts for deferred credits associated with Washington Gas' participation in the energy conservation and efficiency program EmPower in Maryland. (j) Regulatory assets established to capture and track incremental COVID-19 related costs. (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) This amount and timing of draw down is dependent upon the cost of removal of the underlying utility property, plant and equipment and its useful life. (m) This amount represents estimated refunds related to customers billed at a higher rate during the interim period as part of the 2022 Virginia rate case. (n) The Virginia Coronavirus Relief Fund was received by WGL to provide direct assistance to Virginia customers with balances over 60 days in arrears.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2022
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 Total Opening balance, January 1, 2022 $ (8) $ (158) $ 159 $ (7) OCI before reclassification 4 (17) 640 627 Current period OCI (pre-tax) $ 4 $ (17) $ 640 $ 627 Income tax on amounts retained in AOCI (1) 2 — 1 Net current period OCI $ 3 $ (15) $ 640 $ 628 Purchase of remaining non-controlling interest in subsidiaries (note 3) — — 5 5 Ending balance, December 31, 2022 $ (5) $ (173) $ 804 $ 626 Opening balance, January 1, 2021 $ (12) $ (158) $ 220 $ 50 OCI before reclassification 3 — (61) (58) Amounts reclassified from OCI 3 — — 3 Current period OCI (pre-tax) $ 6 $ — $ (61) $ (55) Income tax on amounts retained in AOCI (1) — — (1) Income tax on amounts reclassified to earnings (1) — — (1) Net current period OCI $ 4 $ — $ (61) $ (57) Ending balance, December 31, 2021 $ (8) $ (158) $ 159 $ (7)
Schedule of Reclassification from Accumulated Other Comprehensive Income	Reclassification From Accumulated Other Comprehensive Income AOCI components reclassified Income statement line item Year Ended December 31, 2022 Year Ended Defined benefit pension and PRB plans Other income $ — $ 3 Deferred income taxes Income tax expense – deferred — (1) $ — $ 2

Financial Instruments and Fin_2

Financial Instruments and Financial Risk Management (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Fair Value of Risk Management Assets and Liabilities	As at December 31, 2022 Carrying Amount Level 1 Level 2 Level 3 Total Fair Value Financial assets Fair value through net income (a) Risk management assets - current $ 132 $ — $ 96 $ 36 $ 132 Risk management assets - non-current 77 — 52 25 77 Fair value through regulatory assets (a) Risk management assets - current 8 — 6 2 8 217 $ — $ 154 $ 63 $ 217 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 133 $ — $ 11 $ 122 $ 133 Risk management liabilities - non-current 170 — 4 166 170 Fair value through regulatory liabilities (a) Risk management liabilities - current 39 — — 39 39 Risk management liabilities - non-current 128 — — 128 128 Amortized cost Current portion of long-term debt 334 — 334 — 334 Long-term debt 8,694 — 7,721 — 7,721 Subordinated hybrid notes 544 — 480 — 480 Debt classified as held for sale (note 5) 63 — 60 — 60 Other current liabilities (b) 52 — 52 — 52 $ 10,157 $ — $ 8,662 $ 455 $ 9,117 (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, 2021 Carrying Level 1 Level 2 Level 3 Total Financial assets Fair value through net income (a) Risk management assets - current $ 112 $ — $ 73 $ 39 $ 112 Risk management assets - non-current 50 — 22 28 50 Fair value through regulatory assets (a) Risk management assets - current 1 — — 1 1 Risk management assets - non-current 1 — — 1 1 $ 164 $ — $ 95 $ 69 $ 164 Financial liabilities Fair value through net income (a) Risk management liabilities - current $ 113 $ — $ 58 $ 55 $ 113 Risk management liabilities - non-current 90 — 11 79 90 Fair value through regulatory liabilities (a) Risk management liabilities - current 15 — — 15 15 Risk management liabilities - non-current 75 — — 75 75 Amortized cost Current portion of long-term debt 511 — 511 — 511 Long-term debt 7,684 — 7,898 — 7,898 Other current liabilities (b) 43 — 43 — 43 $ 8,531 $ — $ 8,521 $ 224 $ 8,745 (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.
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, 2022: Net Fair Value Valuation Technique Unobservable Inputs Range Weighted Average (a) Natural gas $ (222) Discounted Cash Flow Natural Gas Basis Price (per Dth) $ (2.59) - $ 14.00 $ (0.50) Natural gas $ (4) Option Model Natural Gas Basis Price (per Dth) $ (2.06) - $ 7.30 $ 0.73 Annualized Volatility of Spot Market Natural Gas 22 % - 292 % 91 % Electricity $ (166) Discounted Cash Flow Electricity Congestion Price (per MWh) $ (10.86) - $ 185.54 $ 23.20 (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 2022 2021 Natural Electricity Total Natural Electricity Total Balance, beginning of year $ (107) $ (48) $ (155) $ (74) $ (19) $ (93) Net realized and unrealized losses: Recorded in income (43) (213) (256) (15) (25) (40) Recorded in regulatory assets (100) — (100) (28) — (28) Transfers out of Level 3 2 (30) (28) (1) — (1) Purchases — 16 16 — 4 4 Settlements 35 118 153 14 (8) 6 Foreign exchange translation (13) (9) (22) (3) — (3) Balance, end of year $ (226) $ (166) $ (392) $ (107) $ (48) $ (155)
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 2022 2021 Recorded to revenue $ (258) $ (79) Recorded to cost of sales 2 39 $ (256) $ (40)
Schedule 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 2022 2021 Natural gas $ (57) $ 6 Energy exports 21 38 Crude oil and NGLs 2 1 NGL frac spread 16 (13) Power (31) 9 Foreign exchange — (23) $ (49) $ 18
Schedule of Offsetting Assets and Liabilities	As at December 31, 2022 Gross amounts of recognized Gross amounts Netting Net amounts Risk management assets (a) Natural gas $ 174 $ (80) $ (17) $ 77 Energy exports 105 (112) 34 27 Crude oil and NGLs 6 (4) 2 4 NGL frac spread 6 (6) — — Power 153 (44) — 109 $ 444 $ (246) $ 19 $ 217 Risk management liabilities (b) Natural gas $ 360 $ (80) $ — $ 280 Energy exports 112 (112) — — Crude oil and NGLs 4 (4) — — NGL frac spread 9 (6) — 3 Power 231 (44) — 187 $ 716 $ (246) $ — $ 470 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $140 million and risk management assets (non‑current) balance of $77 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $172 million and risk management liabilities (non‑current) balance of $298 million. As at December 31, 2021 Gross amounts of Gross amounts Netting Net amounts Risk management assets (a) Natural gas $ 94 $ (22) $ (25) $ 47 Energy exports 61 (60) 37 38 NGL frac spread 4 — — 4 Power 101 (25) (1) 75 $ 260 $ (107) $ 11 $ 164 Risk management liabilities (b) Natural gas $ 164 $ (22) $ (4) $ 138 Energy exports 81 (60) 2 23 Crude oil and NGLs 6 — 2 8 NGL frac spread 23 — — 23 Power 126 (25) — 101 $ 400 $ (107) $ — $ 293 (a) Net amount of risk management assets on the Balance Sheet is comprised of risk management assets (current) balance of $113 million and risk management assets (non‑current) balance of $51 million. (b) Net amount of risk management liabilities on the Balance Sheet is comprised of risk management liabilities (current) balance of $128 million and risk management liabilities (non‑current) balance of $165 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 $ 2 $ 9 Cash collateral held representing an obligation $ 4 $ 2 As at December 31, December 31, Risk management liabilities with credit-risk-contingent features $ 145 $ 42 Maximum potential collateral requirements $ 68 $ 21
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, 2022 and 2021: December 31, 2022 Fixed price Period Notional volume (GJ) Fair Value ($ millions) Sales 1.75 to 20.38 1-130 244,060,786 $ (54) Purchases (a) 1.75 to 20.38 1-98 521,045,852 $ (169) Swaps 3.28 to 17.02 1-57 147,565,012 $ 20 December 31, 2021 Fixed price Period Notional volume (GJ) Fair Value ($ millions) Sales 1.75 to 10.8 1-142 259,750,059 $ (8) Purchases 1.75 to 10.8 1-143 606,923,548 $ (102) Swaps 2.95 to 7.42 1-55 201,266,412 $ 19 (a) Excludes approximately 191,071,366 GJ of natural gas purchases through 2033 that are contingent on the in-service date of the Mountain Valley Pipeline. December 31, 2022 Fixed price Period Notional volume (Bbl) Fair Value ($ millions) Swaps 44.19 to 120.45 1-12 1,597,173 $ 4 December 31, 2021 Fixed price Period Notional volume (Bbl) Fair Value ($ millions) Swaps 41.18 to 97.12 1-12 864,000 $ (8) December 31, 2022 Fixed price Period Notional volume Fair Value ($ millions) Purchases 9.45 1-3 90,646 Less than $1 million Propane and butane swaps 4.8 to 118.69 1-12 89,433,941 $ 27 December 31, 2021 Fixed price Period Notional volume Fair Value ($ millions) Propane and butane swaps 5.2 to 115.54 1-15 38,860,780 $ 15 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, 2022 and 2021: December 31, 2022 Fixed price Period Notional volume Fair Value ($ millions) Propane swaps 48.94 to 50.79/Bbl 1-12 1,075,194 Bbl $ 5 Crude oil swaps 108.65 to 113.88/Bbl 1-12 214,255 Bbl $ 1 Natural gas swaps 4.5 to 4.98/GJ 1-12 6,139,191 GJ $ (9) December 31, 2021 Fixed price Period Notional volume Fair Value ($ millions) Propane swaps 33.14 to 59.75/Bbl 1-12 2,099,243 Bbl $ (15) Butane swaps 36.19 to 36.20/Bbl 1-3 18,967 Bbl $ (1) Crude oil swaps 63.25 to 89.86/Bbl 1-12 369,495 Bbl $ (4) Natural gas swaps 2.54 to 3.89/GJ 1-12 11,873,390 GJ $ 1 December 31, 2022 Fixed price Period Notional volume Fair Value ($ millions) Power sales 37.18 to 167.07 1-42 5,276,832 $ (96) Power purchases 37.18 to 167.07 1-42 6,341,582 $ 99 Swap purchases (10.86) to 185.54 1-41 23,888,348 $ (81) December 31, 2021 Fixed price Period Notional volume Fair Value ($ millions) Power sales 27.19 to 93.94 1-42 4,938,045 $ (60) Power purchases 27.19 to 93.94 1-53 6,393,003 $ 69 Swap purchases (8.13) to 86.84 1-41 22,845,569 $ (35) Foreign exchange forward contract Notional Amount (US$ millions) Duration Weighted average foreign exchange rate Fair Value Foreign exchange swaps (purchases) US$10 Less than one year 1.2640 Less than $1 million
Schedule of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives	The table below provides the potential impact on pre-tax income due to changes in the fair value of risk management contracts in place as at December 31, 2022: Factor Increase or decrease to forward prices Increase or decrease to income before tax ($ millions) PJM power price US$1/MWh 43 NYMEX natural gas price US$0.50/GJ 30 Energy Exports: Propane Far East Index to domestic supply $1/Bbl (3) Baltic LPG Freight $1/Bbl 12 NGL frac spread: Propane $1/Bbl (1) Natural gas $0.50/GJ 3
Schedule of Accounts Receivable Past Due or Impaired	As at December 31, 2022 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 2,067 $ 1,078 $ 41 $ 751 $ 87 $ 26 $ 84 Other 65 — — 65 — — — Allowance for credit losses (41) — (41) — — — $ 2,091 $ 1,078 $ — $ 816 $ 87 $ 26 $ 84 As at December 31, 2021 Total AR Receivables Less than 31 to 61 to Over Trade receivable $ 1,431 $ 560 $ 39 $ 703 $ 52 $ 24 $ 53 Other 35 — — 35 — — — Allowance for credit losses (39) — (39) — — — — $ 1,427 $ 560 $ — $ 738 $ 52 $ 24 $ 53 The following table provides a summary of changes to the allowance for credit losses by segment and major type: Year Ended December 31, 2022 Accounts Receivable Contract Assets (a) Total Utilities Balance, beginning of period $ 38 $ — $ 38 Foreign exchange translation 2 — $ 2 Adjustments to allowance (b) 26 — 26 Written off (29) — (29) Recoveries collected 4 — 4 Reclassified to assets held for sale (note 5) (1) — (1) Balance, end of period $ 40 $ — $ 40 Midstream Balance, beginning of period $ 1 $ 1 $ 2 Adjustments to allowance — — — Balance, end of period $ 1 $ 1 $ 2 Total $ 41 $ 1 $ 42 (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 $2 million recorded to a regulatory asset relating to the impact of COVID-19 on uncollectible accounts. Year Ended December 31, 2021 Accounts Receivable Contract Assets (a) Other long-term investments and other assets (b) Total Utilities Balance, beginning of period $ 40 $ — $ — $ 40 Adjustments to allowance (b) 15 — — 15 Written off (22) — — (22) Recoveries collected 5 — — 5 Balance, end of period $ 38 $ — $ — $ 38 Midstream Balance, beginning of period $ 1 $ 1 $ 2 $ 4 New allowance — — (2) (2) Balance, end of period $ 1 $ 1 $ — $ 2 Total $ 39 $ 1 $ — $ 40 (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 $5 million recorded to a regulatory asset relating to the impact of COVID-19 on uncollectible accounts.
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, 2022 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,902 $ 1,902 $ — $ — $ — Short-term debt 293 293 — — — Other current liabilities (a) 52 52 — — — Risk management contract liabilities 470 172 183 57 58 Current portion of long-term debt (b) 327 327 — — — Long-term debt (b) 8,641 — 2,241 1,968 4,432 Debt classified as held for sale (60) (7) (12) (12) (29) Subordinated hybrid notes 550 — — — 550 $ 12,175 $ 2,739 $ 2,412 $ 2,013 $ 5,011 (a) Excludes non-financial liabilities. (b) Excludes deferred financing costs, discounts, finance lease liabilities, the fair value adjustment on the WGL Acquisition, and debt classified as held for sale. Contractual maturities by period As at December 31, 2021 Total Less than 1-3 years 4-5 years After Accounts payable and accrued liabilities $ 1,544 $ 1,544 $ — $ — $ — Short-term debt 169 169 — — — Other current liabilities (a) 43 43 — — — Risk management contract liabilities 293 128 85 25 55 Current portion of long-term debt (b) 506 506 — — — Long-term debt (b) 7,639 — 1,356 1,775 4,508 $ 10,194 $ 2,390 $ 1,441 $ 1,800 $ 4,563 (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, 2022
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue by Major Sources	The following tables disaggregate revenue by major sources for the year: Year Ended December 31, 2022 Utilities Midstream Corporate/Other Total Revenue from contracts with customers Commodity sales contracts $ 1,715 $ 6,260 $ — $ 7,975 Midstream service contracts — 2,411 — 2,411 Gas sales and transportation services 3,179 — — 3,179 Storage services 24 — — 24 Other 9 — 1 10 Total revenue from contracts with customers $ 4,927 $ 8,671 $ 1 $ 13,599 Other sources of revenue Revenue from alternative revenue programs (a) $ 94 $ — $ — $ 94 Leasing revenue (b) — 232 99 331 Risk management and trading activities (c) (28) 76 (3) 45 Other (13) 31 — 18 Total revenue from other sources $ 53 $ 339 $ 96 $ 488 Total revenue $ 4,980 $ 9,010 $ 97 $ 14,087 (a) 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. (b) 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. (c) 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. Year Ended December 31, 2021 Utilities Midstream Corporate/Other Total Revenue from contracts with customers Commodity sales contracts $ 1,316 $ 4,667 $ 1 $ 5,984 Midstream service contracts — 1,664 — 1,664 Gas sales and transportation services 2,582 — — 2,582 Storage services 24 — — 24 Other 8 — 4 12 Total revenue from contracts with customers $ 3,930 $ 6,331 $ 5 $ 10,266 Other sources of revenue Revenue from alternative revenue programs (a) $ 92 $ — $ — $ 92 Leasing revenue (b) — 168 102 270 Risk management and trading activities (c) (d) (74) 12 (4) (66) Other (12) 22 1 11 Total revenue from other sources $ 6 $ 202 $ 99 $ 307 Total revenue $ 3,936 $ 6,533 $ 104 $ 10,573 (a) 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. (b) 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. (c) 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. (d) WGL Midstream trading margins are reported in risk management and trading activities from the Midstream segment. Prior to the sale of the U.S. transportation and storage business in the second quarter of 2021, WGL Midstream entered 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 of WGL Midstream, including unrealized gains and losses on derivative instruments, are netted within revenues. Gross revenues for the year ended December 31, 2021 of $172 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. While the GAIL contract and AMA are individually not accounted for as derivatives, they are inseparable from the overall trading portfolio. 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 had 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. AltaGas completed the sale of the U.S. transportation and storage business, including the GAIL contract and the AMA, in April 2021.
Schedule of Contract with Customer, Asset and Liability	Contract Assets As at December 31, December 31, Balance, beginning of year $ 54 $ 71 Additions 1 — Amortization (a) (4) (4) Transfers to accounts receivable (b) (10) (13) Balance, end of year $ 41 $ 54 (a) Represents the drawdown of a contract asset under a blend-and-extend contract modification. (b) Amounts included in contract assets are transferred to accounts receivable when AltaGas’ right to consideration becomes unconditional. Contract Liabilities As at December 31, December 31, Balance, beginning of year $ 1 $ — Additions — 1 Revenue recognized from contract liabilities (a) (1) — Balance, end of year $ — $ 1
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, 2022: 2023 2024 2025 2026 2027 2028 & beyond Total Midstream service contracts $ 120 $ 120 $ 116 $ 113 $ 112 $ 784 $ 1,365 Storage services 25 25 25 25 25 106 231 Other 2 2 2 2 2 5 15 $ 147 $ 147 $ 143 $ 140 $ 139 $ 895 $ 1,611

Shareholders_ Equity (Tables)

Shareholders’ Equity (Tables)	12 Months Ended
	Dec. 31, 2022
Stockholders' Equity Note [Abstract]
Schedule of Common Shares Issued and Outstanding	Common Shares Issued and Outstanding (a) Number of Amount January 1, 2021 279,494,299 $ 6,723 Shares issued for cash on exercise of options 774,739 15 Deferred taxes on share issuance cost — (3) December 31, 2021 280,269,038 $ 6,735 Shares issued for cash on exercise of options 1,262,795 28 Deferred taxes on share issuance cost — (2) Issued and outstanding at December 31, 2022 281,531,833 $ 6,761 (a) Dividends declared per share for the year ended December 31, 2022 was $1.06 (December 31, 2021 - $1.00).
Schedule of Preferred Shares Issued and Outstanding	As at December 31, 2022 December 31, 2021 Issued and Outstanding (a) (b) Number of shares Amount Number of shares Amount Series A 6,746,679 $ 169 6,746,679 $ 169 Series B 1,253,321 31 1,253,321 31 Series C (c) — — 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 K (d) — — 12,000,000 300 Share issuance costs, net of taxes (14) (30) 24,000,000 $ 586 44,000,000 $ 1,076 (a) On January 11, 2022, in connection with the offering of the Subordinated Notes, Series 1, AltaGas issued $300 million in Preferred Shares, Series 2022-A, to be held in the AltaGas Hybrid Trust with Computershare Trust Company of Canada acting as a trustee. Refer to Notes 13 and 17 for more details. (b) On August 17, 2022, in connection with the offering of the Subordinated Notes, Series 2, AltaGas issued $250 million in Preferred Shares, Series 2022-B, to be held in the AltaGas Hybrid Trust with Computershare Trust Company of Canada acting as a trustee. Refer to Notes 13 and 17 for more details. (c) On September 30, 2022, AltaGas redeemed all of its outstanding U.S. dollar denominated Series C Preferred Shares. A loss of $74 million was recognized upon redemption, which was comprised of a $69 million foreign exchange loss and a $5 million loss related to share issuance costs for the preferred shares. (d) On March 31, 2022, AltaGas redeemed all of its outstanding Series K Preferred Shares. A loss of $10 million was recognized upon redemption related to share issuance costs for the preferred shares.
Schedule of Cumulative Redeemable Preferred Shares	The following table outlines the characteristics of the cumulative redeemable preferred shares (a) (h) (i) : Current yield Annual dividend per share (b) Redemption price per share (g) Redemption and conversion option date (c)(g) 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 E (e) 5.393 % $1.34825 $25 December 31, 2023 Series F Series G (e) 4.242 % $1.06050 $25 September 30, 2024 Series H Series H (f) (g) Floating Floating $25 September 30, 2024 Series G (a) The Corporation is authorized to issue up to 8,000,000 of Series F 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 are also redeemable for $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 E Shares, and Series G 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 F 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, 2022, the floating quarterly dividend rate is $0.41875 per share for Series B Shares and $0.44340 per share for Series H Shares for the period starting December 31, 2022 to, but excluding, March 31, 2023. (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) The Series 2022-A Shares were issued to Computershare Trust Company of Canada to be held in trust to satisfy AltaGas’ obligations under the Series 1 Indenture, in connection with the issuance of the Subordinated Notes, Series 1. Holders of the Series 2022-A Shares shall not be entitled to receive any dividends, nor shall any dividends accumulate or accrue, on the Series 2022-A Shares prior to delivery to the holders of the Subordinated Notes, Series 1 following the occurrence of certain bankruptcy or insolvency events in respect of AltaGas. If at any time, AltaGas redeems, purchases for cancellation or repays the Subordinated Notes, Series 1 such number of Series 2022-A Shares with an aggregate issue price equal to the principal amount of Subordinated Notes, Series 1 redeemed, purchased for cancellation or repaid by AltaGas will be redeemed in accordance with the terms of the Series 2022-A Shares. (i) The Series 2022-B Shares were issued to Computershare Trust Company of Canada to be held in trust to satisfy AltaGas’ obligations under the Series 2 Indenture, in connection with the issuance of the Subordinated Notes, Series 2. Holders of the Series 2022-B Shares shall not be entitled to receive any dividends, nor shall any dividends accumulate or accrue, on the Series 2022-B Shares prior to delivery to the holders of the Subordinated Notes, Series 2 following the occurrence of certain bankruptcy or insolvency events in respect of AltaGas. If at any time, AltaGas redeems, purchases for cancellation or repays the Subordinated Notes, Series 2 such number of Series 2022-B Shares with an aggregate issue price equal to the principal amount of Subordinated Notes, Series 2 redeemed, purchased for cancellation or repaid by AltaGas will be redeemed in accordance with the terms of the Series 2022-B Shares.
Schedule of Share Option Activity	The following table summarizes information about the Corporation’s share options: December 31, 2022 December 31, 2021 As at Options outstanding Options outstanding Number of Exercise price (a) Number of Exercise price (a) Share options outstanding, beginning of year 8,679,508 $ 19.98 8,362,211 $ 21.06 Granted — — 1,878,670 18.77 Exercised (1,262,795) 19.94 (774,739) 17.44 Forfeited (107,799) 26.24 (214,259) 25.24 Expired (350,775) 32.19 (572,375) 33.26 Share options outstanding, end of year 6,958,139 $ 19.28 8,679,508 $ 19.98 Share options exercisable, end of year 4,960,341 $ 19.38 4,435,287 $ 20.72 (a) Weighted average.
Schedule of Employee Share Option Plan	The following table summarizes the employee share option plan as at December 31, 2022: 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 1,739,186 $ 15.41 2.07 1,712,333 $ 15.40 2.04 $18.01 to $25.08 4,570,158 19.27 3.25 2,601,089 19.43 2.96 $25.09 to $37.86 648,795 29.70 0.72 646,919 29.71 0.71 6,958,139 $ 19.28 2.72 4,960,341 $ 19.38 2.35
Schedule 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 (a) 2022 2021 Fair value per options ($) — 3.37 Risk-free interest rate (%) — 0.42 Expected life (years) — 6 Expected volatility (%) (b) — 35.70 Annual dividend per share ($) (c) — 1.00 Forfeiture rate (%) — — (a) No options were granted in 2022. (b) Expected volatility assumptions are based on the historic daily share price volatility. (c) 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) 2022 2021 Balance, beginning of year 3,877,843 5,920,300 Granted 1,413,790 1,611,727 Vested and paid out (1,784,293) (3,495,702) Forfeited (140,150) (313,621) Units in lieu of dividends 172,563 126,250 Additional units added by performance factor 792,309 28,889 Outstanding, end of year 4,332,062 3,877,843

Net Income Per Common Share (Ta

Net Income Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Schedule of Net Income per Common Share	The following table summarizes the computation of net income per common share: Year Ended December 31 2022 2021 Numerator: Net income applicable to controlling interests $ 523 $ 283 Less: Preferred share dividends (40) (53) Loss on redemption of preferred shares (note 26) (84) — Net income applicable to common shares $ 399 $ 230 Denominator: (millions of shares) Weighted average number of common shares outstanding 281.0 279.9 Dilutive equity instruments (a) 2.3 1.8 Weighted average number of common shares outstanding - diluted 283.3 281.7 Basic net income per common share $ 1.42 $ 0.82 Diluted net income per common share $ 1.41 $ 0.82 (a) Determined using the treasury stock method.

Other Income (Tables)

Other Income (Tables)	12 Months Ended
	Dec. 31, 2022
Other Income and Expenses [Abstract]
Schedule of Other Income	Year Ended December 31 2022 2021 Gains on asset sales (note 4) $ 3 $ 6 Other components of net benefit cost (note 29) 74 64 Interest income and other revenue 17 11 Total $ 94 $ 81

Pension Plans and Retiree Ben_2

Pension Plans and Retiree Benefits (Tables)	12 Months Ended
	Dec. 31, 2022
Retirement Benefits [Abstract]
Schedule 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, 2022 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 $ 1,743 $ 430 $ 1,777 $ 432 Actuarial gain (6) — (473) (118) (479) (118) Current service cost 3 — 22 10 25 10 Member contributions — — — 3 — 3 Interest cost 1 — 52 13 53 13 Benefits paid (4) — (83) (23) (87) (23) Expenses paid — — (1) — (1) — Settlements — — (5) — (5) — Other — — — 1 — 1 Foreign exchange translation — — 98 25 98 25 $ 28 $ 2 $ 1,353 $ 341 $ 1,381 $ 343 Less: projected benefit obligation reclassified to liabilities associated with assets held for sale ( note 5) (b) — — (85) (9) (85) (9) Balance, end of year $ 28 $ 2 $ 1,268 $ 332 $ 1,296 $ 334 Plan assets Fair value, beginning of year $ 16 $ — $ 1,715 $ 1,058 $ 1,731 $ 1,058 Actual return on plan assets (3) — (374) (254) (377) (254) Employer contributions 4 — 8 — 12 — Member contributions — — — 3 — 3 Benefits paid (4) — (83) (23) (87) (23) Expenses paid — — (1) — (1) — Settlements — — (5) — (5) — Other — — — 1 — 1 Foreign exchange translation — — 99 60 99 60 $ 13 $ — $ 1,359 $ 845 $ 1,372 $ 845 Less: plan assets reclassified to assets held for sale ( note 5) (b) — — (93) (3) (93) (3) Fair value, end of year $ 13 $ — $ 1,266 $ 842 $ 1,279 $ 842 Funded status (c) $ (15) $ (2) $ 6 $ 504 $ (9) $ 502 (a) For post-retirement benefit plans, the projected benefit obligation represents the accumulated benefit obligation. (b) Presented on a net basis in Note 5. See below for specific amounts included in the Consolidated Balance Sheets. (c) Calculation includes plan assets and liabilities classified as held for sale. Year Ended December 31, 2021 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 $ 37 $ 2 $ 1,800 $ 452 $ 1,837 $ 454 Actuarial gain (4) — (39) (19) (43) (19) Current service cost 4 — 23 10 27 10 Member contributions — — — 2 — 2 Interest cost 1 — 49 12 50 12 Benefits paid (4) — (74) (25) (78) (25) Expenses paid — — (1) — (1) — Settlements — — (7) — (7) — Plan amendments — — — (1) — (1) Foreign exchange translation — — (8) (1) (8) (1) Balance, end of year $ 34 $ 2 $ 1,743 $ 430 $ 1,777 $ 432 Plan assets Fair value, beginning of year $ 16 $ — $ 1,667 $ 1,016 $ 1,683 $ 1,016 Actual return on plan assets — — 125 67 125 67 Employer contributions 4 — 11 — 15 — Member contributions — — — 2 — 2 Benefits paid (4) — (74) (23) (78) (23) Expenses paid — — (1) — (1) — Settlements — — (7) — (7) — Foreign exchange translation — — (6) (4) (6) (4) Fair value, end of year $ 16 $ — $ 1,715 $ 1,058 $ 1,731 $ 1,058 Funded status $ (18) $ (2) $ (28) $ 628 $ (46) $ 626 (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, 2022 December 31, 2021 Defined Benefit Post- Retirement Benefits Total Defined Benefit Post-Retirement Benefits Total Prepaid post-retirement benefits $ 28 $ 510 $ 538 $ 37 $ 637 $ 674 Assets held for sale ( note 5) 8 — 8 — — — Accounts payable and accrued liabilities (a) (3) — (3) (8) — (8) Future employee obligations (42) (2) (44) (75) (11) (86) Liabilities associated with assets held for sale ( note 5) — (6) (6) — — — $ (9) $ 502 $ 493 $ (46) $ 626 $ 580
Schedule of Funded Status Based on Accumulated Benefit Obligation	The accumulated benefit obligation for all defined benefit plans were: As at December 31, 2022 December 31, 2021 Canada United States Canada United States Accumulated benefit obligation (a) $ 27 $ 1,307 $ 33 $ 1,659 (a) Accumulated benefit obligation differs from projected benefit obligation in that it does not include an assumption with respect to future compensation levels.
Schedule of 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, 2022, the cumulative obligation and asset balances were: As at December 31, 2022 December 31, 2021 Defined Benefit Post-Retirement Benefits Defined Post-Retirement Benefits Projected benefit obligation $ 49 $ 11 $ 375 $ 14 Plan assets $ 3 $ 3 $ 289 $ 3 For those pension plans where the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2022, the cumulative obligation and asset balances were: As at December 31, 2022 December 31, 2021 Defined Benefit Post-Retirement Benefits Defined Post-Retirement Benefits Accumulated benefit obligation $ 48 $ 11 $ 221 $ 14 Plan assets $ 3 $ 3 $ 158 $ 3
Schedule 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, 2022 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Past service cost $ — $ — $ — $ (1) $ — $ (1) Net actuarial loss (2) — — (3) (2) (3) Recognized in AOCI pre-tax $ (2) $ — $ — $ (4) $ (2) $ (4) Increase by the amount — — — 1 — 1 Net amount in AOCI after-tax $ (2) $ — $ — $ (3) $ (2) $ (3) Year Ended December 31, 2021 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service cost $ — $ — $ — $ (2) $ — $ (2) Net actuarial gain (loss) (5) (1) 4 (6) (1) (7) Recognized in AOCI pre-tax $ (5) $ (1) $ 4 $ (8) $ (1) $ (9) Increase (decrease) by the amount 1 — (1) 2 — 2 Net amount in AOCI after-tax $ (4) $ (1) $ 3 $ (6) $ (1) $ (7)
Schedule 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, 2022 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit $ — $ — $ — $ (64) $ — $ (64) Net actuarial gain — — (47) (123) (47) (123) $ — $ — $ (47) $ (187) $ (47) $ (187) Less: regulatory asset (liability) reclassified to assets (liabilities associated with assets) held for sale — — (3) 3 (3) 3 Recognized in regulatory liability $ — $ — $ (50) $ (184) $ (50) $ (184) Year Ended December 31, 2021 Canada United States Total Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Defined Benefit Post- Retirement Benefits Past service credit $ — $ — $ — $ (77) $ — $ (77) Net actuarial gain — — (26) (289) (26) (289) Recognized in regulatory liability $ — $ — $ (26) $ (366) $ (26) $ (366)
Schedule of Net Periodic Benefit Expense	The net pension expense by plan was as follows: Year Ended December 31, 2022 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 3 $ — $ 22 $ 10 $ 25 $ 10 Interest cost (b) 1 — 52 13 53 13 Expected return on plan assets (b) — — (79) (38) (79) (38) Amortization of past service credit (b) — — — (18) — (18) Amortization of net actuarial loss (gain) (b) — — 2 (7) 2 (7) Net benefit cost (income) recognized $ 4 $ — $ (3) $ (40) $ 1 $ (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. Year Ended December 31, 2021 Canada United States Total Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Current service cost (a) $ 4 $ — $ 23 $ 10 $ 27 $ 10 Interest cost (b) 1 — 49 12 50 12 Expected return on plan assets (b) (1) — (76) (34) (77) (34) Amortization of past service credit (b) — — — (18) — (18) Amortization of net actuarial loss (gain) (b) 1 — 6 (6) 7 (6) Plan settlements (b) — — 2 — 2 — Net benefit cost (income) recognized $ 5 $ — $ 4 $ (36) $ 9 $ (36) (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 defined benefit plans are as follows as at December 31, 2022 and December 31, 2021: Year Ended December 31, 2022 Canada Fair value Level 1 Level 2 Percentage of Plan Assets (%) December 31, 2022 Cash and short-term equivalents $ 2 $ 2 $ — 15 Fixed income Canadian bonds 11 $ 11 $ — 85 $ 13 $ 13 $ — 100 December 31, 2021 Cash and short-term equivalents $ 2 $ 2 $ — 13 Fixed income Canadian bonds 14 14 — 87 $ 16 $ 16 $ — 100 Year Ended December 31, 2022 United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) December 31, 2022 Cash and short-term equivalents $ 2 $ 2 $ — — Canadian equities 2 2 — — Foreign equities (a) 247 247 — 20 Fixed income Government debt 413 80 333 33 Corporate debt 355 30 325 28 Derivatives 2 — 2 — Other (b) 11 — 11 1 Total investments in the fair value hierarchy $ 1,032 $ 361 $ 671 82 Investments measured at net asset value using the NAV practical expedient (c) Pooled separate accounts (d) $ 43 3 Collective trust funds (e) 279 22 Total fair value of plan investments $ 1,354 107 Net receivable (f) 5 — $ 1,359 107 Less: investments reclassified to assets held for sale (93) (7) $ 1,266 100 December 31, 2021 Cash and short-term equivalents $ 2 $ 2 $ — — Canadian equities 2 2 — — Foreign equities (a) 290 290 — 17 Fixed income Government debt 346 39 307 20 Corporate debt 502 79 423 30 Derivatives 6 — 6 — Other (b) 11 — 11 1 Total investments in the fair value hierarchy $ 1,159 $ 412 $ 747 68 Investments measured at net asset value using the NAV practical expedient (c) Private equity/limited partnership (g) $ 46 3 Pooled separate accounts (d) 38 2 Collective trust funds (e) 467 27 Total fair value of plan investments $ 1,710 100 Net receivable (f) 5 — $ 1,715 100 (a) Consists of investments in foreign equities include U.S. and international securities. (b) As at December 31, 2022 and December 31, 2021, these investments consisted primarily of non-U.S. government bonds and asset-backed securities. (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, 2022, investments in pooled separate accounts consisted of 100 percent income producing properties located in the United States (December 31, 2021 - 100 percent). (e) As at December 31, 2022, investments in collective trust funds consisted primarily of 79 percent common stock of U.S. companies (December 31, 2021 - 91 percent), 16 percent income producing properties located in the United States (December 31, 2021 - 9 percent), and 5 percent of short-term money market investments (December 31, 2021 - nil). (f) As at December 31, 2022 and December 31, 2021, this net receivable primarily represents pending trades for investments sold and interest receivable net of pending trades for investments purchased. (g) As at December 31, 2021, investments in a private equity/limited partnership consisted of common stock of international companies. The collective investment mixes for the post-retirement benefit plans are as follows as at December 31, 2022 and December 31, 2021: United States Fair value Level 1 Level 2 Percentage of Plan Assets (%) December 31, 2022 Cash and short-term equivalents $ 8 $ 8 $ — 1 Foreign equities (a) 50 50 — 6 Fixed income Government debt 101 21 80 12 Corporate debt 85 8 77 10 Other (b) 5 — 5 1 Total investments in the fair value hierarchy $ 249 $ 87 $ 162 30 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 596 71 Total fair value of plan investments $ 845 101 Less: investments reclassified to assets held for sale (3) (1) $ 842 100 December 31, 2021 Cash and short-term equivalents $ 6 $ 6 $ — 1 Foreign equities (a) 60 60 — 6 Fixed income Government debt 104 10 94 10 Corporate debt 122 20 102 11 Other (b) 6 — 6 1 Total investments in the fair value hierarchy $ 298 $ 96 $ 202 29 Investments measured at net asset value using the NAV practical expedient (c) Commingled funds (d) $ 760 71 $ 1,058 100 (a) Consists of investments in foreign equities include U.S. and international securities. (b) As at December 31, 2022 and December 31, 2021, 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, 2022, investments in commingled funds consisted of approximately 49 percent common stock of large-cap U.S. companies (December 31, 2021 - 51 percent), 23 percent U.S. Government fixed income securities (December 31, 2021 - 21 percent), and 28 percent corporate bonds for WGL’s post-retirement benefit plans (December 31, 2021 - 28 percent).
Schedule of Significant Actuarial Assumptions Used in Measuring Net Benefit Plan Costs and Benefit Obligations	Year Ended December 31 2022 2021 Significant actuarial assumptions used in measuring net benefit plan costs Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 2.50 - 5.05 3.10 1.90 - 2.85 2.50 - 3.10 Expected long-term rate of return on plan assets (%) (a) 2.83 - 6.50 3.00 - 6.50 4.75 - 7.00 3.37 - 7.00 Rate of compensation increase (%) 2.50 - 4.00 3.00 1.00 - 4.00 2.50 - 3.00 (a) Only applicable for funded plans As at December 31 2022 2021 Significant actuarial assumptions used in measuring benefit obligations Defined Benefit Post-Retirement Benefits Defined Benefit Post-Retirement Benefits Discount rate (%) 5.05 - 5.60 5.30 - 5.70 2.50 - 3.10 3.10 Rate of compensation increase (%) 2.50 - 4.00 3.00 2.50 - 4.00 3.00
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: 2023 $ 8 $ — Expected benefit payments: 2023 $ 95 $ 23 2024 $ 94 $ 22 2025 $ 96 $ 22 2026 $ 97 $ 23 2027 $ 98 $ 23 2028 - 2032 $ 501 $ 119

Commitments, Guarantees, and _2

Commitments, Guarantees, and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Payment Commitments	Future payments of these commitments as at December 31, 2022 are estimated as follows: 2023 2024 2025 2026 2027 2028 & beyond Total Gas purchase (a) (b) $ 1,433 $ 1,209 $ 1,088 $ 1,014 $ 1,004 $ 3,406 $ 9,154 Pipeline and storage services (b) (c) 474 428 392 347 303 749 2,693 LPG purchase (d) 431 336 251 173 150 194 1,535 Electricity purchase (e) 869 616 231 56 16 2 1,790 Operating leases (f) 101 96 81 72 56 156 562 Service agreements (g) (h) (i) 76 53 47 38 29 251 494 Environmental (j) 10 1 1 1 — — 13 Post-acquisition contingent payments (k) 5 — — — — — 5 Crude oil and condensate purchase (l) 14 — — — — — 14 Merger commitments (m) 5 2 1 1 1 — 10 Capital projects (n) 32 — — — — — 32 $ 3,450 $ 2,741 $ 2,092 $ 1,702 $ 1,559 $ 4,758 $ 16,302 (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. Pursuant to the May 26, 2022 announcement of the Alaska Utilities Disposition, $2.6 billion of the gas purchase commitments are associated with the assets held for sale at December 31, 2022. The transaction closed on March 1, 2023. Refer to Notes 5 and 34 for more details. (b) Excludes an estimated US$7.6 billion of natural gas purchases through 2033 and US$1 billion of pipeline contracts through 2043 that are contingent on the in-service date of the Mountain Valley Pipeline. (c) Pipeline and storage commitments include minimum payments for natural gas transportation, storage and peaking contracts that have expiration dates through 2044. (d) 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. (e) 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$78 million of commitments related to renewable energy credits. (f) 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. Operating leases also include $203 million in future undiscounted cash flows associated with leasing arrangements for the use of Very Large Gas Carriers (VLGCs) that are anticipated to commence between 2023 and 2024 and $11 million in future discounted cash flows associated with leasing arrangements for rail cars commencing in 2023. (g) 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, 2022, the total commitment was $148 million payable over the next 13 years, of which $53 million is expected to be paid over the next 5 years. (h) In 2017, AltaGas entered into a 12-year service agreement commencing in 2019 for tug services to support the marine operations of RIPET. (i) In 2015, AltaGas entered into a Project Agreement that contemplated the sublease of lands from Ridley Terminals Inc. (RTI, now Trigon Pacific Terminals Ltd. (Trigon)), provision of certain terminal services, and access to Trigon's terminal facilities to support RIPET's operations for an initial term of 20 years ending in 2039. In 2019, RILE LP and Trigon executed a Terminal Services Agreement that formalized the concepts outlined in the Project Agreement. (j) Environmental commitments include committed payments related to certain environmental response costs. (k) Relating to certain air-related violations at the Ferndale terminal. The penalty was paid in full in February 2023. (l) AltaGas enters into 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. (m) Represents the estimated future payments of WGL merger commitments that have been accrued but not paid. Among other things, these commitments include rate credits distributable to both residential and non-residential customers to partially offset rate increases resulting from gas expansion, extension of natural gas service over a 10-year period and other programs, various public interest commitments, and safety programs. As at December 31, 2022, the cumulative amount of merger commitments that have been expensed but not yet paid is approximately US$8 million. Additionally, there are a number of operational commitments with various timeframes, including the funding of leak mitigation and reducing leak backlogs, the funding of damage prevention efforts, developing projects to extend natural gas service, maintaining pre-merger quality of service standards including odor call response times, increasing supplier diversity, achieving synergy savings benefits, as well as reporting and tracking related to certain commitments, and causing the development of 15 MW of either electric grid energy storage or tier one renewable resources. (n) Commitments for capital projects. Estimated amounts are subject to variability depending on the actual construction costs.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Schedule 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, 2022 December 31, 2021 Due from related parties Accounts receivable (a) $ 1 $ 7 Due to related parties Accounts payable (b) $ 1 $ 7 (a) Receivables from affiliates. (b) Payables to affiliates.
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, 2022 and 2021: Year Ended December 31 2022 2021 Cost of sales (a) $ 7 $ 6

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2022
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 2022 2021 Source (use) of cash: Accounts receivable $ (691) $ (206) Inventory (324) (232) Risk management assets - current 4 4 Other current assets (1) 4 Regulatory assets - current 13 (3) Accounts payable and accrued liabilities 377 92 Customer deposits 14 27 Regulatory liabilities - current 98 (12) Risk management liabilities - current (6) (1) Other current liabilities (12) 21 Other operating assets and liabilities (122) (104) Changes in operating assets and liabilities $ (650) $ (410)
Schedule of Supplemental Cash Payments	The following table details the changes in non-cash investing and financing activities: Year Ended 2022 2021 Decrease (increase) of balance: Exercise of stock options $ 3 $ 2 Common share dividends payable $ — $ 22 Net right-of-use assets obtained in exchange for new operating lease liabilities $ (56) $ (38) Net right-of-use assets obtained in exchange for new finance lease liabilities $ (14) $ (10) Capital expenditures included in accounts payable and accrued liabilities $ 6 $ 33 The following cash payments have been included in the determination of earnings: Year Ended 2022 2021 Interest paid (net of capitalized interest) $ 304 $ 279 Income taxes paid $ 17 $ 69
Schedule of Reconciliation of Cash and Restricted Cash Balances	The following table is a reconciliation of cash and restricted cash balances: As at December 31 2022 2021 Cash and cash equivalents $ 53 $ 63 Restricted cash holdings from customers - current — 3 Restricted cash included in prepaid expenses and other current assets (a) 3 8 Restricted cash included in long-term investments and other assets (note 12) (a) 8 10 Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows $ 64 $ 84 (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 29).

Segmented Information (Tables)

Segmented Information (Tables)	12 Months Ended
	Dec. 31, 2022
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. The sale of the Alaskan Utilities closed on March 1, 2023; n rate-regulated natural gas storage in the United States, of which certain storage facilities in Alaska were sold on March 1, 2023, pursuant to the Alaska Utilities Disposition; and n sale of energy 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) export terminals; n transmission pipelines to transport natural gas and NGLs; 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, 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.
Schedule of Reconciliation of Segment Revenue	The following table provides a reconciliation of segment revenue to the disaggregated revenue table disclosed in Note 25: Year Ended December 31, 2022 Utilities Midstream Corporate/Other Total External revenue (note 25) $ 4,980 $ 9,010 $ 97 $ 14,087 Segment revenue $ 4,980 $ 9,010 $ 97 $ 14,087 Year Ended December 31, 2021 Utilities Midstream Corporate/Other Total External revenue (note 25) $ 3,936 $ 6,533 $ 104 $ 10,573 Intersegment revenue — 2 — 2 Segment revenue $ 3,936 $ 6,535 $ 104 $ 10,575
Schedule of Geographic Information	Geographic Information Year Ended December 31 2022 2021 Revenue (a) Canada $ 8,915 $ 6,420 United States 5,155 4,304 Total $ 14,070 $ 10,724 (a) Operating revenue from external customers, excluding unrealized gains or losses on risk management contracts. As at December 31 2022 2021 Property, plant and equipment Canada $ 2,930 $ 3,109 United States 8,756 8,214 Total $ 11,686 $ 11,323 Operating right-of-use assets Canada $ 212 $ 239 United States 69 72 Total $ 281 $ 311
Schedule of Segment Composition	The following tables show the composition by segment: Year Ended December 31, 2022 Utilities Midstream Corporate/Other Intersegment Elimination Total Segment revenue (note 25) $ 4,980 $ 9,010 $ 97 $ — $ 14,087 Cost of sales (3,197) (7,915) (26) — (11,138) Operating and administrative (1,023) (461) (84) — (1,568) Accretion expenses (1) (6) — — (7) Depreciation and amortization (290) (116) (33) — (439) Provisions on assets (note 6) — (6) — — (6) Income from equity investments 2 11 — — 13 Other income 77 9 8 — 94 Foreign exchange gains — — 10 — 10 Interest expense — — (330) — (330) Income (loss) before income taxes $ 548 $ 526 $ (358) $ — $ 716 Net additions (reductions) to: Property, plant and equipment (a) $ 822 $ (117) $ (10) $ — $ 695 Intangible assets $ 2 $ 6 $ 1 $ — $ 9 (a) 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, 2021 Utilities Midstream Corporate/Other Intersegment Elimination Total Segment revenue (note 25) $ 3,936 $ 6,535 $ 104 $ (2) $ 10,573 Cost of sales (2,273) (5,412) (25) 2 (7,708) Operating and administrative (906) (475) (95) — (1,476) Accretion expenses (1) (6) 1 — (6) Depreciation and amortization (285) (104) (33) — (422) Provision on assets (note 6) — (59) (5) — (64) Income (loss) from equity investments 2 (263) — — (261) Other income 65 16 — — 81 Foreign exchange gains (losses) — 10 (6) — 4 Interest expense — — (275) — (275) Income (loss) before income taxes $ 538 $ 242 $ (334) $ — $ 446 Net additions (reductions) to: Property, plant and equipment (a) $ 705 $ (284) $ 8 $ — $ 429 Intangible assets $ 2 $ 2 $ 2 $ — $ 6 (a) 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, 2022 Goodwill $ 3,718 $ 1,532 $ — $ 5,250 Segmented assets $ 16,782 $ 6,728 $ 455 $ 23,965 As at December 31, 2021 Goodwill $ 3,691 $ 1,462 $ — $ 5,153 Segmented assets $ 14,603 $ 6,415 $ 575 $ 21,593

Organization and Overview of _2

Organization and Overview of the Business (Details) customer in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2022 USD ($) customer MW
Organization And Overview Of Business [Line Items]
Utilities customers, base rate | $	$ 5.2
Number of megawatts of power | MW	508
Utilities
Organization And Overview Of Business [Line Items]
Number of customers | customer	1.7
Midstream | CINGSA
Organization And Overview Of Business [Line Items]
Equity method investment, ownership interest (percent)	65%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2022
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	1 year
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	43 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Finite-Lived Intangible Assets (Details)	12 Months Ended
	Dec. 31, 2022
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
E&T contracts
Finite-Lived Intangible Assets
Intangible asset, useful life	25 years
Commodity contracts | Maximum
Finite-Lived Intangible Assets
Intangible asset, useful life	7 years

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Share Options and Other Compensation Plans (Details) - Performance units	12 Months Ended
	Dec. 31, 2022
Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Performance multiplier	0%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Performance multiplier	200%

Acquisitions - Narrative (Detai

Acquisitions - Narrative (Details) - CAD ($) $ in Millions		12 Months Ended
	Jul. 05, 2022	Dec. 31, 2022	Dec. 31, 2021
Contributed surplus
Business Acquisition
Purchase of remaining non-controlling interest in subsidiaries (note 3)			$ 0
Petrogas Energy Corporation
Business Acquisition
Additional ownership interest acquired (as a percent)	25.97%
Cash consideration	$ 285
AOCI including portion attributable to noncontrolling interest, period increase (decrease)		$ 5
Total ownership interest in acquiree (as a percent)		100%
Petrogas Energy Corporation | Contributed surplus
Business Acquisition
Purchase of remaining non-controlling interest in subsidiaries (note 3)		$ 237

Dispositions (Details)

Dispositions (Details) - Disposal by sale $ in Millions, $ in Millions			1 Months Ended	3 Months Ended		12 Months Ended
	May 27, 2022 CAD ($) MW	Apr. 12, 2022 CAD ($)	Feb. 28, 2023 USD ($)	Mar. 31, 2022 CAD ($) MW	Mar. 31, 2022 USD ($) MW	Dec. 31, 2022 CAD ($)
Energy Storage Development Project
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Number of megawatts sold | MW				60	60
Proceeds from disposition of business				$ 20	$ 15
Gain (loss) on disposal of business				$ 7
Energy Storage Development Project | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition of business			$ 8
Aitken Creek Processing Facilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition of business		$ 224
Gain (loss) on disposal of business						$ 1
Brush II
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Number of megawatts sold | MW	70
Proceeds from disposition of business	$ 1
Gain (loss) on disposal of business						$ (2)

Assets Held For Sale - Schedule

Assets Held For Sale - Schedule of Assets Held for Sale (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Liabilities associated with assets held for sale
Accounts receivable, allowance for credit loss	$ 42	$ 40
Held for sale | Alaskan Utilities
Assets held for sale
Accounts receivable (net of credit losses of $1 million) (note 24)	93	0
Inventory	86	0
Restricted cash holdings from customers	1	0
Prepaid expenses and other current assets	6	0
Property, plant and equipment	646	0
Intangible assets	5	0
Operating right-of-use assets	1	0
Goodwill	226	0
Regulatory assets - non-current	14	0
Post retirement benefits	8	0
Long-term investments and other assets	1	0
Total assets held for sale	1,087	0
Liabilities associated with assets held for sale
Accounts payable and accrued liabilities	59	0
Current portion of long-term debt	7	0
Customer deposits	13	0
Long-term debt	56	0
Asset retirement obligations	4	0
Regulatory liabilities - non-current	96	0
Operating lease liabilities - non-current	1	0
Other long-term liabilities	53	0
Future employee obligations	6	0
Total liabilities associated with assets held for sale	$ 295	$ 0

Assets Held For Sale - Narrativ

Assets Held For Sale - Narrative (Details) - Held for sale - Alaskan Utilities $ in Millions, $ in Millions	May 26, 2022 CAD ($)	May 26, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations
Proceeds from disposition of business	$ 1,100	$ 800
Assets held for sale			$ 1,087	$ 0
Liabilities held for sale			$ 295	$ 0

Provisions on Assets - Schedule

Provisions on Assets - Schedule of Provisions on Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Provisions On Assets Disclosure
Provisions on assets	$ 6	$ 64
Midstream
Provisions On Assets Disclosure
Provisions on assets	6	59
Corporate/Other
Provisions On Assets Disclosure
Provisions on assets	$ 0	$ 5

Provisions on Assets - Narrativ

Provisions on Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Provisions On Assets Disclosure
Provisions on assets (note 6)	$ 6	$ 64
Midstream
Provisions On Assets Disclosure
Provisions on assets (note 6)	6	59
Corporate/Other
Provisions On Assets Disclosure
Provisions on assets (note 6)	$ 0	$ 5

Inventory - Schedule of Invento

Inventory - Schedule of Inventory (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	May 26, 2022	Dec. 31, 2021
Inventory [Line Items]
Natural gas held in storage	$ 588	$ 72	$ 341
Natural gas liquids	197		175
Materials and supplies	76		70
Renewable energy credits and emission compliance instruments	127		82
Crude oil and condensate	152		109
Processed finished products	6		5
Inventory, Gross, Total	1,146		782
Inventory Adjustments	(86)		0
Total inventory	1,060		782
Inventory Write-down	5
Rate Regulated Utilities
Inventory [Line Items]
Natural gas held in storage	$ 520		$ 304

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment
Cost	$ 13,371	$ 13,170
Accumulated amortization	(1,685)	(1,847)
Property, plant and equipment (note 8)	11,686	11,323
Held for sale
Property, Plant and Equipment Assets Held-for-sale Disclosure [Abstract]
Cost	(1,124)	0
Accumulated amortization	478	0
Net book value	(646)	0
Utilities
Property, Plant and Equipment
Cost	9,806	8,432
Accumulated amortization	(614)	(437)
Property, plant and equipment (note 8)	9,192	7,995
Midstream
Property, Plant and Equipment
Cost	3,810	3,898
Accumulated amortization	(884)	(793)
Property, plant and equipment (note 8)	2,926	3,105
Corporate/Other
Property, Plant and Equipment
Cost	879	840
Accumulated amortization	(665)	(617)
Property, plant and equipment (note 8)	$ 214	$ 223

Property, Plant and Equipment_2

Property, Plant and Equipment - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Interest capitalized	$ 1	$ 1
Capital projects under construction	571	570
Depreciation expense	$ 375	$ 365

Intangible Assets - Schedule of

Intangible Assets - Schedule of Intangible Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Finite-Lived Intangible Assets
Cost	$ 460	$ 455
Accumulated amortization	(340)	(284)
Net book value	120	171
Held for sale
Finite-Lived Intangible Assets
Cost	30	0
Accumulated amortization	(25)	0
Net book value	5	0
E&T contracts
Finite-Lived Intangible Assets
Cost	26	26
Accumulated amortization	(18)	(17)
Net book value	8	9
Energy services relationships
Finite-Lived Intangible Assets
Cost	96	90
Accumulated amortization	(86)	(63)
Net book value	10	27
Software
Finite-Lived Intangible Assets
Cost	359	331
Accumulated amortization	(255)	(203)
Net book value	104	128
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	8	7
Accumulated amortization	(6)	(1)
Net book value	$ 2	$ 6

Intangible Assets - Narratives

Intangible Assets - Narratives (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense	$ 64	$ 57
Assets excluded from asset base subject to amortization	$ 6	$ 7

Intangible Assets - Schedule _2

Intangible Assets - Schedule of Estimated Amortization Expense of Intangible Assets (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2023	$ 46
2024	33
2025	29
2026	1
2027	1
Thereafter	$ 4

Leases - Schedule of Components

Leases - Schedule of Components of Lease Cost (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lease, Cost
Operating lease cost (includes variable lease payments)	$ 100	$ 96
Amortization of right-of-use assets	7	6
Interest on lease liabilities	1	0
Total finance lease cost	8	6
Total lease cost	$ 108	$ 102

Leases - Schedule of Supplement

Leases - Schedule of Supplemental Cashflow Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows used by operating leases	$ (111)	$ (96)
Financing cash flows from finance leases	(8)	(6)
Right-of-use assets obtained in exchange for new lease liabilities
Operating leases	56	38
Finance leases	$ 14	$ 10

Leases - Schedule of Suppleme_2

Leases - Schedule of Supplemental Balance Sheet Location (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Operating lease right-of-use assets
Long-term	$ 281	$ 311
Included in assets held for sale (note 5)	1
Total operating lease right-of-use assets	282	311
Operating lease liabilities
Current	(92)	(91)
Long-term	(215)	(253)
Included in liabilities associated with assets held for sale (note 5)	(1)	0
Total operating lease liabilities	(308)	(344)
Finance Leases
Property and equipment, gross	46	29
Accumulated depreciation	(21)	(12)
Total property and equipment, net	25	17
Less: finance lease property and equipment reclassified to assets held for sale (note 5)	(3)	0
Property and equipment, net	22	17
Current portion of long-term debt	(8)	(6)
Long-term debt	(17)	(11)
Total finance lease liabilities	(25)	(17)
Less: finance lease liabilities reclassified to liabilities associated with assets held for sale (note 5)	3	0
Finance lease liabilities	$ (22)	$ (17)
Weighted average remaining lease term (years)
Operating leases	6 years 4 months 24 days	6 years 10 months 24 days
Finance leases	4 years 6 months	4 years 3 months 18 days
Weighted average discount rate (%)
Operating leases	2.91%	2.45%
Finance leases (percent)	3.29%	2.23%

Leases - Schedule of Future Lea

Leases - Schedule of Future Lease Liability for Operating and Finance Lease (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Operating Leases
2023	$ 95
2024	65
2025	50
2026	41
2027	25
Thereafter	73
Total lease payments	349
Less: imputed interest	(41)
Total	308	$ 344
Finance Leases
2023	8
2024	7
2025	5
2026	4
2027	2
Thereafter	2
Total lease payments	28
Less: imputed interest	(3)
Total	$ (25)	$ (17)

Leases - Schedule of Operating

Leases - Schedule of Operating Lease Receivables (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Operating Leases
2023	$ 73
2024	2
2025	2
2026	2
2027	1
Thereafter	76
Total	$ 156

Leases - Narrative (Details)

Leases - Narrative (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Leases [Abstract]
Carrying value of property plant and equipment associated with leases	$ 203

Goodwill - Schedule of Goodwill

Goodwill - Schedule of Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Goodwill
Balance, beginning of year	$ 5,153	$ 5,039
Adjustment to goodwill on business acquisition	0	147
Goodwill included in dispositions	0	(13)
Reclassified to assets held for sale (note 5)	(226)	0
Foreign exchange translation	323	(20)
Balance, end of year	$ 5,250	$ 5,153

Long-Term Investments and Oth_3

Long-Term Investments and Other Assets - Schedule of Long-Term and Other Investments (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Investments, All Other Investments [Abstract]
Deferred lease receivable	$ 17	$ 15
Debt issuance costs associated with credit facilities	7	8
Refundable deposits	10	9
Prepayment on long-term service agreements	79	72
Deferred information technology costs	24	6
Cash calls from joint venture partners	21	23
Contract asset (net of credit losses of $1 million) (notes 24 and 25)	37	41
Rabbi trust (notes 29 and 32)	8	10
Capitalized contract costs	5	5
Financial transmission rights	39	17
Other	27	21
Investments and Other Non Current Assets, Gross	274	227
Less: long-term investments and other assets reclassified to assets held for sale (note 5)	(1)	0
Long-term investments and other assets (net of credit losses of $1 million) (notes 12, 29, and 32)	273	227
Contract assets, allowance for credit loss	$ 1	$ 1

Variable Interest Entities - Na

Variable Interest Entities - Narratives (Details)	May 05, 2017	Dec. 31, 2022 CAD ($) cavern	Aug. 17, 2022 CAD ($) shares	Jul. 05, 2022	Jul. 04, 2022	Jan. 11, 2022 CAD ($) shares	Dec. 31, 2021 CAD ($)
Variable Interest Entity
Investments accounted for by the equity method (note 14)		$ 654,000,000					$ 623,000,000
Number Of Underground Storage Salt Caverns | cavern		5
Petrogas Energy Corporation
Variable Interest Entity
Additional ownership interest acquired (as a percent)				25.97%
Strathcona Storage LP
Variable Interest Entity
Equity method investment, ownership interest (percent)				40%	30%
Strathcona Storage LP | Canada
Variable Interest Entity
Equity method investment, ownership interest (percent)				40%	30%
Investments accounted for by the equity method (note 14)		$ 130,000,000					$ 131,000,000
Altagas LPG | RILE LP
Variable Interest Entity
VIE ownership percentage	70%
Vopak | RILE LP
Variable Interest Entity
VIE ownership percentage	30%
AltaGas Hybrid Trust | Series A
Variable Interest Entity
Preferred stock, shares issued | shares						300,000,000
AltaGas Hybrid Trust | Series B
Variable Interest Entity
Preferred stock, shares issued | shares			250,000,000
AltaGas Hybrid Trust | Fixed-to-Fixed Rate Subordinated Notes, Series 1
Variable Interest Entity
Debt face amount						$ 300,000,000
Debt instrument, stated rate (as a percent)						5.25%
AltaGas Hybrid Trust | Fixed-to-Fixed Rate Subordinated Notes, Series 2
Variable Interest Entity
Debt face amount			$ 250,000,000
Debt instrument, stated rate (as a percent)			7.35%

Variable Interest Entities - Sc

Variable Interest Entities - Schedule of VIE Amounts in Consolidated Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Variable Interest Entity
Current assets	$ 4,638	$ 2,624
Property, plant and equipment	11,686	11,323
Long-term investments and other assets	273	227
Current liabilities	(3,407)	(2,657)
Asset retirement obligations	(458)	(436)
VIE
Variable Interest Entity
Current assets	12	6
Property, plant and equipment	353	357
Long-term investments and other assets	45	47
Current liabilities	(16)	(8)
Asset retirement obligations	(4)	(3)
Net assets	$ 390	$ 399

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, 2022	Dec. 31, 2021	Jul. 05, 2022	Jul. 04, 2022
Schedule of Equity Method Investments
Equity method investment	$ 654	$ 623
Income from equity investments	$ 13	(261)
Petrogas Energy Corporation
Schedule of Equity Method Investments
Additional ownership interest acquired (as a percent)			25.97%
Petrogas Terminals Penn LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)			50%	37%
Strathcona Storage LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)			40%	30%
United States | Constitution Pipeline, LLC (Constitution)
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	10%
Equity method investment	$ 0	0
Income from equity investments	$ 3	0
United States | Eaton Rapids Gas Storage System
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50%
Equity method investment	$ 28	27
Income from equity investments	$ 3	2
United States | Mountain Valley Pipeline, LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	10%
Equity method investment	$ 478	447
Income from equity investments	$ 0	(271)
United States | Petrogas Terminals Penn LLC
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50%
Equity method investment	$ 1	1
Income from equity investments	$ 0	0
Canada | Sarnia Airport Storage Pool LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)	50%
Equity method investment	$ 17	17
Income from equity investments	1	1
Canada | Strathcona Storage LP
Schedule of Equity Method Investments
Equity method investment, ownership interest (percent)			40%	30%
Equity method investment	130	131
Income from equity investments	$ 6	$ 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, 2022	Dec. 31, 2021
Schedule of Equity Method Investments
Revenues	$ 14,087	$ 10,573
Cost of sales	(11,138)	(7,708)
Current assets	4,638	2,624
Property, plant and equipment	11,686	11,323
Long-term investments and other assets	273	227
Current liabilities	(3,407)	(2,657)
Other long-term liabilities	(122)	(134)
Equity Method Investment, Nonconsolidated Investee or Group of Investees
Schedule of Equity Method Investments
Revenues	50	97
Cost of sales	(26)	(23)
Gross profit	24	74
Current assets	136	206
Property, plant and equipment	9,544	8,571
Long-term investments and other assets	12	3
Current liabilities	(166)	(214)
Other long-term liabilities	$ (14)	$ (12)

Short-term Debt - Schedule of S

Short-term Debt - Schedule of Short-Term Debt (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Commercial paper	$ 293	$ 161
Project financing	0	8
Short-term debt	$ 293	$ 169
Weighted average interest rate on short-term borrowings outstanding (as a percent)	4.80%	0.30%

Short-term Debt - Narrative (De

Short-term Debt - Narrative (Details)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)
Short-term Debt
Short-term debt (notes 15 and 24)	$ 293,000,000		$ 169,000,000
Commercial paper	293,000,000		161,000,000
Unsecured Bilateral Demand Facility | Letter of Credit
Short-term Debt
Credit facility maximum borrowing capacity		$ 300,000,000		$ 200,000,000
Amount outstanding	181,000,000		139,000,000
Demand Letter Credit Facility | Letter of Credit
Short-term Debt
Short-term debt (notes 15 and 24)			125,000,000
Letters of credit outstanding			99,000,000
Revolving Letter of Credit Facility
Short-term Debt
Credit facility maximum borrowing capacity	30,000,000		30,000,000
Letters of credit outstanding	16,000,000		7,000,000
Operating Facility
Short-term Debt
Credit facility maximum borrowing capacity		25,000,000		25,000,000
Letters of credit outstanding		$ 0		$ 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		$ 34,000,000

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-Term Debt (Details)	3 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)
Debt Instrument
Fair value adjustment on WGL Acquisition (note 3)	$ 79,000,000		$ 77,000,000
Finance lease liabilities (note 10)	25,000,000		17,000,000
Long-term debt including lease obligations	9,132,000,000		8,239,000,000
Less: debt issuance costs	(41,000,000)		(44,000,000)
Total long-term debt	9,091,000,000		8,195,000,000
Less: current portion	(334,000,000)		(511,000,000)
Less: liabilities associated with assets held for sale (note 5) (e)	(63,000,000)		0
Long-term debt, noncurrent	8,694,000,000		7,684,000,000
$450 million term loan
Debt Instrument
Debt face amount	450,000,000
Long-term debt, gross	450,000,000		0
$500 million Senior unsecured - 2.61 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 500,000,000
Debt instrument rate (as a percent)	2.61%	2.61%
Long-term debt, gross	$ 0		500,000,000
$300 million Senior unsecured - 3.57 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 300,000,000
Debt instrument rate (as a percent)	3.57%	3.57%
Long-term debt, gross	$ 300,000,000		300,000,000
$200 million Senior unsecured - 4.40 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 200,000,000
Debt instrument rate (as a percent)	4.40%	4.40%
Long-term debt, gross	$ 200,000,000		200,000,000
Senior Unsecured Notes 1.23% Due March 2024 | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 350,000,000
Debt instrument rate (as a percent)	1.23%	1.23%
Long-term debt, gross	$ 350,000,000		350,000,000
$300 million Senior unsecured - 3.84 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 300,000,000
Debt instrument rate (as a percent)	3.84%	3.84%
Long-term debt, gross	$ 300,000,000		300,000,000
$500 million Senior unsecured - 2.16 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 500,000,000
Debt instrument rate (as a percent)	2.16%	2.16%
Long-term debt, gross	$ 500,000,000		500,000,000
$350 million Senior unsecured - 4.12 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 350,000,000
Debt instrument rate (as a percent)	4.12%	4.12%
Long-term debt, gross	$ 350,000,000		350,000,000
$200 million Senior unsecured - 2.17 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 200,000,000
Debt instrument rate (as a percent)	2.17%	2.17%
Long-term debt, gross	$ 200,000,000		200,000,000
$200 million Senior unsecured - 3.98 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 200,000,000
Debt instrument rate (as a percent)	3.98%	3.98%
Long-term debt, gross	$ 200,000,000		200,000,000
$500 million Senior unsecured - 2.08 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 500,000,000
Debt instrument rate (as a percent)	2.08%	2.08%
Long-term debt, gross	$ 500,000,000		500,000,000
$200 million Senior unsecured - 2.48 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 200,000,000
Debt instrument rate (as a percent)	2.48%	2.48%
Long-term debt, gross	$ 200,000,000		200,000,000
$100 million Senior unsecured - 5.16 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 100,000,000
Debt instrument rate (as a percent)	5.16%	5.16%
Long-term debt, gross	$ 100,000,000		100,000,000
$300 million Senior unsecured - 4.50 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 300,000,000
Debt instrument rate (as a percent)	4.50%	4.50%
Long-term debt, gross	$ 300,000,000		300,000,000
$250 million Senior unsecured - 4.99 percent | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount	$ 250,000,000
Debt instrument rate (as a percent)	4.99%	4.99%
Long-term debt, gross	$ 250,000,000		250,000,000
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	$ 27,000,000		25,000,000
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	$ 55,000,000		51,000,000
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	$ 72,000,000		67,000,000
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	$ 98,000,000		91,000,000
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	$ 70,000,000		66,000,000
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	$ 12,000,000		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	$ 68,000,000		63,000,000
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	$ 102,000,000		95,000,000
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%	5%
US$75 million Senior unsecured - 5.00 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 102,000,000		95,000,000
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	$ 405,000,000		380,000,000
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	$ 608,000,000		572,000,000
US$400 million Senior unsecured - 3.65 percent | 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 | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Long-term debt, gross	$ 563,000,000		528,000,000
Premium from debt issued	$ 15,000,000
US$200 million Senior unsecured - 2.98 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount		$ 200,000,000
Debt instrument rate (as a percent)	2.98%	2.98%
Long-term debt, gross	$ 271,000,000		254,000,000
US$25 million Senior unsecured - 5.25 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount		$ 25,000,000
Debt instrument rate (as a percent)	5.25%	5.25%
Long-term debt, gross	$ 34,000,000		0
US$175 million Senior unsecured - 5.33 percent | WGL And Washington Gas | AltaGas Ltd. medium-term notes (MTNs)
Debt Instrument
Debt face amount		$ 175,000,000
Debt instrument rate (as a percent)	5.33%	5.33%
Long-term debt, gross	$ 237,000,000		0
US$82 million SEMCO Senior Secured - 4.48 percent | SEMCO long-term debt
Debt Instrument
Debt face amount		$ 82,000,000
Debt instrument rate (as a percent)	4.48%	4.48%
Long-term debt, gross	$ 60,000,000		63,000,000
US$225 million First Mortgage Bonds - 2.45 percent | SEMCO long-term debt
Debt Instrument
Debt face amount		$ 225,000,000
Debt instrument rate (as a percent)	2.45%	2.45%
Long-term debt, gross	$ 305,000,000		285,000,000
US$225 million First Mortgage Bonds - 3.15 percent | SEMCO long-term debt
Debt Instrument
Debt face amount		$ 225,000,000
Debt instrument rate (as a percent)	3.15%	3.15%
Long-term debt, gross	$ 305,000,000		285,000,000
Credit facilities | $2 billion unsecured extendible revolving facility (a)
Debt Instrument
Debt face amount	2,000,000,000
Long-term debt, gross	860,000,000		375,000,000
Credit facilities | $2 billion unsecured extendible revolving facility (a) | Line of Credit
Debt Instrument
Debt face amount	$ 200,000,000
Debt instrument term (years)	3 years
Credit facilities | $2 billion unsecured extendible revolving facility (a) | Extendable Side Car Liquidity Revolving Facility
Debt Instrument
Debt face amount	$ 300,000,000
Debt instrument term (years)	2 years
Credit facilities | $2 billion unsecured extendible revolving facility (a) | Extendable Committed Revolving Facility
Debt Instrument
Debt instrument term (years)	5 years
Credit facilities | US$150 million unsecured extendible revolving facility
Debt Instrument
Debt face amount		$ 150,000,000
Long-term debt, gross	$ 188,000,000		120,000,000
Credit facilities | Commercial Paper
Debt Instrument
Long-term debt, gross	$ 386,000,000		$ 469,000,000

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) - Revolving Credit Facility	3 Months Ended	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)
Debt Instrument
Proceeds from unsecured lines of credit	$ 200,000,000
Credit facility maximum borrowing capacity	2,500,000,000	$ 2,500,000,000		$ 2,300,000,000
Amount outstanding	860,000,000	860,000,000		375,000,000
$2 billion unsecured extendible revolving facility (a)
Debt Instrument
Long-term debt, gross	860,000,000	860,000,000		375,000,000
Commercial Paper
Debt Instrument
Long-term debt, gross	386,000,000	386,000,000		469,000,000
AltaGas
Debt Instrument
Credit facility maximum borrowing capacity	450,000,000	$ 450,000,000
Debt instrument term (years)		2 years
Amount outstanding	$ 450,000,000	$ 450,000,000
SEMCO
Debt Instrument
Credit facility maximum borrowing capacity			$ 150,000,000		$ 150,000,000
Amount outstanding			140,000,000		95,000,000
Petrogas Energy Corporation
Debt Instrument
Credit facility maximum borrowing capacity					25,000,000
Amount outstanding				0
Extendable Committed Revolving Facility | $2 billion unsecured extendible revolving facility (a)
Debt Instrument
Debt instrument term (years)	5 years
Extendable Side Car Liquidity Revolving Facility | $2 billion unsecured extendible revolving facility (a)
Debt Instrument
Debt instrument term (years)	2 years
Line of Credit | $2 billion unsecured extendible revolving facility (a)
Debt Instrument
Debt instrument term (years)	3 years
Line of Credit | WGL Holdings
Debt Instrument
Credit facility maximum borrowing capacity			300,000,000		300,000,000
Amount outstanding	$ 0	0		0
Line of Credit | Washington Gas
Debt Instrument
Credit facility maximum borrowing capacity			$ 450,000,000		$ 450,000,000
Amount outstanding	$ 0	$ 0		$ 0

Subordinated Hybrid Notes - Sch

Subordinated Hybrid Notes - Schedule of Subordinated Borrowing (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Subordinated Borrowing [Line Items]
Less: debt issuance costs	$ (41)	$ (44)
Long term debt	9,091	8,195
Subordinated Debt
Subordinated Borrowing [Line Items]
Long-term debt, gross	550	0
Less: debt issuance costs	(6)	0
Long term debt	544	0
$300 million subordinated notes, Series 1 | Subordinated Debt
Subordinated Borrowing [Line Items]
Long-term debt, gross	300	0
$250 million subordinated notes, Series 2 | Subordinated Debt
Subordinated Borrowing [Line Items]
Long-term debt, gross	$ 250	$ 0

Subordinated Hybrid Notes - Nar

Subordinated Hybrid Notes - Narrative (Details) - AltaGas - Subordinated Debt - CAD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Aug. 17, 2022	Jan. 11, 2022
Subordinated Borrowing [Line Items]
Interest expense	$ 22,000,000	$ 0
$300 million subordinated notes, Series 1
Subordinated Borrowing [Line Items]
Debt face amount				$ 300,000,000
Debt instrument, stated rate (as a percent)				5.25%
$250 million subordinated notes, Series 2
Subordinated Borrowing [Line Items]
Debt face amount			$ 250,000,000
Debt instrument, stated rate (as a percent)			7.35%

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis
Balance, beginning of year	$ 429	$ 379
Obligations acquired	0	5
New obligations	3	4
Obligations settled	(10)	(10)
Disposals	(1)	0
Revision in estimated cash flow	(2)	40
Accretion expense	20	19
Foreign exchange translation	23	(1)
Reclassified to liabilities associated with assets held for sale (note 5)	(4)	0
Total	458	436
Less: current portion (included in accounts payable and accrued liabilities)	(7)	(7)
Balance, end of year	451	429
Asset retirement obligation, current	$ 7	$ 7

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligations [Line Items]
Undiscounted cash required to settle the asset retirement obligations, excluding growth for inflation	$ 877	$ 892
Minimum
Asset Retirement Obligations [Line Items]
Discount rate for asset retirement obligations (percent)	2%	2%
Maximum
Asset Retirement Obligations [Line Items]
Discount rate for asset retirement obligations (percent)	8.40%	8.50%

Environmental Matters (Details)

Environmental Matters (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) site	Dec. 31, 2021 CAD ($)
Site Contingency
Identified operated manufactured gas plants | site	12
Accrual for environmental loss contingencies	$ 13	$ 18
Regulatory assets	15	16
Maximum
Site Contingency
Accrual for environmental loss contingencies	$ 50	$ 50

Other Long-term Liabilities (De

Other Long-term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Liabilities Disclosure [Abstract]
Deferred revenue	$ 11	$ 13
Customer advances for construction	69	59
Merger commitments	5	7
Non-retirement employee benefits (a)	51	19
Uncertain tax positions (note 21)	20	20	$ 21
Other	19	16
Other liabilities	175	134
Less: liabilities associated with assets held for sale (note 5)	(53)	0
Other long-term liabilities (notes 20 and 24)	$ 122	$ 134

Income Taxes - Schedule of Inco

Income Taxes - Schedule of Income Tax Provision (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income before income taxes - consolidated	$ 716	$ 446
Statutory income tax rate (%)	23%	23%
Expected taxes at statutory rates	$ 165	$ 103
Permanent differences	2	3
Statutory and other rate differences	1	25
Deferred income tax recovery on regulated assets	(21)	(18)
Tax differences on divestitures and transactions	(3)	(4)
Other	(1)	(3)
Income tax expense, total	143	106
Current	23	59
Deferred	$ 120	$ 47
Effective income tax rate (%)	20%	23.80%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Income Tax Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
PP&E and intangible assets	$ 1,862	$ 1,709
Regulatory assets	(187)	(233)
Tax pools, deferred financing, and compensation	(238)	(236)
Other	(69)	(84)
Valuation allowance	1	2
Net deferred income tax liabilities	$ 1,369	$ 1,158

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Income Tax Disclosure [Abstract]
Tax-affected non-capital losses	$ 338

Income Taxes - Schedule of Unce

Income Taxes - Schedule of Uncertain Tax Positions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Unrecognized Tax Benefits
Balance, beginning of year	$ 20	$ 21
Settlement	0	(1)
Balance, end of year	$ 20	$ 20

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current	$ 38	$ 48
Regulatory assets - non-current	448	436
Regulatory Asset, Noncurrent, Before Assets Held For Sale	462	436
Less: non-current regulatory assets reclassified to assets held for sale (note 5)	(14)	0
Regulatory liabilities - current	183	79
Regulatory liabilities - non-current	1,201	1,424
Regulatory Liability, Noncurrent, Before Assets Held For Sale	1,297	1,424
Less: non-current regulatory liabilities associated with assets held for sale (note 5)	(96)	0
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current	164	71
Refundable tax credit
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current	0	2
Federal income tax rate change
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current	1	1
Regulatory liabilities - non-current	568	543
Virginia Rate Refund
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current	5	0
Interruptible sharing
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current	3	4
Virginia and Maryland Revenue Normalization
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current	2	0
Virginia Coronavirus Relief Fund
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current	0	1
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current	235	425
Future removal and site restoration costs
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current	490	453
Deferred gain on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - non-current	1	1
Fair value adjustment	74	72
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory liabilities - current	8	0
Regulatory liabilities - non-current	3	2
Deferred cost of gas
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current	15	20
Accelerated replacement recovery mechanisms
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current	11	7
Energy Optimization Costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current	4	5
Virginia and Maryland Revenue Normalization
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - current	8	16
Deferred regulatory costs and rate stabilization adjustment mechanism
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current	$ 254	199
Deferred regulatory costs and rate stabilization adjustment mechanism | Minimum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)	1 year
Deferred regulatory costs and rate stabilization adjustment mechanism | Maximum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)	53 years
Future recovery of pension and other retirement benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current	$ 1	33
Future recovery of pension and other retirement benefits | Minimum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)	2 years
Future recovery of pension and other retirement benefits | Maximum
Schedule Of Regulatory Assets And Liabilities
Recovery period (years)	20 years
Future recovery of non-retirement employee benefits
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current	$ 16	19
Deferred environmental costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current	15	16
Deferred loss on debt transactions and derivative instruments
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current	91	89
Fair value adjustment		72
Deferred future income taxes
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current	42	43
Energy efficiency program - Maryland
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current	31	23
COVID-19 Costs
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current	4	6
Other
Schedule Of Regulatory Assets And Liabilities
Regulatory assets - non-current	$ 8	$ 8

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) - Schedule of Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	$ 7,601
Total other comprehensive income (loss) (OCI), net of taxes	631	$ (57)
Balance, end of year	7,618	7,601
Total
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(7)	50
OCI before reclassification	627	(58)
Amounts reclassified from OCI	0	3
Current period OCI (pre-tax)	627	(55)
Income tax on amounts retained in AOCI	1	(1)
Income tax on amounts reclassified to earnings	0	(1)
Total other comprehensive income (loss) (OCI), net of taxes	628	(57)
Balance, end of year	626	(7)
Defined benefit pension and PRB plans
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(8)	(12)
OCI before reclassification	4	3
Amounts reclassified from OCI		3
Current period OCI (pre-tax)	4	6
Income tax on amounts retained in AOCI	(1)	(1)
Income tax on amounts reclassified to earnings		(1)
Total other comprehensive income (loss) (OCI), net of taxes	3	4
Purchase of remaining non-controlling interest in subsidiaries (note 3)	0
Balance, end of year	(5)	(8)
Hedge net investments
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	(158)	(158)
OCI before reclassification	(17)	0
Amounts reclassified from OCI		0
Current period OCI (pre-tax)	(17)	0
Income tax on amounts retained in AOCI	2	0
Income tax on amounts reclassified to earnings		0
Total other comprehensive income (loss) (OCI), net of taxes	(15)	0
Purchase of remaining non-controlling interest in subsidiaries (note 3)	0
Balance, end of year	(173)	(158)
Translation foreign operations
AOCI Attributable to Parent, Net of Tax
Balance, beginning of year	159	220
OCI before reclassification	640	(61)
Amounts reclassified from OCI		0
Current period OCI (pre-tax)	640	(61)
Income tax on amounts retained in AOCI	0	0
Income tax on amounts reclassified to earnings		0
Total other comprehensive income (loss) (OCI), net of taxes	640	(61)
Purchase of remaining non-controlling interest in subsidiaries (note 3)	5
Balance, end of year	$ 804	$ 159

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income (Loss) - Schedule of Reclassification from Accumulated Other Comprehensive Income (Details) - Total - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Defined benefit pension and PRB plans	$ 0	$ 3
Deferred income taxes	0	(1)
Reclassifications from AOCI, net	$ 0	$ 2

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, 2022	Dec. 31, 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	$ 140	$ 113
Risk management assets - non-current	77	51
Risk management liabilities - current	172	128
Risk management liabilities - non-current	298	165
Subordinated hybrid notes (notes 17 and 24)	544	0
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Financial assets	217	164
Current portion of long-term debt	334	511
Long-term debt	8,694	7,684
Debt classified as held for sale (note 5)	63
Other current liabilities		43
Financial liabilities	10,157	8,531
Carrying Amount | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	132	112
Risk management assets - non-current	77	50
Risk management liabilities - current	133	113
Risk management liabilities - non-current	170	90
Carrying Amount | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	8	1
Risk management assets - non-current		1
Risk management liabilities - current	39	15
Risk management liabilities - non-current	128	75
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Financial assets	217	164
Current portion of long-term debt	334	511
Long-term debt	7,721	7,898
Subordinated hybrid notes (notes 17 and 24)	480
Debt classified as held for sale (note 5)	60
Other current liabilities	52	43
Financial liabilities	9,117	8,745
Fair Value | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	132	112
Risk management assets - non-current	77	50
Risk management liabilities - current	133	113
Risk management liabilities - non-current	170	90
Fair Value | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	8	1
Risk management assets - non-current		1
Risk management liabilities - current	39	15
Risk management liabilities - non-current	128	75
Fair Value | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Financial assets	0	0
Current portion of long-term debt	0	0
Long-term debt	0	0
Subordinated hybrid notes (notes 17 and 24)	0
Debt classified as held for sale (note 5)	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
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
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
Financial assets	154	95
Current portion of long-term debt	334	511
Long-term debt	7,721	7,898
Subordinated hybrid notes (notes 17 and 24)	480
Debt classified as held for sale (note 5)	60
Other current liabilities	52	43
Financial liabilities	8,662	8,521
Fair Value | Level 2 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	96	73
Risk management assets - non-current	52	22
Risk management liabilities - current	11	58
Risk management liabilities - non-current	4	11
Fair Value | Level 2 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	6	0
Risk management assets - non-current		0
Risk management liabilities - current	0	0
Risk management liabilities - non-current	0	0
Fair Value | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Financial assets	63	69
Current portion of long-term debt	0	0
Long-term debt	0	0
Subordinated hybrid notes (notes 17 and 24)	0
Debt classified as held for sale (note 5)	0
Other current liabilities	0	0
Financial liabilities	455	224
Fair Value | Level 3 | Fair value through net income
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	36	39
Risk management assets - non-current	25	28
Risk management liabilities - current	122	55
Risk management liabilities - non-current	166	79
Fair Value | Level 3 | Fair value through regulatory assets/liabilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Risk management assets - current	2	1
Risk management assets - non-current		1
Risk management liabilities - current	39	15
Risk management liabilities - non-current	$ 128	$ 75

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, 2022 CAD ($) $ / dekatherm $ / MWh
Gas purchase | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (222)
Fair Value, Net Asset (Liability), Per Dekatherm	(0.50)
Gas purchase | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(2.59)
Gas purchase | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	14
Gas purchase | Option Model
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (4)
Fair Value, Net Asset (Liability), Per Dekatherm	0.73
Fair Value, Net Asset (Liability), Percent	91%
Gas purchase | Option Model | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	(2.06)
Fair Value, Net Asset (Liability), Percent	22%
Gas purchase | Option Model | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Dekatherm	7.30
Fair Value, Net Asset (Liability), Percent	292%
Electricity | Discounted Cash Flow
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability) | $	$ (166)
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MWh	23.20
Electricity | Discounted Cash Flow | Minimum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MWh	(10.86)
Electricity | Discounted Cash Flow | Maximum
Fair Value Measurement Inputs and Valuation Techniques
Fair Value, Net Asset (Liability), Per Megawatt Hour | $ / MWh	185.54

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, 2022	Dec. 31, 2021
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	$ (155)	$ (93)
Recorded in income	(256)	(40)
Recorded in regulatory assets	(100)	(28)
Transfers out of Level 3	(28)	(1)
Purchases	16	4
Settlements	153	6
Foreign exchange translation	(22)	(3)
Balance, end of year	(392)	(155)
Gas purchase
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	(107)	(74)
Recorded in income	(43)	(15)
Recorded in regulatory assets	(100)	(28)
Transfers out of Level 3	2	(1)
Purchases	0	0
Settlements	35	14
Foreign exchange translation	(13)	(3)
Balance, end of year	(226)	(107)
Electricity
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance, beginning of year	(48)	(19)
Recorded in income	(213)	(25)
Recorded in regulatory assets	0	0
Transfers out of Level 3	(30)	0
Purchases	16	4
Settlements	118	(8)
Foreign exchange translation	(9)	0
Balance, end of year	$ (166)	$ (48)

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, 2022	Dec. 31, 2021
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation
Realized and Unrealized Losses Recorded to Income for Level 3 Measurements	$ (256)	$ (40)
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	(258)	(79)
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	$ 2	$ 39

Financial Instruments and Fin_7

Financial Instruments and Financial Risk Management - Schedule of Unrealized Gains (Losses) on Risk Management Contracts (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ (49)	$ 18
Natural gas
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(57)	6
Energy exports
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	21	38
Crude oil and NGLs
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	2	1
NGL frac spread
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	16	(13)
Power
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	(31)	9
Foreign exchange
Derivative Instruments, Gain (Loss)
Unrealized gains (losses) on risk management contracts	$ 0	$ (23)

Financial Instruments and Fin_8

Financial Instruments and Financial Risk Management - Schedule of Offsetting Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Offsetting Assets And Liabilities
Netting of collateral	$ 0	$ 0
Risk management assets - current	140	113
Risk management assets - non-current	77	51
Risk management liabilities - current	172	128
Risk management liabilities - non-current	298	165
Risk management contracts
Offsetting Assets And Liabilities
Gross amounts of recognized assets	444	260
Gross amounts offset in balance sheet	(246)	(107)
Netting of collateral	19	11
Net amount of assets presented in balance sheet	217	164
Gross amounts of recognized liabilities	716	400
Gross amounts offset in balance sheet	(246)	(107)
Netting of collateral	0	0
Net amount of liabilities presented in balance sheet	470	293
Natural gas
Offsetting Assets And Liabilities
Gross amounts of recognized assets	174	94
Gross amounts offset in balance sheet	(80)	(22)
Netting of collateral	(17)	(25)
Net amount of assets presented in balance sheet	77	47
Gross amounts of recognized liabilities	360	164
Gross amounts offset in balance sheet	(80)	(22)
Netting of collateral	0	(4)
Net amount of liabilities presented in balance sheet	280	138
Energy exports
Offsetting Assets And Liabilities
Gross amounts of recognized assets	105	61
Gross amounts offset in balance sheet	(112)	(60)
Netting of collateral	34	37
Net amount of assets presented in balance sheet	27	38
Gross amounts of recognized liabilities	112	81
Gross amounts offset in balance sheet	(112)	(60)
Netting of collateral	0	2
Net amount of liabilities presented in balance sheet	0	23
Crude oil and NGLs
Offsetting Assets And Liabilities
Gross amounts of recognized assets	6
Gross amounts offset in balance sheet	(4)
Netting of collateral	2
Net amount of assets presented in balance sheet	4
Gross amounts of recognized liabilities	4	6
Gross amounts offset in balance sheet	(4)	0
Netting of collateral	0	2
Net amount of liabilities presented in balance sheet	0	8
NGL frac spread
Offsetting Assets And Liabilities
Gross amounts of recognized assets	6	4
Gross amounts offset in balance sheet	(6)	0
Netting of collateral	0	0
Net amount of assets presented in balance sheet	0	4
Gross amounts of recognized liabilities	9	23
Gross amounts offset in balance sheet	(6)	0
Netting of collateral	0	0
Net amount of liabilities presented in balance sheet	3	23
Power
Offsetting Assets And Liabilities
Gross amounts of recognized assets	153	101
Gross amounts offset in balance sheet	(44)	(25)
Netting of collateral	0	(1)
Net amount of assets presented in balance sheet	109	75
Gross amounts of recognized liabilities	231	126
Gross amounts offset in balance sheet	(44)	(25)
Netting of collateral	0	0
Net amount of liabilities presented in balance sheet	$ 187	$ 101

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, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Collateral posted with counterparties	$ 2	$ 9
Cash collateral held representing an obligation	$ 4	$ 2

Financial Instruments and Fi_10

Financial Instruments and Financial Risk Management - Narrative (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Netting of collateral	$ 0	$ 0
Long term debt	9,091	8,195
Other comprehensive income (loss)	631	(57)
Unrealized gain on net investment hedge	(15)	0
Unrealized gains (losses) on risk management contracts	(49)	18
Foreign Exchange Forward
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Realized gain on foreign exchange forward contracts	$ 1	$ 19
Interest rate risk
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Fixed rate debt, percent	78%	87%	78%	87%
Weather Related Instruments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Loss on derivatives	$ 1	$ 1
Net investment hedge
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Long term debt			$ 281	$ 122
Hedge net investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions
Other comprehensive income (loss)	$ (15)	$ 0

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, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk management liabilities with credit-risk-contingent features	$ 145	$ 42
Maximum potential collateral requirements	$ 68	$ 21

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, 2022 CAD ($) kJ MWh GJ $ / MWh $ / barrel $ / gigajoule bbl	Dec. 31, 2021 CAD ($) MWh kJ GJ $ / MWh $ / dekatherm $ / barrel $ / gigajoule bbl
Natural gas | Sales
Derivative
Notional volume (GJ) | kJ	244,060,786	259,750,059
Fair Value ($)	$ (54)	$ (8)
Natural gas | Sales | Minimum
Derivative
Fixed price | $ / gigajoule	1.75	1.75
Period (months)	1 month	1 month
Natural gas | Sales | Maximum
Derivative
Fixed price | $ / gigajoule	20.38	10.8
Period (months)	130 months	142 months
Natural gas | Purchases
Derivative
Notional volume (GJ) | kJ	521,045,852	606,923,548
Fair Value ($)	$ (169)	$ (102)
Natural gas | Purchases | Mountain Valley Pipeline
Derivative
Notional volume (GJ) | GJ	191,071,366
Natural gas | Purchases | Minimum
Derivative
Fixed price | $ / gigajoule	1.75	1.75
Period (months)	1 month	1 month
Natural gas | Purchases | Maximum
Derivative
Fixed price | $ / gigajoule	20.38	10.8
Period (months)	98 months	143 months
Natural gas | Swaps
Derivative
Notional volume (GJ) | kJ	147,565,012	201,266,412
Fair Value ($)	$ 20	$ 19
Natural gas | Swaps | Minimum
Derivative
Fixed price | $ / gigajoule	3.28	2.95
Period (months)	1 month	1 month
Natural gas | Swaps | Maximum
Derivative
Fixed price | $ / gigajoule	17.02	7.42
Period (months)	57 months	55 months
Crude oil and NGLs | Swaps
Derivative
Notional volume (Bbl) | bbl	1,597,173	864,000
Fair Value ($)	$ 4	$ (8)
Crude oil and NGLs | Swaps | Minimum
Derivative
Fixed price	44.19	41.18
Period (months)	1 month	1 month
Crude oil and NGLs | Swaps | Maximum
Derivative
Fixed price	120.45	97.12
Period (months)	12 months	12 months
Energy exports
Derivative
Notional volume (Bbl) | bbl	90,646
Energy exports | Propane and butane swaps
Derivative
Notional volume (Bbl) | bbl	89,433,941	38,860,780
Fair Value ($)	$ 27	$ 15
Energy exports | Minimum
Derivative
Period (months)	1 month
Energy exports | Minimum | Propane and butane swaps
Derivative
Fixed price | $ / barrel	4.8	5.2
Period (months)	1 month	1 month
Energy exports | Maximum
Derivative
Fixed price | $ / barrel	9.45
Period (months)	3 months
Energy exports | Maximum | Propane and butane swaps
Derivative
Fixed price | $ / barrel	118.69	115.54
Period (months)	12 months	15 months
NGL frac spread | Swaps | Propane
Derivative
Notional volume (Bbl) | bbl	1,075,194	2,099,243
Fair Value ($)	$ 5	$ (15)
NGL frac spread | Swaps | Butane swaps
Derivative
Notional volume (Bbl) | bbl		18,967
Fair Value ($)		$ (1)
NGL frac spread | Swaps | Crude oil swaps
Derivative
Notional volume (Bbl) | bbl	214,255
Notional volume (GJ) | kJ		369,495
Fair Value ($)	$ 1	$ (4)
NGL frac spread | Swaps | Gas purchase
Derivative
Notional volume (GJ)	6,139,191	11,873,390
Fair Value ($)	$ (9)	$ 1
NGL frac spread | Swaps | Minimum | Propane
Derivative
Fixed price | $ / barrel	48.94	33.14
Period (months)	1 month	1 month
NGL frac spread | Swaps | Minimum | Butane swaps
Derivative
Fixed price | $ / barrel		36.19
Period (months)		1 month
NGL frac spread | Swaps | Minimum | Crude oil swaps
Derivative
Fixed price	108.65	63.25
Period (months)	1 month	1 month
NGL frac spread | Swaps | Minimum | Gas purchase
Derivative
Fixed price	4.5	2.54
Period (months)	1 month	1 month
NGL frac spread | Swaps | Maximum | Propane
Derivative
Fixed price | $ / barrel	50.79	59.75
Period (months)	12 months	12 months
NGL frac spread | Swaps | Maximum | Butane swaps
Derivative
Fixed price | $ / barrel		36.20
Period (months)		3 months
NGL frac spread | Swaps | Maximum | Crude oil swaps
Derivative
Fixed price	113.88	89.86
Period (months)	12 months	12 months
NGL frac spread | Swaps | Maximum | Gas purchase
Derivative
Fixed price	4.98	3.89
Period (months)	12 months	12 months
Power | Sales
Derivative
Notional volume (GJ) | MWh	5,276,832	4,938,045
Fair Value ($)	$ (96)	$ (60)
Power | Sales | Minimum
Derivative
Fixed price | $ / MWh	37.18	27.19
Period (months)	1 month	1 month
Power | Sales | Maximum
Derivative
Fixed price | $ / MWh	167.07	93.94
Period (months)	42 months	42 months
Power | Purchases
Derivative
Notional volume (GJ) | MWh	6,341,582	6,393,003
Fair Value ($)	$ 99	$ 69
Power | Purchases | Minimum
Derivative
Fixed price | $ / MWh	37.18	27.19
Period (months)	1 month	1 month
Power | Purchases | Maximum
Derivative
Fixed price | $ / MWh	167.07	93.94
Period (months)	42 months	53 months
Power | Swaps
Derivative
Notional volume (GJ) | MWh	23,888,348	22,845,569
Fair Value ($)	$ (81)	$ (35)
Power | Swaps | Minimum
Derivative
Fixed price | $ / MWh	(10.86)	(8.13)
Period (months)	1 month	1 month
Power | Swaps | Maximum
Derivative
Fixed price | $ / MWh	185.54	86.84
Period (months)	41 months	41 months

Financial Instruments and Fi_13

Financial Instruments and Financial Risk Management - Schedule of Potential Impact on Pre-Tax Income Due to Change in Fair Value of Price Risk Derivatives (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) $ / gigajoule $ / gigajoule $ / MWh $ / barrel	Dec. 31, 2021 CAD ($)
Derivative
Unrealized gains (losses) on risk management contracts	$ (49)	$ 18
PJM power price
Derivative
Increase or decrease to forward prices, energy | $ / MWh	1
Unrealized gains (losses) on risk management contracts	$ 43
NYMEX natural gas price
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.50
Unrealized gains (losses) on risk management contracts	$ 30
Energy exports
Derivative
Unrealized gains (losses) on risk management contracts	$ (3)
Energy exports | LPG purchase
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Baltic LPG Freight
Derivative
Unrealized gains (losses) on risk management contracts	$ 12
Baltic LPG Freight | LPG purchase
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
NGL frac spread
Derivative
Unrealized gains (losses) on risk management contracts	$ 16	$ (13)
NGL frac spread | LPG purchase
Derivative
Increase or decrease to forward prices, volume | $ / barrel	1
Unrealized gains (losses) on risk management contracts	$ (1)
NGL frac spread | Gas purchase
Derivative
Increase or decrease to forward prices, energy | $ / gigajoule	0.50
Unrealized gains (losses) on risk management contracts	$ 3

Financial Instruments and Fi_14

Financial Instruments and Financial Risk Management - Foreign Exchange Contracts (Details) - Foreign Exchange Forward - Swaps $ in Millions	Dec. 31, 2021 USD ($)
Derivative
Derivative, notional amount	$ 10
Weighted average foreign exchange rate	1.2640
Derivative, fair value, net	$ 1

Financial Instruments and Fi_15

Financial Instruments and Financial Risk Management - Schedule of Accounts Receivable Past Due or Impaired (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accounts, Notes, Loans and Financing Receivable
AR accruals	$ 1,078	$ 560
Receivables impaired	0	0
Allowance for credit losses	(41)	(41)
Accounts receivable	2,091	1,427
Utilities
Accounts, Notes, Loans and Financing Receivable
New allowance from COVID-19	2	5
Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	816	738
31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	87	52
61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	26	24
Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	84	53
Trade receivable
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	2,067	1,431
AR accruals	1,078	560
Receivables impaired	41	39
Trade receivable | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	751	703
Trade receivable | 31 to 60 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	87	52
Trade receivable | 61 to 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	26	24
Trade receivable | Over 90 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	84	53
Other
Accounts, Notes, Loans and Financing Receivable
Accounts receivable, gross	65	35
AR accruals	0	0
Receivables impaired	0	0
Other | Less than 30 days
Accounts, Notes, Loans and Financing Receivable
Accounts receivable	65	35
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)	(39)
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

Financial Instruments and Fi_16

Financial Instruments and Financial Risk Management - Allowance for Credit Loss (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	$ 40
Balance, end of period	42	$ 40
Held for sale | Alaskan Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Reclassified to assets held for sale (note 5)	(1)
Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	38	40
Foreign exchange translation	2
New allowance	26	15
Written off	(29)	(22)
Recoveries collected	4	5
Reclassified to assets held for sale (note 5)	(1)
Balance, end of period	40	38
New allowance from COVID-19	2	5
Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	2	4
New allowance	0
Recoveries collected		(2)
Balance, end of period	2	2
Accounts receivable
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	39
Balance, end of period	41	39
Accounts receivable | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	38	40
Foreign exchange translation	2
New allowance	26	15
Written off	(29)	(22)
Recoveries collected	4	5
Balance, end of period	40	38
Accounts receivable | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1	1
New allowance	0
Recoveries collected		0
Balance, end of period	1	1
Contract assets
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1
Balance, end of period	1	1
Contract assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0	0
Foreign exchange translation	0
New allowance	0	0
Written off	0	0
Recoveries collected	0	0
Reclassified to assets held for sale (note 5)	0
Balance, end of period	0	0
Contract assets | Midstream
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	1	1
New allowance	0
Recoveries collected		0
Balance, end of period	1	1
Other Long-Term Investments and Other Assets
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0
Balance, end of period		0
Other Long-Term Investments and Other Assets | Utilities
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance, beginning of period	0	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	2
Recoveries collected		(2)
Balance, end of period		$ 0

Financial Instruments and Fi_17

Financial Instruments and Financial Risk Management - Schedule of Contractual Maturities for Financial Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Contractual maturities by period
Total	$ 12,175	$ 10,194
Less than 1 year	2,739	2,390
1-3 years	2,412	1,441
4-5 years	2,013	1,800
After 5 years	5,011	4,563
Accounts payable and accrued liabilities
Contractual maturities by period
Total	1,902	1,544
Less than 1 year		1,544
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Short-term debt
Contractual maturities by period
Total	293	169
Less than 1 year	293	169
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Other current liabilities
Contractual maturities by period
Total	52	43
Less than 1 year	52	43
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Risk management contract liabilities
Contractual maturities by period
Total	470	293
Less than 1 year	172	128
1-3 years	183	85
4-5 years	57	25
After 5 years	58	55
Current portion of long-term debt
Contractual maturities by period
Total	327	506
Less than 1 year	327	506
1-3 years	0	0
4-5 years	0	0
After 5 years	0	0
Long-term debt
Contractual maturities by period
Total	8,641	7,639
Less than 1 year	0	0
1-3 years	2,241	1,356
4-5 years	1,968	1,775
After 5 years	4,432	$ 4,508
Debt classified as held for sale
Contractual maturities by period
Total	60
Less than 1 year	7
1-3 years	12
4-5 years	12
After 5 years	29
Subordinated hybrid notes
Contractual maturities by period
Total	550
Less than 1 year	0
1-3 years	0
4-5 years	0
After 5 years	$ 550

Revenue - Schedule of Disaggreg

Revenue - Schedule of Disaggregation of Revenue by Major Sources (Details) - CAD ($) $ in Millions	12 Months Ended		57 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2022
Disaggregation of Revenue
Revenue from contracts with customers	$ 13,599	$ 10,266
Other sources of revenue	488	307
Total revenue	14,087	10,573
GAIL
Disaggregation of Revenue
Contract term			20 years
Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers	7,975	5,984
Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers	2,411	1,664
Gas sales and transportation services
Disaggregation of Revenue
Revenue from contracts with customers	3,179	2,582
Storage services
Disaggregation of Revenue
Revenue from contracts with customers	24	24
Other
Disaggregation of Revenue
Revenue from contracts with customers	10	12
Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue	94	92
Leasing revenue
Disaggregation of Revenue
Other sources of revenue	331	270
Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue	45	(66)
Risk management and trading activities | GAIL
Disaggregation of Revenue
Revenue from contracts with customers		172
Other
Disaggregation of Revenue
Other sources of revenue	18	11
Utilities
Disaggregation of Revenue
Total revenue	4,980	3,936
Midstream
Disaggregation of Revenue
Total revenue	9,010	6,535
Corporate/Other
Disaggregation of Revenue
Total revenue	97	104
Operating Segments
Disaggregation of Revenue
Total revenue		10,575
Operating Segments | Utilities
Disaggregation of Revenue
Revenue from contracts with customers	4,927	3,930
Other sources of revenue	53	6
Total revenue	4,980	3,936
Operating Segments | Utilities | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers	1,715	1,316
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	3,179	2,582
Operating Segments | Utilities | Storage services
Disaggregation of Revenue
Revenue from contracts with customers	24	24
Operating Segments | Utilities | Other
Disaggregation of Revenue
Revenue from contracts with customers	9	8
Operating Segments | Utilities | Revenue from alternative revenue programs
Disaggregation of Revenue
Other sources of revenue	94	92
Operating Segments | Utilities | Leasing revenue
Disaggregation of Revenue
Other sources of revenue	0	0
Operating Segments | Utilities | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue	(28)	(74)
Operating Segments | Utilities | Other
Disaggregation of Revenue
Other sources of revenue	(13)	(12)
Operating Segments | Midstream
Disaggregation of Revenue
Revenue from contracts with customers	8,671	6,331
Other sources of revenue	339	202
Total revenue	9,010	6,533
Operating Segments | Midstream | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers	$ 6,260	4,667
Contract term	1 year
Operating Segments | Midstream | Midstream service contracts
Disaggregation of Revenue
Revenue from contracts with customers	$ 2,411	1,664
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	0
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	232	168
Operating Segments | Midstream | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue	76	12
Operating Segments | Midstream | Other
Disaggregation of Revenue
Other sources of revenue	31	22
Operating Segments | Corporate/Other
Disaggregation of Revenue
Revenue from contracts with customers	1	5
Other sources of revenue	96	99
Total revenue	97	104
Operating Segments | Corporate/Other | Commodity sales contracts
Disaggregation of Revenue
Revenue from contracts with customers	0	1
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	1	4
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	99	102
Operating Segments | Corporate/Other | Risk management and trading activities
Disaggregation of Revenue
Other sources of revenue	(3)	(4)
Operating Segments | Corporate/Other | Other
Disaggregation of Revenue
Other sources of revenue	$ 0	$ 1

Revenue - Narrative (Details)

Revenue - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) component	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)
Disaggregation of Revenue
Contract asset	$ 41	$ 54	$ 71
Contract with customer, asset, before allowance	38
Contract asset, non current	37	41
Contract asset, current	4	13
Contract liability	$ 0	$ 1	$ 0
Utilities | Gas sales and transportation services
Disaggregation of Revenue
Number of billing components | component	2
Utilities | Gas Storage Services
Disaggregation of Revenue
Number of billing components | component	4
Maximum storage capacity (as a percent)	100%
Utilities | Operating Segments | Gas Storage Services
Disaggregation of Revenue
Contract term	1 year
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

Revenue - Schedule of Contract

Revenue - Schedule of Contract with Customer, Asset and Liability (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Change in Contract with Customer, Asset
Balance, beginning of year	$ 54	$ 71
Additions	1	0
Amortization	(4)	(4)
Transfers to accounts receivable	(10)	(13)
Balance, end of year	41	54
Change in Contract with Customer, Liability
Balance, beginning of year	1	0
Additions	0	1
Revenue recognized from contract liabilities	(1)	0
Balance, end of year	$ 0	$ 1

Revenue - Schedule of Estimated

Revenue - Schedule of Estimated Revenue Related to Performance Obligations (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,611
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 147
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 147
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 143
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 140
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 139
Performance satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 895
Performance satisfaction period	1 year
Midstream service contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 1,365
Midstream service contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 120
Performance satisfaction period	1 year
Midstream service contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 120
Performance satisfaction period	1 year
Midstream service contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 116
Performance satisfaction period	1 year
Midstream service contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 113
Performance satisfaction period	1 year
Midstream service contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 112
Performance satisfaction period	1 year
Midstream service contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 784
Performance satisfaction period	1 year
Storage services
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 231
Storage services | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 25
Performance satisfaction period	1 year
Storage services | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 25
Performance satisfaction period	1 year
Storage services | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 25
Performance satisfaction period	1 year
Storage services | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 25
Performance satisfaction period	1 year
Storage services | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 25
Performance satisfaction period	1 year
Storage services | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 106
Performance satisfaction period	1 year
Other
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 15
Other | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Other | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Other | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Other | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Other | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 2
Performance satisfaction period	1 year
Other | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Estimated revenue expected to be recognized in the future related to performance obligations	$ 5
Performance satisfaction period	1 year

Shareholders_ Equity - Schedule

Shareholders’ Equity - Schedule of Common Shares Issued and Outstanding (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) shares	Dec. 31, 2022 $ / shares	Dec. 31, 2021 CAD ($) shares	Dec. 31, 2021 $ / shares
Increase (Decrease) in Stockholders' Equity
Shares issued for cash on exercise of options (in shares) | shares	1,262,795		774,739
Balance, beginning of year	$ 6,949
Balance at end of year	$ 7,456		$ 6,949
Dividend, common stock declared (in dollars per share) | $ / shares		$ 1.06		$ 1
Common stock
Increase (Decrease) in Stockholders' Equity
Beginning balance (in shares) | shares	280,269,038		279,494,299
Shares issued for cash on exercise of options (in shares) | shares	1,262,795		774,739
Ending balance (in shares) | shares	281,531,833		280,269,038
Balance, beginning of year	$ 6,735		$ 6,723
Shares issued for cash on exercise of options	28		15
Deferred taxes on share issuance cost	(2)		(3)
Balance at end of year	$ 6,761		$ 6,735

Shareholders' Equity - Schedule

Shareholders' Equity - Schedule of Preferred Shares Issued and Outstanding (Details) - CAD ($) $ in Millions			12 Months Ended
	Sep. 30, 2022	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021
Class of Stock
Preferred stock, value			$ 7,456	$ 6,949
Series C
Class of Stock
Share issuance costs, net of taxes	$ (5)
Preferred shares, loss recognized on redemption	74
Realized gain on foreign exchange forward contracts	$ 69
Series K
Class of Stock
Preferred shares, loss recognized on redemption		$ 10
Preferred shares
Class of Stock
Preferred stock, shares			24,000,000	44,000,000
Preferred stock, value			$ 586	$ 1,076
Share issuance costs, net of taxes			$ (14)	$ (30)
Preferred shares | Series A
Class of Stock
Preferred stock, shares			6,746,679	6,746,679
Preferred stock, value			$ 169	$ 169
Preferred shares | Series B
Class of Stock
Preferred stock, shares			1,253,321	1,253,321
Preferred stock, value			$ 31	$ 31
Preferred shares | Series C
Class of Stock
Preferred stock, shares			0	8,000,000
Preferred stock, value			$ 0	$ 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 K
Class of Stock
Preferred stock, shares			0	12,000,000
Preferred stock, value			$ 0	$ 300

Shareholders_ Equity - Schedu_2

Shareholders’ Equity - Schedule of Cumulative Redeemable Preferred Shares (Details)	12 Months Ended
	Dec. 31, 2022 $ / shares $ / shares shares
Class of Stock
Redemption price (in shares)	$ 25.50
Series A
Class of Stock
Current yield	3.06%
Annual dividend per share	$ 0.76500
Redemption price (in shares)	$ 25
Series A | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	2.66%
Series B
Class of Stock
Redemption price (in shares)	$ 25
Preferred stock floating dividend rate (in shares)	$ 0.41875
Series B | 90-Day government of Canada treasury bill rate
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	2.66%
Series E
Class of Stock
Current yield	5.393%
Annual dividend per share	$ 1.34825
Redemption price (in shares)	$ 25
Series E | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.17%
Series G
Class of Stock
Current yield	4.242%
Annual dividend per share	$ 1.06050
Redemption price (in shares)	$ 25
Series G | Five year government of Canada bond yield
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.06%
Series H
Class of Stock
Redemption price (in shares)	$ 25
Preferred stock floating dividend rate (in shares)	$ 0.44340
Series H | 90-Day government of Canada treasury bill rate
Class of Stock
Preferred stock cumulative quarterly dividend variable rate (percent)	3.06%
Series F
Class of Stock
Redemption price (in shares)	$ 25.50
Preferred stock shares authorized (in shares) | shares	8,000,000

Shareholders_ Equity - Narrativ

Shareholders’ Equity - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Share Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Shares reserved for issuance	11,713,367
Unexpensed fair value of share option compensation cost	$ 1	$ 3
Aggregate intrinsic value of options exercisable	24	33
Intrinsic value of options outstanding	33	68
Mid-Term Incentive And Deferred Share Unit Plans
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense	50	66
Unrecognized compensation expense	$ 14	16
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	$ 11	$ 5

Shareholders_ Equity - Schedu_3

Shareholders’ Equity - Schedule of Share Option Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Number of options
Outstanding, beginning of year (in shares)	8,679,508	8,362,211
Granted (in shares)	0	1,878,670
Exercised (in shares)	(1,262,795)	(774,739)
Forfeited (shares)	(107,799)	(214,259)
Expired (in shares)	(350,775)	(572,375)
Outstanding, end of year (in shares)	6,958,139	8,679,508
Share options exercisable, end of year (in shares)	4,960,341	4,435,287
Exercise price
Outstanding, beginning of year (in shares)	$ 19.98	$ 21.06
Granted (in shares)	0	18.77
Exercised (in shares)	19.94	17.44
Forfeited (in shares)	26.24	25.24
Expired (in shares)	32.19	33.26
Outstanding, end of year (in shares)	19.28	19.98
Share options exercisable, end of year (in shares)	$ 19.38	$ 20.72

Shareholders_ Equity - Schedu_4

Shareholders’ Equity - Schedule of Employee Share Option Plan (Details)	12 Months Ended
	Dec. 31, 2022 $ / shares $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award
Options outstanding, Number outstanding (shares) | shares	6,958,139
Options outstanding, Weighted average exercise price (per share)	$ 19.28
Options outstanding, Weighted average remaining contractual life	2 years 8 months 19 days
Options exercisable, Number exercisable (shares) | shares	4,960,341
Options exercisable, Weighted average exercise price (per share)	$ 19.38
Options exercisable, Weighted average remaining contractual life	2 years 4 months 6 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	1,739,186
Options outstanding, Weighted average exercise price (per share)	$ 15.41
Options outstanding, Weighted average remaining contractual life	2 years 25 days
Options exercisable, Number exercisable (shares) | shares	1,712,333
Options exercisable, Weighted average exercise price (per share)	$ 15.40
Options exercisable, Weighted average remaining contractual life	2 years 14 days
$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	4,570,158
Options outstanding, Weighted average exercise price (per share)	$ 19.27
Options outstanding, Weighted average remaining contractual life	3 years 3 months
Options exercisable, Number exercisable (shares) | shares	2,601,089
Options exercisable, Weighted average exercise price (per share)	$ 19.43
Options exercisable, Weighted average remaining contractual life	2 years 11 months 15 days
$25.09 to $37.86
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)	$ 37.86
Options outstanding, Number outstanding (shares) | shares	648,795
Options outstanding, Weighted average exercise price (per share)	$ 29.70
Options outstanding, Weighted average remaining contractual life	8 months 19 days
Options exercisable, Number exercisable (shares) | shares	646,919
Options exercisable, Weighted average exercise price (per share)	$ 29.71
Options exercisable, Weighted average remaining contractual life	8 months 15 days

Shareholders_ Equity - Schedu_5

Shareholders’ Equity - Schedule of Fair Value of Options Granted (Details)	12 Months Ended
	Dec. 31, 2021 $ / shares
Stockholders' Equity Note [Abstract]
Fair value per option (in shares)	$ 3.37
Risk-free interest rate (%)	0.42%
Expected life (years)	6 years
Expected volatility (%)	35.70%
Annual dividend per share (in shares)	$ 1
Forfeiture rate (%)	0%

Shareholders_ Equity - Schedu_6

Shareholders’ Equity - Schedule of MTIP and DSUP Activity (Details) - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
PUs, RUs, and DSUs (number of units)
Balance, beginning of year (units)	3,877,843	5,920,300
Granted (units)	1,413,790	1,611,727
Vested and paid out (units)	(1,784,293)	(3,495,702)
Forfeited (units)	(140,150)	(313,621)
Units in lieu of dividends (units)	172,563	126,250
Additional units added by performance factor (in shares)	792,309	28,889
Outstanding, end of year (units)	4,332,062	3,877,843

Net Income Per Common Share - S

Net Income Per Common Share - Schedule of Net Income per Common Share (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Numerator:
Net income applicable to controlling interests	$ 523	$ 283
Less: Preferred share dividends	(40)	(53)
Loss on redemption of preferred shares (note 26)	(84)
Net income applicable to common shares	$ 399	$ 230
Denominator:
Weighted average number of common shares outstanding (in shares)	281	279.9
Dilutive equity instruments (in shares)	2.3	1.8
Weighted average number of common shares outstanding - diluted (in shares)	283.3	281.7
Basic net income per common share (in shares)	$ 1.42	$ 0.82
Diluted net income per common share (in shares)	$ 1.41	$ 0.82
Anti-dilutive share options excluded from diluted income per share (in shares)		1.7

Other Income -Schedule of Other

Other Income -Schedule of Other Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Other Income and Expenses [Abstract]
Gains on asset sales (note 4)	$ 3	$ 6
Other components of net benefit cost (note 29)	74	64
Interest income and other revenue	17	11
Total	$ 94	$ 81

Pension Plans and Retiree Ben_3

Pension Plans and Retiree Benefits - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) plan age division	Dec. 31, 2021 CAD ($)
Defined Benefit Plan Disclosure
Defined contribution plan cost recorded | $	$ 25	$ 22
Rabbi trust | $	$ 11	$ 18
Minimum
Defined Benefit Plan Disclosure
Plan assets investment objective period	3 years
Assumed initial healthcare cost trend rate	2.80%
Ultimate trend rate	2.60%
Maximum
Defined Benefit Plan Disclosure
Plan assets investment objective period	5 years
Assumed initial healthcare cost trend rate	6.50%
Ultimate trend rate	5%
Fixed income | SEMCO
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	33%
Fixed income | Minimum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	50%
Fixed income | Maximum | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	70%
Canada | Fixed income
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	100%
Defined Benefit
Defined Benefit Plan Disclosure
Number of divisions | division	5
Defined Benefit | Canada
Defined Benefit Plan Disclosure
Number of pension plans	1
Curtailment recorded to AOCI | $	$ 1
Defined Benefit | Canada | Partially funded
Defined Benefit Plan Disclosure
Number of pension plans	2
Defined Benefit | Foreign Plan
Defined Benefit Plan Disclosure
Number of pension plans	5
Target asset mix (as a percent)	500%	0%
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	5
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)	23%	21%
Post-Retirement Benefits | Foreign Plan | Partially funded
Defined Benefit Plan Disclosure
Number of pension plans	1
Post-Retirement Benefits | Foreign Plan | Fully funded
Defined Benefit Plan Disclosure
Number of pension plans	3
Post-Retirement Benefits | Foreign Plan | Not funded
Defined Benefit Plan Disclosure
Number of pension plans	1

Pension Plans and Retiree Ben_4

Pension Plans and Retiree Benefits - Schedule of Defined Benefit Plans (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	$ 1,777	$ 1,837
Actuarial gain	(479)	(43)
Current service cost	25	27
Member contributions	0	0
Interest cost	53	50
Benefits paid	(87)	(78)
Expenses paid	(1)	(1)
Settlements	(5)	(7)
Plan amendments		0
Other	0
Foreign exchange translation	98	(8)
Balance, end of year	1,381	1,777
Less: projected benefit obligation reclassified to liabilities associated with assets held for sale (note 5)	(85)
Projected benefit obligation, total	1,296
Plan assets
Fair value, beginning of year	1,731	1,683
Actual return on plan assets	(377)	125
Employer contributions	12	15
Member contributions	0	0
Benefits paid	(87)	(78)
Expenses paid	(1)	(1)
Settlements	(5)	(7)
Other	0
Foreign exchange translation	99	(6)
Plan assets, Fair value, end of year	1,372	1,731
Less: plan assets reclassified to assets held for sale (note 5)	(93)
Plan assets, total	1,279
Funded status	(9)	(46)
Defined Benefit | Canada
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	34	37
Actuarial gain	(6)	(4)
Current service cost	3	4
Member contributions	0	0
Interest cost	1	1
Benefits paid	(4)	(4)
Expenses paid	0	0
Settlements	0	0
Plan amendments		0
Other	0
Foreign exchange translation	0	0
Balance, end of year	28	34
Less: projected benefit obligation reclassified to liabilities associated with assets held for sale (note 5)	0
Projected benefit obligation, total	28
Plan assets
Fair value, beginning of year	16	16
Actual return on plan assets	(3)	0
Employer contributions	4	4
Member contributions	0	0
Benefits paid	(4)	(4)
Expenses paid	0	0
Settlements	0	0
Other	0
Foreign exchange translation	0	0
Plan assets, Fair value, end of year	13	16
Less: plan assets reclassified to assets held for sale (note 5)	0
Plan assets, total	13
Funded status	(15)	(18)
Defined Benefit | Foreign Plan
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	1,743	1,800
Actuarial gain	(473)	(39)
Current service cost	22	23
Member contributions	0	0
Interest cost	52	49
Benefits paid	(83)	(74)
Expenses paid	(1)	(1)
Settlements	(5)	(7)
Plan amendments		0
Other	0
Foreign exchange translation	98	(8)
Balance, end of year	1,353	1,743
Less: projected benefit obligation reclassified to liabilities associated with assets held for sale (note 5)	(85)
Projected benefit obligation, total	1,268
Plan assets
Fair value, beginning of year	1,715	1,667
Actual return on plan assets	(374)	125
Employer contributions	8	11
Member contributions	0	0
Benefits paid	(83)	(74)
Expenses paid	(1)	(1)
Settlements	(5)	(7)
Other	0
Foreign exchange translation	99	(6)
Plan assets, Fair value, end of year	1,359	1,715
Less: plan assets reclassified to assets held for sale (note 5)	(93)
Plan assets, total	1,266
Funded status	6	(28)
Post-Retirement Benefits
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	432	454
Actuarial gain	(118)	(19)
Current service cost	10	10
Member contributions	3	2
Interest cost	13	12
Benefits paid	(23)	(25)
Expenses paid	0	0
Settlements	0	0
Plan amendments		(1)
Other	1
Foreign exchange translation	25	(1)
Balance, end of year	343	432
Less: projected benefit obligation reclassified to liabilities associated with assets held for sale (note 5)	(9)
Projected benefit obligation, total	334
Plan assets
Fair value, beginning of year	1,058	1,016
Actual return on plan assets	(254)	67
Employer contributions	0	0
Member contributions	3	2
Benefits paid	(23)	(23)
Expenses paid	0	0
Settlements	0	0
Other	1
Foreign exchange translation	60	(4)
Plan assets, Fair value, end of year	845	1,058
Less: plan assets reclassified to assets held for sale (note 5)	(3)
Plan assets, total	842
Funded status	502	626
Post-Retirement Benefits | Canada
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	2	2
Actuarial 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
Plan amendments		0
Other	0
Foreign exchange translation	0	0
Balance, end of year	2	2
Less: projected benefit obligation reclassified to liabilities associated with assets held for sale (note 5)	0
Projected benefit obligation, total	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
Other	0
Foreign exchange translation	0	0
Plan assets, Fair value, end of year	0	0
Less: plan assets reclassified to assets held for sale (note 5)	0
Plan assets, total	0
Funded status	(2)	(2)
Post-Retirement Benefits | Foreign Plan
Defined Benefit Plan, Change in Benefit Obligation
Balance, beginning of year	430	452
Actuarial gain	(118)	(19)
Current service cost	10	10
Member contributions	3	2
Interest cost	13	12
Benefits paid	(23)	(25)
Expenses paid	0	0
Settlements	0	0
Plan amendments		(1)
Other	1
Foreign exchange translation	25	(1)
Balance, end of year	341	430
Less: projected benefit obligation reclassified to liabilities associated with assets held for sale (note 5)	(9)
Projected benefit obligation, total	332
Plan assets
Fair value, beginning of year	1,058	1,016
Actual return on plan assets	(254)	67
Employer contributions	0	0
Member contributions	3	2
Benefits paid	(23)	(23)
Expenses paid	0	0
Settlements	0	0
Other	1
Foreign exchange translation	60	(4)
Plan assets, Fair value, end of year	845	1,058
Less: plan assets reclassified to assets held for sale (note 5)	(3)
Plan assets, total	842
Funded status	$ 504	$ 628

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, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	$ 538	$ 674
Assets held for sale (note 5)	8	0
Accounts payable and accrued liabilities	(3)	(8)
Future employee obligations	(44)	(86)
Liabilities associated with assets held for sale (note 5)	(6)	0
Total amounts included in Consolidated Balance Sheets	493	580
Defined Benefit
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	28	37
Assets held for sale (note 5)	8	0
Accounts payable and accrued liabilities	(3)	(8)
Future employee obligations	(42)	(75)
Liabilities associated with assets held for sale (note 5)	0	0
Total amounts included in Consolidated Balance Sheets	(9)	(46)
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Prepaid post-retirement benefits	510	637
Assets held for sale (note 5)	0	0
Accounts payable and accrued liabilities	0	0
Future employee obligations	(2)	(11)
Liabilities associated with assets held for sale (note 5)	(6)	0
Total amounts included in Consolidated Balance Sheets	$ 502	$ 626

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, 2022	Dec. 31, 2021
Canada
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ 27	$ 33
Foreign Plan
Defined Benefit Plan Disclosure
Accumulated benefit obligation	$ 1,307	$ 1,659

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, 2022	Dec. 31, 2021
Defined Benefit
Defined Benefit Plan Disclosure
Projected benefit obligation	$ 49	$ 375
Plan assets	3	289
Accumulated benefit obligation	48	221
Plan assets	3	158
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Projected benefit obligation	11	14
Plan assets	3	3
Accumulated benefit obligation	11	14
Plan assets	$ 3	$ 3

Pension Plans and Retiree Ben_8

Pension Plans and Retiree Benefits - Schedule of Amounts Recorded in Other Comprehensive Income (Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit
Defined Benefit Plan Disclosure
Past service cost	$ 0	$ 0
Net actuarial gain (loss)	(2)	(1)
Recognized in AOCI pre-tax	(2)	(1)
Increase (decrease) by the amount included in deferred tax liabilities	0	0
Net amount in AOCI after-tax	(2)	(1)
Defined Benefit | Canada
Defined Benefit Plan Disclosure
Past service cost	0	0
Net actuarial gain (loss)	(2)	(5)
Recognized in AOCI pre-tax	(2)	(5)
Increase (decrease) by the amount included in deferred tax liabilities	0	1
Net amount in AOCI after-tax	(2)	(4)
Defined Benefit | Foreign Plan
Defined Benefit Plan Disclosure
Past service cost	0	0
Net actuarial gain (loss)	0	4
Recognized in AOCI pre-tax	0	4
Increase (decrease) by the amount included in deferred tax liabilities	0	(1)
Net amount in AOCI after-tax	0	3
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service cost	(1)	(2)
Net actuarial gain (loss)	(3)	(7)
Recognized in AOCI pre-tax	(4)	(9)
Increase (decrease) by the amount included in deferred tax liabilities	1	2
Net amount in AOCI after-tax	(3)	(7)
Post-Retirement Benefits | Canada
Defined Benefit Plan Disclosure
Past service cost	0	0
Net actuarial gain (loss)	0	(1)
Recognized in AOCI pre-tax	0	(1)
Increase (decrease) by the amount included in deferred tax liabilities	0	0
Net amount in AOCI after-tax	0	(1)
Post-Retirement Benefits | Foreign Plan
Defined Benefit Plan Disclosure
Past service cost	(1)	(2)
Net actuarial gain (loss)	(3)	(6)
Recognized in AOCI pre-tax	(4)	(8)
Increase (decrease) by the amount included in deferred tax liabilities	1	2
Net amount in AOCI after-tax	$ (3)	$ (6)

Pension Plans and Retiree Ben_9

Pension Plans and Retiree Benefits - Schedule of Amounts Recorded in A Regulatory Asset (Liability) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure
Liabilities associated with assets held for sale (note 5)	$ 6	$ 0
Defined Benefit
Defined Benefit Plan Disclosure
Past service credit	0	0
Net actuarial gain	(47)	(26)
Defined benefit plan, total	(47)
Less: regulatory asset (liability) reclassified to assets (liabilities associated with assets) held for sale	(3)
Liabilities associated with assets held for sale (note 5)	0	0
Recognized in regulatory liability	(50)	(26)
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit	(64)	(77)
Net actuarial gain	(123)	(289)
Defined benefit plan, total	(187)
Less: regulatory asset (liability) reclassified to assets (liabilities associated with assets) held for sale	3
Liabilities associated with assets held for sale (note 5)	6	0
Recognized in regulatory liability	(184)	(366)
Canada | Defined Benefit
Defined Benefit Plan Disclosure
Past service credit	0	0
Net actuarial gain	0	0
Defined benefit plan, total	0
Less: regulatory asset (liability) reclassified to assets (liabilities associated with assets) held for sale	0
Recognized in regulatory liability	0	0
Canada | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit	0	0
Net actuarial gain	0	0
Defined benefit plan, total	0
Less: regulatory asset (liability) reclassified to assets (liabilities associated with assets) held for sale	0
Recognized in regulatory liability	0	0
Foreign Plan | Defined Benefit
Defined Benefit Plan Disclosure
Past service credit	0	0
Net actuarial gain	(47)	(26)
Defined benefit plan, total	(47)
Less: regulatory asset (liability) reclassified to assets (liabilities associated with assets) held for sale	(3)
Recognized in regulatory liability	(50)	(26)
Foreign Plan | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Past service credit	(64)	(77)
Net actuarial gain	(123)	(289)
Defined benefit plan, total	(187)
Less: regulatory asset (liability) reclassified to assets (liabilities associated with assets) held for sale	3
Recognized in regulatory liability	$ (184)	$ (366)

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, 2022	Dec. 31, 2021
Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	$ 25	$ 27
Interest cost	53	50
Expected return on plan assets	(79)	(77)
Amortization of past service (credit)	0	0
Amortization of net actuarial loss (gain)	2	7
Plan settlements		2
Net benefit cost (income) recognized	1	9
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	10	10
Interest cost	13	12
Expected return on plan assets	(38)	(34)
Amortization of past service (credit)	(18)	(18)
Amortization of net actuarial loss (gain)	(7)	(6)
Plan settlements		0
Net benefit cost (income) recognized	(40)	(36)
Canada | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	3	4
Interest cost	1	1
Expected return on plan assets	0	(1)
Amortization of past service (credit)	0	0
Amortization of net actuarial loss (gain)	0	1
Plan settlements		0
Net benefit cost (income) recognized	4	5
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 (credit)	0	0
Amortization of net actuarial loss (gain)	0	0
Plan settlements		0
Net benefit cost (income) recognized	0	0
Foreign Plan | Defined Benefit
Defined Benefit Plan Disclosure
Current service cost	22	23
Interest cost	52	49
Expected return on plan assets	(79)	(76)
Amortization of past service (credit)	0	0
Amortization of net actuarial loss (gain)	2	6
Plan settlements		2
Net benefit cost (income) recognized	(3)	4
Foreign Plan | Post-Retirement Benefits
Defined Benefit Plan Disclosure
Current service cost	10	10
Interest cost	13	12
Expected return on plan assets	(38)	(34)
Amortization of past service (credit)	(18)	(18)
Amortization of net actuarial loss (gain)	(7)	(6)
Plan settlements		0
Net benefit cost (income) recognized	$ (40)	$ (36)

Pension Plans and Retiree Be_11

Pension Plans and Retiree Benefits - Schedule of Collective Investment Mixes for Plan Assets (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Canada | Fixed income
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	100%
Defined Benefit
Defined Benefit Plan Disclosure
Fair value of Plan Assets	$ 1,372,000,000	$ 1,731,000,000	$ 1,683,000,000
Plan assets, total	1,279,000,000
Defined Benefit | Canada
Defined Benefit Plan Disclosure
Fair value of Plan Assets	13,000,000	16,000,000	16,000,000
Plan assets, total	13,000,000
Defined Benefit | Canada | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 13,000,000	$ 16,000,000
Percentage of Plan Assets	100%	100%
Defined Benefit | Canada | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2,000,000	$ 2,000,000
Percentage of Plan Assets	15%	13%
Defined Benefit | Canada | Fair value | Fixed income | Canadian bonds
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 11,000,000	$ 14,000,000
Percentage of Plan Assets	85%	87%
Defined Benefit | Canada | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 13,000,000	$ 16,000,000
Defined Benefit | Canada | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	2,000,000	2,000,000
Defined Benefit | Canada | Level 1 | Fixed income | Canadian bonds
Defined Benefit Plan Disclosure
Total fair value of plan investment	11,000,000	14,000,000
Defined Benefit | Canada | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Defined Benefit | Canada | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Defined Benefit | Canada | Level 2 | Fixed income | Canadian bonds
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Defined Benefit | Foreign Plan
Defined Benefit Plan Disclosure
Total fair value of plan investment	1,354,000,000	1,710,000,000
Less: investments reclassified to assets held for sale	(93,000,000)
Fair value of Plan Assets	$ 1,359,000,000	$ 1,715,000,000	1,667,000,000
Percentage of Plan Assets	100%	100%
Percentage of Plan Asset before net receivable	107%	100%
Percentage of Plan Assets before reclassified asset held for sale	107%
Percentage of Plan Assets, investments reclassified to assets held for sale	(7.00%)
Plan assets, total	$ 1,266,000,000
Target asset mix (as a percent)	500%	0%
Defined Benefit | Foreign Plan | Income producing property
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	16%	900%
Defined Benefit | Foreign Plan | Private equity/limited partnership
Defined Benefit Plan Disclosure
Total fair value of plan investment		$ 46,000,000
Percentage of Plan Asset before net receivable		3%
Defined Benefit | Foreign Plan | Pooled separate accounts
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 43,000,000	$ 38,000,000
Percentage of Plan Asset before net receivable	3%	2%
Defined Benefit | Foreign Plan | Pooled separate accounts | Income producing property
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	100%	100%
Defined Benefit | Foreign Plan | Collective trust fund
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 279,000,000	$ 467,000,000
Percentage of Plan Asset before net receivable	22%	27%
Target asset mix (as a percent)	79%	91%
Defined Benefit | Foreign Plan | Net receivable
Defined Benefit Plan Disclosure
Net receivable	$ 5,000,000	$ 5,000,000
Percentage of Plan Assets Net receivable	0%	0%
Defined Benefit | Foreign Plan | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 1,032,000,000	$ 1,159,000,000
Percentage of Plan Assets	82%	68%
Defined Benefit | Foreign Plan | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2,000,000	$ 2,000,000
Percentage of Plan Assets	0%	0%
Defined Benefit | Foreign Plan | Fair value | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2,000,000	$ 2,000,000
Percentage of Plan Assets	0%	0%
Defined Benefit | Foreign Plan | Fair value | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 247,000,000	$ 290,000,000
Percentage of Plan Assets	20%	17%
Defined Benefit | Foreign Plan | Fair value | Fixed income | Government debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 413,000,000	$ 346,000,000
Percentage of Plan Assets	33%	20%
Defined Benefit | Foreign Plan | Fair value | Fixed income | Corporate debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 355,000,000	$ 502,000,000
Percentage of Plan Assets	28%	30%
Defined Benefit | Foreign Plan | Fair value | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 2,000,000	$ 6,000,000
Percentage of Plan Assets	0%	0%
Defined Benefit | Foreign Plan | Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 11,000,000	$ 11,000,000
Percentage of Plan Assets	1%	1%
Defined Benefit | Foreign Plan | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 361,000,000	$ 412,000,000
Defined Benefit | Foreign Plan | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	2,000,000	2,000,000
Defined Benefit | Foreign Plan | Level 1 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	2,000,000	2,000,000
Defined Benefit | Foreign Plan | Level 1 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	247,000,000	290,000,000
Defined Benefit | Foreign Plan | Level 1 | Fixed income | Government debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	80,000,000	39,000,000
Defined Benefit | Foreign Plan | Level 1 | Fixed income | Corporate debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	30,000,000	79,000,000
Defined Benefit | Foreign Plan | Level 1 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Defined Benefit | Foreign Plan | Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Defined Benefit | Foreign Plan | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	671,000,000	747,000,000
Defined Benefit | Foreign Plan | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Defined Benefit | Foreign Plan | Level 2 | Equities | Canada
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Defined Benefit | Foreign Plan | Level 2 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Defined Benefit | Foreign Plan | Level 2 | Fixed income | Government debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	333,000,000	307,000,000
Defined Benefit | Foreign Plan | Level 2 | Fixed income | Corporate debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	325,000,000	423,000,000
Defined Benefit | Foreign Plan | Level 2 | Derivatives
Defined Benefit Plan Disclosure
Total fair value of plan investment	2,000,000	6,000,000
Defined Benefit | Foreign Plan | Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	11,000,000	11,000,000
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Fair value of Plan Assets	845,000,000	1,058,000,000	1,016,000,000
Plan assets, total	842,000,000
Post-Retirement Benefits | Canada
Defined Benefit Plan Disclosure
Fair value of Plan Assets	0	0	0
Plan assets, total	0
Post-Retirement Benefits | Foreign Plan
Defined Benefit Plan Disclosure
Total fair value of plan investment		1,058,000,000
Less: investments reclassified to assets held for sale	(3,000,000)
Fair value of Plan Assets	$ 845,000,000	$ 1,058,000,000	$ 1,016,000,000
Percentage of Plan Assets	100%	100%
Percentage of Plan Assets before reclassified asset held for sale	101%
Percentage of Plan Assets, investments reclassified to assets held for sale	(1.00%)
Plan assets, total	$ 842,000,000
Post-Retirement Benefits | Foreign Plan | Fixed income | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	23%	21%
Post-Retirement Benefits | Foreign Plan | Commingled funds
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 596,000,000	$ 760,000,000
Percentage of Plan Assets	71%	71%
Post-Retirement Benefits | Foreign Plan | Commingled funds | WGL Holdings | Common stock large cap
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	49%	51%
Post-Retirement Benefits | Foreign Plan | Corporate bonds | WGL Holdings
Defined Benefit Plan Disclosure
Target asset mix (as a percent)	28%	28%
Post-Retirement Benefits | Foreign Plan | Fair value
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 249,000,000	$ 298,000,000
Percentage of Plan Assets	30%	29%
Post-Retirement Benefits | Foreign Plan | Fair value | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 8,000,000	$ 6,000,000
Percentage of Plan Assets	1%	1%
Post-Retirement Benefits | Foreign Plan | Fair value | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 50,000,000	$ 60,000,000
Percentage of Plan Assets	6%	6%
Post-Retirement Benefits | Foreign Plan | Fair value | Fixed income | Government debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 101,000,000	$ 104,000,000
Percentage of Plan Assets	12%	10%
Post-Retirement Benefits | Foreign Plan | Fair value | Fixed income | Corporate debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 85,000,000	$ 122,000,000
Percentage of Plan Assets	10%	11%
Post-Retirement Benefits | Foreign Plan | Fair value | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 5,000,000	$ 6,000,000
Percentage of Plan Assets	1%	1%
Post-Retirement Benefits | Foreign Plan | Level 1
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 87,000,000	$ 96,000,000
Post-Retirement Benefits | Foreign Plan | Level 1 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	8,000,000	6,000,000
Post-Retirement Benefits | Foreign Plan | Level 1 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	50,000,000	60,000,000
Post-Retirement Benefits | Foreign Plan | Level 1 | Fixed income | Government debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	21,000,000	10,000,000
Post-Retirement Benefits | Foreign Plan | Level 1 | Fixed income | Corporate debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	8,000,000	20,000,000
Post-Retirement Benefits | Foreign Plan | Level 1 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Post-Retirement Benefits | Foreign Plan | Level 2
Defined Benefit Plan Disclosure
Total fair value of plan investment	162,000,000	202,000,000
Post-Retirement Benefits | Foreign Plan | Level 2 | Cash and short-term equivalents
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Post-Retirement Benefits | Foreign Plan | Level 2 | Equities | Foreign
Defined Benefit Plan Disclosure
Total fair value of plan investment	0	0
Post-Retirement Benefits | Foreign Plan | Level 2 | Fixed income | Government debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	80,000,000	94,000,000
Post-Retirement Benefits | Foreign Plan | Level 2 | Fixed income | Corporate debt
Defined Benefit Plan Disclosure
Total fair value of plan investment	77,000,000	102,000,000
Post-Retirement Benefits | Foreign Plan | Level 2 | Other
Defined Benefit Plan Disclosure
Total fair value of plan investment	$ 5,000,000	$ 6,000,000

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, 2022	Dec. 31, 2021
Defined Benefit | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	2.50%	1.90%
Expected long-term rate of return on plan assets (percent)	2.83%	4.75%
Rate of compensation increase (percent)	2.50%	1%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	5.05%	2.50%
Rate of compensation increase (percent)	2.50%	2.50%
Defined Benefit | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	5.05%	2.85%
Expected long-term rate of return on plan assets (percent)	6.50%	7%
Rate of compensation increase (percent)	4%	4%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	5.60%	3.10%
Rate of compensation increase (percent)	4%	4%
Post-Retirement Benefits
Significant actuarial assumptions used in measuring benefit obligations
Rate of compensation increase (percent)	3%
Post-Retirement Benefits | Minimum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)		2.50%
Expected long-term rate of return on plan assets (percent)	3%	3.37%
Rate of compensation increase (percent)		250%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	5.30%
Post-Retirement Benefits | Maximum
Significant actuarial assumptions used in measuring net benefit plan costs
Discount rate (percent)	3.10%	3.10%
Expected long-term rate of return on plan assets (percent)	6.50%	7%
Rate of compensation increase (percent)	3%	3%
Significant actuarial assumptions used in measuring benefit obligations
Discount rate (percent)	5.70%	3.10%
Rate of compensation increase (percent)		3%

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, 2022 CAD ($)
Defined Benefit
Defined Benefit Plan Disclosure
Expected employer contributions, 2023	$ 8
Expected benefit payments:
2023	95
2024	94
2025	96
2026	97
2027	98
2028 - 2032	501
Post-Retirement Benefits
Defined Benefit Plan Disclosure
Expected employer contributions, 2023	0
Expected benefit payments:
2023	23
2024	22
2025	22
2026	23
2027	23
2028 - 2032	$ 119

Commitments, Guarantees, and _3

Commitments, Guarantees, and Contingencies - Schedule of Future Payment Commitments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2014 hour	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2015
Operating Leases
2023			$ 95
2024			65
2025			50
2026			41
2027			25
2028 & beyond			73
Total lease payments			349
Commitments, 2023			3,450
Commitments, 2024			2,741
Commitments, 2025			2,092
Commitments, 2026			1,702
Commitments, 2027			1,559
Commitments, 2028 and beyond			4,758
Commitments			16,302
Purchase commitment, remaining minimum amount committed			2,600
Undiscounted cash flows			41
Service agreement payable			148
Service agreement payable in five years			53
Environmental
Other Commitment, Fiscal Year Maturity [Abstract]
2023			10
2024			1
2025			1
2026			1
2027			0
2027			0
Total			13
Post Acquisition Contingent Payments
Other Commitment, Fiscal Year Maturity [Abstract]
2024			0
2025			0
2026			0
2027			0
2027			0
Total			5
Merger commitments
Other Commitment, Fiscal Year Maturity [Abstract]
2023			5
2024			2
2025			1
2026			1
2027			1
2027			0
Total			10
Operating Leases
Cumulative expenses incurred but not yet paid				$ 8
Capital projects
Other Commitment, Fiscal Year Maturity [Abstract]
2023			32
2024			0
2025			0
2026			0
2027			0
2027			0
Total			32
Gas purchase
Purchase Obligation, Fiscal Year Maturity [Abstract]
2023			1,433
2024			1,209
2025			1,088
2026			1,014
2027			1,004
2028 & beyond			3,406
Total			9,154
Operating Leases
Purchase commitment, remaining minimum amount committed				7,600
Purchase obligation			9,154
Pipeline and storage services
Purchase Obligation, Fiscal Year Maturity [Abstract]
2023			474
2024			428
2025			392
2026			347
2027			303
2028 & beyond			749
Total			2,693
Operating Leases
Purchase commitment, remaining minimum amount committed				1,000
Purchase obligation			2,693
LPG purchase
Purchase Obligation, Fiscal Year Maturity [Abstract]
2023			431
2024			336
2025			251
2026			173
2027			150
2028 & beyond			194
Total			1,535
Operating Leases
Purchase obligation			1,535
Electricity purchase
Purchase Obligation, Fiscal Year Maturity [Abstract]
2023			869
2024			616
2025			231
2026			56
2027			16
2028 & beyond			2
Total			1,790
Operating Leases
Purchase obligation			1,790
Operating Lease Contracts
Operating Leases
2023			101
2024			96
2025			81
2026			72
2027			56
2028 & beyond			156
Total lease payments			562
Service agreements
Purchase Obligation, Fiscal Year Maturity [Abstract]
2023			76
2024			53
2025			47
2026			38
2027			29
2028 & beyond			251
Total			494
Operating Leases
Purchase obligation			494
Service agreement term, (EOH/CT) | hour		124,000
Service agreement term		25 years
Service agreement payment period	12 years
Service agreements | Ridley Terminals Inc.
Operating Leases
Lease term (years)					20 years
Crude Oil and Condensate Purchase
Purchase Obligation, Fiscal Year Maturity [Abstract]
2023			14
2024			0
2025			0
2026			0
2027			0
2028 & beyond			0
Total			14
Operating Leases
Purchase obligation			14
Electricity, renewable energy credits
Purchase Obligation, Fiscal Year Maturity [Abstract]
Total				78
Operating Leases
Purchase obligation				$ 78
Very Large Gas Carriers
Operating Leases
2023			11
Undiscounted cash flows			$ 203

Commitments, Guarantees, and _4

Commitments, Guarantees, and Contingencies - Narrative (Details) - Dec. 31, 2022 $ in Millions	CAD ($)	USD ($)
Commitments and Contingencies Disclosure [Abstract]
Guarantees issued on behalf of external parties	$ 0
Loss accrual	$ 5,000,000	$ 4

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Amounts Included in Balance Sheets (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Related Party Transactions [Abstract]
Due from related parties, Accounts receivable	$ 1	$ 7
Due to related parties, Accounts payable	$ 1	$ 7

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Transactions (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Related Party Transactions [Abstract]
Cost of sales	$ 7	$ 6

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, 2022	Dec. 31, 2021
Supplemental Cash Flow Elements [Abstract]
Accounts receivable	$ (691)	$ (206)
Inventory	(324)	(232)
Risk management assets - current	4	4
Other current assets	(1)	4
Regulatory assets - current	13	(3)
Accounts payable and accrued liabilities	377	92
Customer deposits	14	27
Regulatory liabilities - current	98	(12)
Risk management liabilities - current	(6)	(1)
Other current liabilities	(12)	21
Other operating assets and liabilities	(122)	(104)
Changes in operating assets and liabilities	$ (650)	$ (410)

Supplemental Cash Flow Inform_4

Supplemental Cash Flow Information - Schedule of Supplemental Cash Payments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Supplemental Cash Flow Elements [Abstract]
Exercise of stock options	$ 3	$ 2
Common share dividends payable	0	22
Net right-of-use assets obtained in exchange for new operating lease liabilities	(56)	(38)
Net right-of-use assets obtained in exchange for new finance lease liabilities	(14)	(10)
Capital expenditures included in accounts payable and accrued liabilities	6	33
Interest paid (net of capitalized interest)	304	279
Income taxes paid	$ 17	$ 69

Supplemental Cash Flow Inform_5

Supplemental Cash Flow Information - Schedule of Reconciliation of Cash and Restricted Cash Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Cash Flow Elements [Abstract]
Cash and cash equivalents	$ 53	$ 63
Restricted cash holdings from customers - current	0	3
Restricted cash included in prepaid expenses and other current assets	3	8
Restricted cash included in long-term investments and other assets	8	10
Cash, cash equivalents, and restricted cash per Consolidated Statements of Cash Flows	$ 64	$ 84	$ 74

Segmented Information - Schedul

Segmented Information - Schedule of Reconciliation of Segment Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information
Revenues	$ 14,087	$ 10,573
Utilities
Segment Reporting Information
Revenues	4,980	3,936
Midstream
Segment Reporting Information
Revenues	9,010	6,535
Corporate/Other
Segment Reporting Information
Revenues	97	104
Operating Segments
Segment Reporting Information
Revenues		10,575
Operating Segments | Utilities
Segment Reporting Information
Revenues	4,980	3,936
Operating Segments | Midstream
Segment Reporting Information
Revenues	9,010	6,533
Operating Segments | Corporate/Other
Segment Reporting Information
Revenues	97	104
Intersegment revenue
Segment Reporting Information
Revenues	$ 0	(2)
Intersegment revenue | Utilities
Segment Reporting Information
Revenues		0
Intersegment revenue | Midstream
Segment Reporting Information
Revenues		(2)
Intersegment revenue | Corporate/Other
Segment Reporting Information
Revenues		$ 0

Segmented Information - Sched_2

Segmented Information - Schedule of Geographic Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenues from External Customers and Long-Lived Assets
Revenues	$ 14,070	$ 10,724
Property, plant and equipment	11,686	11,323
Long-term	281	311
Canada
Revenues from External Customers and Long-Lived Assets
Revenues	8,915	6,420
Property, plant and equipment	2,930	3,109
Long-term	212	239
United States
Revenues from External Customers and Long-Lived Assets
Revenues	5,155	4,304
Property, plant and equipment	8,756	8,214
Long-term	$ 69	$ 72

Segmented Information - Sched_3

Segmented Information - Schedule of Segment Composition (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information
Segment revenue (note 25)	$ 14,087	$ 10,573
Cost of sales	(11,138)	(7,708)
Operating and administrative	(1,568)	(1,476)
Accretion expenses	(7)	(6)
Depreciation and amortization	(439)	(422)
Provision on assets (note 6)	(6)	(64)
Income from equity investments	13	(261)
Other income	94	81
Foreign exchange gains	10	4
Interest expense	(330)	(275)
Income (loss) before income taxes	716	446
Net additions (reductions) to property, plant and equipment	695	429
Net additions (reductions) to intangible assets	9	6
Utilities
Segment Reporting Information
Segment revenue (note 25)	4,980	3,936
Midstream
Segment Reporting Information
Segment revenue (note 25)	9,010	6,535
Provision on assets (note 6)	(6)	(59)
Corporate/Other
Segment Reporting Information
Segment revenue (note 25)	97	104
Provision on assets (note 6)	0	(5)
Operating Segments
Segment Reporting Information
Segment revenue (note 25)		10,575
Operating Segments | Utilities
Segment Reporting Information
Segment revenue (note 25)	4,980	3,936
Cost of sales	(3,197)	(2,273)
Operating and administrative	(1,023)	(906)
Accretion expenses	(1)	(1)
Depreciation and amortization	(290)	(285)
Provision on assets (note 6)	0	0
Income from equity investments	2	2
Other income	77	65
Foreign exchange gains	0	0
Interest expense	0	0
Income (loss) before income taxes	548	538
Net additions (reductions) to property, plant and equipment	822	705
Net additions (reductions) to intangible assets	2	2
Operating Segments | Midstream
Segment Reporting Information
Segment revenue (note 25)	9,010	6,533
Cost of sales	(7,915)	(5,412)
Operating and administrative	(461)	(475)
Accretion expenses	(6)	(6)
Depreciation and amortization	(116)	(104)
Provision on assets (note 6)	(6)	(59)
Income from equity investments	11	(263)
Other income	9	16
Foreign exchange gains	0	10
Interest expense	0	0
Income (loss) before income taxes	526	242
Net additions (reductions) to property, plant and equipment	(117)	(284)
Net additions (reductions) to intangible assets	6	2
Operating Segments | Corporate/Other
Segment Reporting Information
Segment revenue (note 25)	97	104
Cost of sales	(26)	(25)
Operating and administrative	(84)	(95)
Accretion expenses	0	1
Depreciation and amortization	(33)	(33)
Provision on assets (note 6)	0	(5)
Income from equity investments	0	0
Other income	8	0
Foreign exchange gains	10	(6)
Interest expense	(330)	(275)
Income (loss) before income taxes	(358)	(334)
Net additions (reductions) to property, plant and equipment	(10)	8
Net additions (reductions) to intangible assets	1	2
Intersegment Elimination
Segment Reporting Information
Segment revenue (note 25)	0	(2)
Cost of sales	0	2
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	0	0
Foreign exchange gains	0	0
Interest expense	0	0
Income (loss) 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
Segment revenue (note 25)		0
Intersegment Elimination | Midstream
Segment Reporting Information
Segment revenue (note 25)		(2)
Intersegment Elimination | Corporate/Other
Segment Reporting Information
Segment revenue (note 25)		$ 0

Segmented Information - Sched_4

Segmented Information - Schedule of Goodwill and Total Assets by Segment (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information
Goodwill	$ 5,250	$ 5,153	$ 5,039
Segmented assets	23,965	21,593
Operating Segments | Utilities
Segment Reporting Information
Goodwill	3,718	3,691
Segmented assets	16,782	14,603
Operating Segments | Midstream
Segment Reporting Information
Goodwill	1,532	1,462
Segmented assets	6,728	6,415
Operating Segments | Corporate/Other
Segment Reporting Information
Goodwill	0	0
Segmented assets	$ 455	$ 575

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event $ in Millions, $ in Billions	Mar. 01, 2023 USD ($)	Mar. 01, 2023 CAD ($)
Subsequent Event
Proceeds from sale of interests	$ 800	$ 1.1
ENSTAR
Subsequent Event
Controlling interest (percent)	100%	100%
CINGSA
Subsequent Event
Controlling interest (percent)	65%	65%