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% |