TransAlta (TAC) 40-F 23 Feb 23 2022 FY Annual report (Canada) Financial data

Cover

Cover	12 Months Ended
	Dec. 31, 2022 shares
Entity Addresses [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Entity File Number	001-15214
Entity Registrant Name	TRANSALTA CORPORATION
Entity Incorporation, State or Country Code	Z4
Entity Address, Address Line One	110-12th Avenue S.W., Box 1900, Station “M”
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Postal Zip Code	T2P 2M1
City Area Code	403
Local Phone Number	267-7110
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	268,290,896
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Central Index Key	0001144800
Business Contact
Entity Addresses [Line Items]
Contact Personnel Name	TransAlta Centralia Generation LLC
Entity Address, Address Line One	913 Big Hanaford Road
Entity Address, City or Town	Centralia
Entity Address, State or Province	WA
Entity Address, Postal Zip Code	98531
City Area Code	360
Local Phone Number	736-9901

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	Chartered Professional Accountants
Auditor Location	Calgary, Canada
Auditor Firm ID	1263

Consolidated Statements of Earn

Consolidated Statements of Earnings (Loss) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Profit or loss [abstract]
Revenues	$ 2,976	$ 2,721	$ 2,101
Fuel and purchased power	1,263	1,054	805
Carbon compliance	78	178	163
Gross margin	1,635	1,489	1,133
Operations, maintenance, and administration	521	511	472
Depreciation and amortization	599	529	654
Asset impairment charges	9	648	84
Taxes, other than income taxes	33	32	33
Net other operating (income) loss	(58)	8	(11)
Operating income (loss)	531	(239)	(99)
Equity income (loss)	9	9	1
Finance lease income	19	25	7
Net interest expense	(262)	(245)	(238)
Foreign exchange gain	4	16	17
Gain on sale of assets and other	52	54	9
Earnings (loss) before income taxes	353	(380)	(303)
Income tax expense (recovery)	192	45	(50)
Net earnings (loss)	161	(425)	(253)
Net earnings (loss) attributable to:
TransAlta shareholders	50	(537)	(287)
Non-controlling interests	111	112	34
Net earnings (loss)	161	(425)	(253)
Preferred share dividends	46	39	49
Net earnings (loss) attributable to common shareholders	$ 4	$ (576)	$ (336)
Weighted average number of common shares outstanding in the year (in shares)	271,000	271,000	275,000
Net earnings (loss) per share attributable to common shareholders, basic (in CAD per share)	$ 0.01	$ (2.13)	$ (1.22)
Net earnings (loss) per share attributable to common shareholders, diluted (in CAD per share)	$ 0.01	$ (2.13)	$ (1.22)

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Loss - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of comprehensive income [abstract]
Net earnings (loss)		$ 161	$ (425)	$ (253)
Other comprehensive loss
Net actuarial gains (losses) on defined benefit plans, net of tax	[1]	37	37	(11)
Fair value losses on third-party investments, net of tax		(1)	0	0
Losses on derivatives designated as cash flow hedges, net of tax		0	0	(1)
Total items that will not be reclassified subsequently to net earnings (loss)		36	37	(12)
Gains (losses) on translating net assets of foreign operations, net of tax		21	(14)	(11)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax	[2]	(25)	0	11
Gains (losses) on derivatives designated as cash flow hedges, net of tax	[3]	(556)	(200)	20
Reclassification of losses (gains) on derivatives designated as cash flow hedges to net earnings (loss), net of tax	[4]	100	(8)	(110)
Total items that will be reclassified subsequently to net earnings (loss)		(460)	(222)	(90)
Other comprehensive loss		(424)	(185)	(102)
Total comprehensive loss		(263)	(610)	(355)
Total comprehensive income (loss) attributable to:
TransAlta shareholders		(318)	(693)	(439)
Non-controlling interests		$ 55	$ 83	$ 84
[1]Net of income tax expense of $12 million for the year ended Dec. 31, 2022 (2021 – $11 million expense, 2020 – $3 million recovery).[2]Net of income tax recovery of $3 million for the year ended Dec. 31, 2022 (2021 and 2020 – nil).[3]Net of income tax recovery of $138 million for the year ended Dec. 31, 2022 (2021 – $55 million recovery, 2020 – $8 million expense).[4]Net of reclassification of income tax expense of $26 million for the year ended Dec. 31, 2022 (2021 – $2 million recovery,  2020 – $31 million recovery).

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Loss (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of comprehensive income [abstract]
Net impact to net actuarial gains (losses)	$ 12	$ 11	$ (3)
Net income tax expense (recovery) relating to gains (losses) on financial instruments	(3)	0	0
Net of income tax (recovery) expense	(138)	(55)	8
Net of reclassification of income tax expense (recovery)	$ 26	$ (2)	$ (31)

Consolidated Statements of Fina

Consolidated Statements of Financial Position - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 1,134	$ 947
Restricted cash	70	70
Trade and other receivables	1,589	651
Prepaid expenses	33	29
Risk management assets	709	308
Inventory	157	167
Assets held for sale	22	25
Current assets	3,714	2,197
Non-current assets
Investments	129	105
Long-term portion of finance lease receivables	129	185
Risk management assets	161	399
Property, plant and equipment	5,556	5,320
Right-of-use assets	126	95
Intangible assets	252	256
Goodwill	464	463
Deferred income tax assets	50	64
Other assets	160	142
Total assets	10,741	9,226
Current liabilities
Bank overdraft	16	0
Accounts payable and accrued liabilities	1,346	689
Current portion of decommissioning and other provisions	70	48
Risk management liabilities	1,129	261
Current portion of contract liabilities	8	19
Income taxes payable	73	8
Dividends payable	68	62
Current portion of long-term debt and lease liabilities	178	844
Current liabilities	2,888	1,931
Non-current liabilities
Credit facilities, long-term debt and lease liabilities	3,475	2,423
Exchangeable securities	739	735
Decommissioning and other provisions	659	779
Deferred income tax liabilities	352	354
Risk management liabilities	333	145
Contract liabilities	12	13
Defined benefit obligation and other long-term liabilities	294	253
Equity
Common shares	2,863	2,901
Preferred shares	942	942
Contributed surplus	41	46
Deficit	(2,514)	(2,453)
Accumulated other comprehensive income (loss)	(222)	146
Equity attributable to shareholders	1,110	1,582
Non-controlling interests	879	1,011
Total equity	1,989	2,593
Total liabilities and equity	10,741	9,226
Cost
Non-current assets
Property, plant and equipment	14,012	13,389
Intangible assets	868	827
Current liabilities
Bank overdraft	16
Accounts payable and accrued liabilities	1,346
Dividends payable	68
Non-current liabilities
Exchangeable securities	750
Accumulated depreciation
Non-current assets
Property, plant and equipment	(8,456)	(8,069)
Intangible assets	$ (616)	$ (571)

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - CAD ($) $ in Millions	Total	Common shares	Preferred shares	Issued capital Common shares	Issued capital Preferred shares	Contributed surplus	Deficit	Deficit Common shares	Deficit Preferred shares	Accumulated other comprehensive income (loss)	[1]	Attributable to shareholders	Attributable to shareholders Common shares	Attributable to shareholders Preferred shares	Attributable to non-controlling interests
Balance, beginning of year at Dec. 31, 2020	$ 3,436			$ 2,896	$ 942	$ 38	$ (1,826)			$ 302		$ 2,352			$ 1,084
Changes in equity [abstract]
Net earnings (loss)	(425)						(537)					(537)			112
Other comprehensive income (loss):
Net losses on translating net assets of foreign operations, net of hedges and of tax	(14)									(14)		(14)
Net losses on derivatives designated as cash flow hedges, net of tax	(208)									(208)		(208)
Net actuarial gains on defined benefits plans, net of tax	37									37		37
Intercompany and third-party FVTOCI investments	0									29		29			(29)
Total comprehensive loss	(610)						(537)			(156)		(693)			83
Dividends	(39)	$ (51)	$ (39)					$ (51)	$ (39)				$ (51)	$ (39)
Effect of share-based payment plans	13			5		8						13
Distributions paid and payable, to non-controlling interests	(156)														(156)
Balance, end of year at Dec. 31, 2021	2,593			2,901	942	46	(2,453)			146		1,582			1,011
Changes in equity [abstract]
Net earnings (loss)	161						50					50			111
Other comprehensive income (loss):
Net losses on translating net assets of foreign operations, net of hedges and of tax	(4)									(4)		(4)
Net losses on derivatives designated as cash flow hedges, net of tax	(456)									(456)		(456)			0
Net actuarial gains on defined benefits plans, net of tax	37									37		37
Intercompany and third-party FVTOCI investments	(1)									55		55			(56)
Total comprehensive loss	(263)						50			(368)		(318)			55
Dividends	(46)	$ (57)	$ (46)					$ (57)	$ (46)				$ (57)	$ (46)
Shares purchased under NCIB	(54)			(46)			(8)					(54)
Effect of share-based payment plans	3			8		(5)						3
Distributions paid and payable, to non-controlling interests	(187)														(187)
Balance, end of year at Dec. 31, 2022	$ 1,989			$ 2,863	$ 942	$ 41	$ (2,514)			$ (222)		$ 1,110			$ 879
[1]Refer to Note 30 for details on components of and changes in, accumulated other comprehensive income (loss).

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating activities
Net earnings (loss)	$ 161	$ (425)	$ (253)
Depreciation and amortization	599	719	798
Net gain on sale of assets	(32)	(54)	(9)
Accretion of provisions	49	32	30
Decommissioning and restoration costs settled	(35)	(18)	(18)
Deferred income tax expense (recovery)	127	(11)	(85)
Unrealized (gain) loss from risk management activities	385	(34)	42
Unrealized foreign exchange (gain) loss	(82)	(24)	1
Provisions and contract liabilities	19	(41)	9
Asset impairment charges	9	648	84
Equity income, net of distributions from investments	(4)	(5)	(1)
Other non-cash items	(3)	40	15
Cash flow from operations before changes in working capital	1,193	827	613
Change in non-cash operating working capital	(316)	174	89
Cash flow from operating activities	877	1,001	702
Investing activities
Additions to property, plant and equipment	(918)	(480)	(486)
Additions to intangibles assets	(31)	(9)	(14)
Restricted cash	0	(1)	(39)
Repayments (advances) in loan receivable	18
Repayments (advances) in Loan receivable		(3)	(5)
Acquisitions, net of cash acquired	(10)	(120)	(32)
Investments	(10)	0	(102)
Proceeds on sale of Pioneer Pipeline	0	128	0
Proceeds on sale of property, plant and equipment	66	39	6
Realized gain (loss) on financial instruments	27	(6)	2
Decrease in finance lease receivable	46	41	17
Other	45	(16)	(12)
Change in non-cash investing working capital balances	26	(45)	(22)
Cash flow used in investing activities	(741)	(472)	(687)
Financing activities
Net increase (decrease) in borrowings under credit facilities	449	(114)	(106)
Repayment of long-term debt	(621)	(92)	(489)
Issuance of long-term debt	532	173	753
Issuance of exchangeable securities	0	0	400
Repurchase of common shares under NCIB	(52)	(4)	(57)
Proceeds on issuance of common shares	3	8	0
Realized gains on financial instruments	42	3	3
Distributions paid to subsidiaries' non-controlling interests	(187)	(156)	(97)
Decrease in lease liabilities	(9)	(8)	(25)
Financing fees and other	(13)	(4)	(11)
Change in non-cash financing working capital balances	(2)	(1)	(13)
Cash flow from (used in) financing activities	45	(282)	272
Cash flow from operating, investing and financing activities	181	247	287
Effect of translation on foreign currency cash	6	(3)	5
Increase in cash and cash equivalents	187	244	292
Cash and cash equivalents, beginning of year	1,134	947	703
Cash and cash equivalents, end of year	1,134	947	703
Supplemental cash flow information
Cash taxes paid	67	57	36
Cash interest paid	229	220	201
Common shares
Financing activities
Dividends paid	(54)	(48)	(47)
Preferred shares
Financing activities
Dividends paid	$ (43)	$ (39)	$ (39)

Corporate Information

Corporate Information	12 Months Ended
	Dec. 31, 2022
Corporate Information and Statement of IFRS Compliance [Abstract]
Corporate Information	Corporate Information A. Description of the Business TransAlta Corporation (“TransAlta” or the “Company”) was incorporated under the Canada Business Corporations Act in March 1985. The Company became a public company in December 1992. The Company's head office is located in Calgary, Alberta. Operating Segments Generation Segments The four generation segments of the Company are as follows: Hydro, Wind and Solar, Gas, and Energy Transition. The Company directly or indirectly owns and operates hydro, wind and solar, natural-gas-fired facilities, a coal-fired facility and natural gas pipeline operations in Canada, the United States (“US”) and Australia. The Wind and Solar segment includes the financial results, on a proportionate basis, of our investment in SP Skookumchuck Investment, LLC ("Skookumchuck"). Segment revenues are derived from the availability and production of electricity and steam as well as ancillary services. Energy Marketing Segment The Energy Marketing segment derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives. The Energy Marketing segment also performs services on behalf of certain assets outside of Alberta for the power marketing of available generating capacity as well as the procurement of the fuel and transmission needs of those assets by utilizing contracts of various durations for the forward sales of electricity and for the purchase of natural gas and transmission capacity. The results of these power marketing activities are included in the gross margin of each generation segment. The Energy Marketing segment allocates charges to recognize the performance of these activities to the applicable generation segment thereto. Corporate Segment The Corporate segment includes the Company’s central finance, legal, administrative, corporate development, and investor relations functions. Activities and charges directly or reasonably attributable to other segments are allocated thereto. The Corporate segment includes our investment in EMG International, LLC ("EMG"), a wastewater treatment processing company, which is accounted for using the equity method. Revenues are derived from the design and construction of wastewater treatment facilities. B. Basis of Preparation These consolidated financial statements have been prepared by management in compliance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The consolidated financial statements have been prepared on a historical cost basis except for financial instruments, which are measured at fair value, as explained in the following accounting policies. These consolidated financial statements were authorized for issue by TransAlta's Board of Directors (the "Board") on Feb. 22, 2023. C. Basis of Consolidation The consolidated financial statements include the accounts of the Company and the subsidiaries that it controls. Control exists when the Company is exposed, or has rights, to variable returns from its involvement with the subsidiary and has the ability to affect the returns through its power over the subsidiary. The financial statements of the subsidiaries are prepared for the same reporting period and apply consistent accounting policies as the parent company.

Material Accounting Policies

Material Accounting Policies	12 Months Ended
	Dec. 31, 2022
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Material Accounting Policies	Material Accounting Policies The Company has reviewed its material accounting policies. The definition of material that management has used to judgmentally determine disclosure is that information is material if omitting it or misstating it could influence decisions users make on the basis of financial information. A. Revenue Recognition I. Revenue from Contracts with Customers The majority of the Company’s revenues from contracts with customers are derived from the sale of generation capacity, electricity, thermal energy, environmental attributes and byproducts of power generation. The Company evaluates whether the contracts it enters into meet the definition of a contract with a customer at the inception of the contract and on an ongoing basis if there is an indication of significant changes in facts and circumstances. Contract modifications are accounted for as separate contracts when the consideration for the additional promised goods reflects a stand-alone selling price. Otherwise, contract modifications are accounted for as part of the existing contract. If the additional goods are not considered distinct the transaction price can be affected and adjustments to previously recognized revenue can occur. If the additional goods are distinct, the existing and modified contracts are treated together as a new contract, with impacts reflected prospectively from the modification date. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the goods or services are transferred to the customer. For certain contracts, revenue may be recognized at the invoiced amount, as permitted using the invoice practical expedient, if such amount corresponds directly with the Company’s performance to date. The Company excludes amounts collected on behalf of third parties from revenue. Performance Obligations Each promised good or service is accounted for separately as a performance obligation if it is distinct. The Company’s contracts may contain more than one performance obligation. Transaction Price The Company allocates the transaction price in the contract to each performance obligation. Transaction price allocated to performance obligations may include variable consideration. Variable consideration is included in the transaction price for each performance obligation when it is highly probable that a significant reversal of the cumulative variable revenue will not occur. Variable consideration that has previously been constrained is assessed at each reporting period to determine whether the constraint is lifted. The consideration contained in some of the Company's contracts with customers is primarily variable and may include both variability in quantity and pricing, such as: revenues can be dependent upon future production volumes that are driven by customer or market demand or by the operational ability of the plant; revenues can be dependent upon the variable cost of producing the energy; revenues can be dependent upon market prices; and revenues can be subject to various indices and escalators. When multiple performance obligations are present in a contract, the transaction price is allocated to each performance obligation in an amount that depicts the consideration the Company expects to be entitled to in exchange for transferring the good or service. The Company estimates the amount of the transaction price to allocate to individual performance obligations based on their relative stand-alone selling prices, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions. Recognition The nature, timing of recognition of satisfied performance obligations and payment terms for the Company’s goods and services are described below: Good or service Description Capacity Capacity refers to the availability of an asset to deliver goods or services. Customers typically pay for capacity for each defined time period (e.g., monthly) in an amount representative of the availability of the asset for the defined time period. Obligations to deliver capacity are satisfied over time and revenue is recognized using a time-based measure. Contracts for capacity are typically long term in nature. Payments are typically received from customers on a monthly basis. Contract power The sale of contract power refers to the delivery of units of electricity to a customer under the terms of a contract. Customers pay a contractually specified price for the output at the end of predefined contractual periods (e.g., monthly). Obligations to deliver electricity are satisfied over time and revenue is recognized using a units-based output measure (i.e., megawatt hours). Contracts for power are typically long term in nature and payments are typically received on a monthly basis. Thermal energy Thermal energy refers to the delivery of units of steam to a customer under the terms of a contract. Customers pay a contractually specified price for the output at the end of predefined contractual periods (e.g., monthly). Obligations to deliver steam are satisfied over time and revenue is recognized using a units-based output measure (i.e., gigajoules). Contracts for thermal energy are typically long term in nature. Payments are typically received from customers on a monthly basis. Environmental attributes Environmental attributes refers to the delivery of renewable energy certificates, green attributes and other similar items. Customers may contract for environmental attributes in conjunction with the purchase of power, in which case the customer pays for the attributes in the month subsequent to the delivery of the power. Alternatively, customers pay upon delivery of the environmental attributes. Obligations to deliver environmental attributes are satisfied at a point in time, generally upon delivery of the item. Generation byproducts Generation byproducts refers to the sale of byproducts from the use of coal in the Company’s US coal operations and the sale of coal to third parties. O bligations to deliver byproducts are satisfied at a point in time, generally upon delivery of the item. Payments are received upon satisfaction of delivery of the byproducts. A contract liability is recorded when the Company receives consideration before the performance obligations have been satisfied. A contract asset is recorded when the Company has rights to consideration for the completion of a performance obligation before it has invoiced the customer. The Company recognizes unconditional rights to consideration separately as a receivable. Contract assets and receivables are evaluated at each reporting period to determine whether there is any objective evidence that they are impaired. II. Revenue from Other Sources Merchant Revenue Revenues from non-contracted capacity (i.e., merchant) comprise energy payments, at market price, for each MWh produced and are recognized upon delivery. Lease Revenue In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Revenues associated with non-lease elements are recognized as goods or services revenues as outlined above. Where the terms and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income. Where the Company retains the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including contingent rents where applicable, is recognized over the term of the contract. Revenue from Derivatives Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales contracts, futures contracts and options, which are used to earn revenues and to gain market information. The Company also enters into contracts for differences and Virtual Power Purchase Agreements ("VPPA"). Contracts for differences are financial contracts whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh. A VPPA is whereby the Company receives the difference between the fixed contract price per MWh and the settled market price. These arrangements are option-based derivatives and judgment is applied to determine if the contract meets the "own use" exemption or if derivative treatment is required. These derivatives are accounted for using fair value accounting. The initial recognition and subsequent changes in fair value affect reported net earnings in the period the change occurs and are presented on a net basis in revenue. The fair values of instruments that remain open at the end of the reporting period represent unrealized gains or losses and are presented on the Consolidated Statements of Financial Position as risk management assets or liabilities. Some of the derivatives used by the Company in trading activities are not traded on an active exchange or have terms that extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives are determined using internal valuation techniques or models. B. Financial Instruments and Hedges I. Financial Instruments Classification and Measurement IFRS 9 introduced the requirement to classify and measure financial assets based on their contractual cash flow characteristics and the Company’s business model for the financial asset. All financial assets and financial liabilities, including derivatives, are recognized at fair value on the Consolidated Statements of Financial Position when the Company becomes party to the contractual provisions of a financial instrument or non-financial derivative contract. Financial assets must be classified and measured at either amortized cost, at fair value through profit or loss (“FVTPL”), or at fair value through other comprehensive income (loss) (“FVTOCI”). Financial assets with contractual cash flows arising on specified dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows, are subsequently measured at amortized cost. Financial assets measured at FVTOCI are those that have contractual cash flows, arising on specific dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows and to sell the financial asset and investments in equity instruments. All other financial assets are subsequently measured at FVTPL. Financial liabilities are classified as FVTPL when the financial liability is held for trading. All other financial liabilities are subsequently measured at amortized cost. Funds received under tax equity investment arrangements are classified as long-term debt. These arrangements are used in the US where project investors acquire an equity investment in the project entity and in return for their investment, are allocated substantially all of the earnings, cash flows and tax benefits (such as production tax credits, investment tax credits, accelerated tax depreciation, as applicable) until they have achieved the agreed upon target rate of return. Once achieved, the arrangements flip, with the Company then receiving the majority of earnings, cash flows and tax benefits. At that time, the tax equity financings will be classified as a non-controlling interest. In applying the effective interest method to tax equity financings, the Company has made an accounting policy choice to recognize the impacts of the tax attributes in net interest expense. The Company enters into a variety of derivative financial instruments to manage its exposure to commodity price risk, interest rate risk and foreign currency exchange risk, including fixed price financial swaps, long-term physical power sale contracts, foreign exchange forward contracts and designating foreign currency debt as a hedge of net investments in foreign operations. Derivatives are initially recognized at fair value at the date the derivative contracts are entered into and are subsequently remeasured to their fair value at the end of each reporting period. The resulting gain or loss is recognized in net earnings immediately, unless the derivative is designated and effective as a hedging instrument, in which case the timing of the recognition in net earnings is dependent on the nature of the hedging relationship. Derivatives embedded in non-derivative host contracts that are not financial assets within the scope of IFRS 9 (e.g., financial liabilities) are treated as separate derivatives when they meet the definition of a derivative, their risks and characteristics are not closely related to those of the host contracts and the host contracts are not measured at FVTPL. Derivatives embedded in hybrid contracts that contain financial asset hosts within the scope of IFRS 9 are not separated and the entire contract is measured at either FVTPL or amortized cost, as appropriate. Financial assets are derecognized when the contractual rights to receive cash flows expire. Financial liabilities are derecognized when the obligation is discharged, cancelled or expired. Financial assets are also derecognized when the Company has transferred its rights to receive cash flows from the asset or has assumed an obligation to pay the received cash flows to a third party under a "pass-through" arrangement and either transferred substantially all the risks and rewards of the asset, or transferred control of the asset. TransAlta will continue to recognize the asset and any associated liability if TransAlta retains substantially all of the risks and rewards of the asset, or retains control of the asset. Continuing involvement that takes the form of a guarantee over the transferred asset is measured at the lower of the original carrying amount of the asset and the maximum amount of consideration that TransAlta could be required to repay. Financial assets and financial liabilities are offset and the net amount is reported in the Consolidated Statements of Financial Position if there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis or to realize the assets and settle the liabilities simultaneously. Transaction costs are expensed as incurred for financial instruments classified or designated as FVTPL. For other financial instruments, such as debt instruments, transaction costs are recognized as part of the carrying amount of the financial instrument. The Company uses the effective interest method of amortization for any transaction costs or fees, premiums or discounts earned or incurred for financial instruments measured at amortized cost. Impairment of Financial Assets TransAlta recognizes an allowance for expected credit losses for financial assets measured at amortized cost as well as certain other instruments. The loss allowance for a financial asset is measured at an amount equal to the lifetime expected credit loss if its credit risk has increased significantly since initial recognition or if the financial asset is a purchased or originated credit-impaired financial asset. If the credit risk on a financial asset has not increased significantly since initial recognition, its loss allowance is measured at an amount equal to the 12-month expected credit loss. For trade receivables, lease receivables and contract assets recognized under IFRS 15, TransAlta applies a simplified approach for measuring the loss allowance. Therefore, the Company does not track changes in credit risk but instead recognizes a loss allowance at an amount equal to the lifetime expected credit losses at each reporting date. The assessment of the expected credit loss is based on historical data and adjusted by forward-looking information. Forward-looking information utilized includes third-party default rates over time, dependent on credit ratings. II. Hedges Where hedge accounting can be applied and the Company chooses to seek hedge accounting treatment, a hedge relationship is designated as a fair value hedge, a cash flow hedge or a hedge of foreign currency exposures of a net investment in a foreign operation. A relationship qualifies for hedge accounting if, at inception, it is formally designated and documented as a hedge and the hedging instrument and the hedged item have values that generally move in opposite direction because of the hedged risk. The documentation includes identification of the hedging instrument and hedged item or transaction, the nature of the risk being hedged, the Company’s risk management objectives and strategy for undertaking the hedge and how hedge effectiveness will be assessed. The process of hedge accounting includes linking derivatives to specific recognized assets and liabilities or to specific firm commitments or highly probable anticipated transactions. The Company formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives used are highly effective in offsetting changes in fair values or cash flows of hedged items. If hedge criteria are not met or the Company does not apply hedge accounting, the derivative is recognized at fair value on the Consolidated Statements of Financial Position, with subsequent changes in fair value recorded in net earnings in the period of change. Fair Value Hedges In a fair value hedging relationship, the carrying amount of the hedged item is adjusted for changes in fair value attributable to the hedged risk, with the changes being recognized in net earnings. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging derivative, which is also recorded in net earnings. For fair value hedges relating to items carried at amortized cost, any adjustment to carrying value is amortized through profit or loss over the remaining term of the hedge using the effective interest rate ("EIR") method. The EIR amortization may begin as soon as an adjustment exists and no later than when the hedged item ceases to be adjusted for changes in its fair value attributable to the risk being hedged. If the hedged item is derecognized, the unamortized fair value is recognized immediately in profit or loss. Cash Flow Hedges In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in other comprehensive income (loss) ("OCI") while any ineffective portion is recognized in net earnings. The cash flow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item. If cash flow hedge accounting is discontinued, the amounts previously recognized in accumulated other comprehensive income (loss) ("AOCI") must remain in AOCI if the hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately reclassified to net earnings as a reclassification adjustment. After discontinuation, once the hedged cash flow occurs, any amount remaining in AOCI must be accounted for depending on the nature of the underlying transaction. Hedges of Foreign Currency Exposures of a Net Investment in a Foreign Operation In hedging of a foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instrument is recognized in OCI and the ineffective portion is recognized in net earnings. The related fair values are recorded in risk management assets or liabilities, as appropriate. The amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in the hedged net investment as a result of a disposal, partial disposal or loss of control. C. Cash and Cash Equivalents Cash and cash equivalents comprises cash and highly liquid investments with original maturities of three months or less. D. Inventory I. Fuel The Company’s inventory balance is composed of coal and natural gas used as fuel, which is measured at the lower of weighted average cost and net realizable value. The cost of natural gas and purchased coal inventory includes all applicable expenditures and charges incurred in bringing the inventory to its existing condition and location. II. Energy Marketing Commodity inventories held in the Energy Marketing segment for trading purposes are measured at fair value less costs to sell. Changes in fair value less costs to sell are recognized in net earnings in the period of change. III. Parts, Materials and Supplies Parts, materials and supplies are recorded at the lower of cost and measured at moving average costs and net realizable value. IV. Emission Credits and Allowances Emission credits and allowances are recorded as inventory at cost. Those purchased for use by the Company are recorded at cost and are carried at the lower of weighted average cost and net realizable value. For emission credits that are not ordinarily interchangeable, the Company records the credits using the specific identification method. Credits granted to, or internally generated by, TransAlta are recorded at nil. Emission liabilities are recorded using the best estimate of the amount required by the Company to settle its obligation in excess of government-established caps and targets. To the extent compliance costs are recoverable under the terms of contracts with third parties, the amounts are recognized as revenue in the period of recovery. Emission credits and allowances that are held for trading and that meet the definition of a derivative are accounted for using the fair value method of accounting. Emission credits and allowances that do not satisfy the criteria of a derivative are accounted for using the accrual method. E. Property, Plant and Equipment The Company’s investment in property, plant and equipment (“PP&E”) is initially measured at the original cost of each component at the time of construction, purchase or acquisition. A component is a tangible portion of an asset that can be separately identified and depreciated over its own expected useful life and is expected to provide a benefit for a period in excess of one year. Original cost includes items such as materials, labour, borrowing costs and other directly attributable costs, including the initial estimate of the cost of decommissioning and restoration. Costs are recognized as PP&E if it is probable that future economic benefits will be realized and the cost of the item can be measured reliably. The cost of major spare parts is capitalized and classified as PP&E, as these items can only be used in connection with an item of PP&E. Planned maintenance is performed at regular intervals. Planned major maintenance includes inspection, repair and maintenance of existing components and the replacement of existing components. Costs incurred for planned major maintenance activities are capitalized in the period maintenance activities occur and are amortized on a straight-line basis over the term until the next major maintenance event. Expenditures incurred for the replacement of components during major maintenance are capitalized and amortized over the estimated useful life of such components. The cost of routine repairs and maintenance and the replacement of minor parts is charged to net earnings as incurred. Subsequent to initial recognition and measurement at cost, all classes of PP&E continue to be measured using the cost model and are reported at cost less accumulated depreciation and impairment losses, if any. An item of PP&E or a component is derecognized upon disposal or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition is included in net earnings when the asset is derecognized. The estimate of the useful life of each component of PP&E is based on current facts and past experience and takes into consideration existing long-term sales agreements and contracts, current and forecasted demand and the potential for technological obsolescence. The useful life is used to estimate the rate at which the component of PP&E is depreciated. PP&E assets are subject to depreciation when the asset is considered to be available for use, which is typically upon commencement of commercial operations. Insurance spares that are designated as critical for uninterrupted operation in a particular facility are depreciated over the life of that facility, even if the item is not in service. Capital spares begin to be depreciated when the item is put into service. Each significant component of an item of PP&E is depreciated to its residual value over its estimated useful life, generally using straight-line or unit-of-production methods. Estimated useful lives, residual values and depreciation methods are reviewed annually and are subject to revision based on new or additional information. The effect of a change in useful life, residual value or depreciation method is accounted for prospectively. Estimated remaining useful lives of the components of depreciable assets, categorized by asset class, are as follows: Hydro generation 2-50 years Wind and Solar generation 2-30 years Gas generation 2-35 years Energy Transition 1-10 years Capital spares and other 2-50 years TransAlta capitalizes borrowing costs on capital invested in projects under construction. Upon commencement of commercial operations, capitalized borrowing costs, as a portion of the total cost of the asset, are depreciated over the estimated useful life of the related asset. F. Intangible Assets Intangible assets acquired in a business combination are recognized separately from goodwill at their fair value at the date of acquisition. Intangible assets acquired separately are recognized at cost. Internally generated intangible assets arising from development projects are recognized when certain criteria related to the feasibility of internal use or sale and probable future economic benefits of the intangible asset, are demonstrated. Intangible assets are initially recognized at cost, which is comprised of all directly attributable costs necessary to create, produce and prepare the intangible asset to be capable of operating in the manner intended by management. Subsequent to initial recognition, intangible assets continue to be measured using the cost model and are reported at cost less accumulated amortization and impairment losses, if any. Amortization is included in depreciation and amortization in the Consolidated Statements of Earnings (Loss). Amortization commences when the intangible asset is available for use and is computed on a straight-line basis over the intangible asset’s estimated useful life. Estimated useful lives of intangible assets may be determined, for example, with reference to the term of the related contract or licence agreement. The estimated useful lives and amortization methods are reviewed annually with the effect of any changes being accounted for prospectively. Intangible assets consist of power sale contracts with fixed prices higher than market prices at the date of acquisition, software and intangibles under development. Estimated remaining useful lives of intangible assets are as follows: Software 1-7 years Power sale contracts 1-18 years G. Impairment of Tangible and Intangible Assets Excluding Goodwill At the end of each reporting period, the Company assesses whether there is any indication that PP&E and finite life intangible assets are impaired. Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected operating results; significant changes in the manner in which an asset is used, or in the Company’s overall business strategy; or significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations where the Company is not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence. The Company’s operations, the market and business environment are routinely monitored and judgments and assessments are made to determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is made of the recoverable amount of the asset or cash-generating unit (“CGU”) to which the asset belongs. Recoverable amount is the higher of an asset’s fair value less costs of disposal and its value in use. Fair value is the price that would be received to sell an asset in an orderly transaction between market participants at the measurement date. In determining fair value, recent market transactions are taken into account. If no such transactions can be identified, an appropriate valuation model such as discounted cash flows is used. Value in use is the present value of the estimated future cash flows expected to be derived from the asset from its continued use and ultimate disposal by the Company. If the recoverable amount is less than the carrying amount of the asset or CGU, an asset impairment charge is recognized in net earnings and the asset’s carrying amount is reduced to its recoverable amount. At each reporting date, an assessment is made whether there is any indication that an impairment charge previously recognized may no longer exist or may have decreased. If such indication exists, the recoverable amount of the asset or CGU to which the asset belongs is estimated and, if there has been an increase in the recoverable amount, the impairment charge previously recognized is reversed. Where an impairment charge is subsequently reversed, the carrying amount of the asset is increased to the lesser of the revised estimate of its recoverable amount or the carrying amount that would have been determined (net of depreciation) had no impairment charge been recognized previously. A reversal of an impairment charge is recognized in net earnings. H. Goodwill Goodwill arising in a business combination is recognized as an asset at the date control is acquired. Goodwill is measured as the cost of an acquisition plus the amount of any non-controlling interest in the acquiree (if applicable) less the fair value of the related identifiable assets acquired and liabilities assumed. Goodwill is not subject to amortization, but is tested for impairment at least annually, or more frequently, if an analysis of events and circumstances indicates that a possible impairment may exist. These events could include a significant change in financial position of the CGUs or groups of CGUs to which the goodwill relates or significant negative industry or economic trends. For impairment purposes, goodwill is allocated to each of the Company’s CGUs or groups of CGUs that are expected to benefit from the synergies of the business combination in which the goodwill arose. Accordingly, the Company performs its test for impairment, where the recoverable amount of the CGUs or groups of CGUs to which the goodwill relates is compared to its carrying amount for each operating segment. If the recoverable amount is less than the carrying amount, an impairment charge is recognized in net earnings immediately, by first reducing the carrying amount of the goodwill and then by reducing the carrying amount of the other assets in the unit. An impairment charge recognized for goodwill is not reversed in subsequent periods. I. Income Taxes The Company uses the liability method of accounting for income taxes. Under the liability method, deferred income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and their respective income tax basis (temporary differences). A deferred income tax asset may also be recognized for the benefit expected from unused tax credits and losses available for carryforward, to the extent that it is probable that future taxable earnings will be available against which the tax credits and losses can be applied. Deferred income tax assets and liabilities are measured based on income tax rates and tax laws that are enacted or substantively enacted by the end of the reporting period and that are expected to apply in the years in which temporary differences are expected to be realized or set

Accounting Changes

Accounting Changes	12 Months Ended
	Dec. 31, 2022
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Accounting Changes	Accounting Changes A. Current Accounting Changes Amendments to International Accounting Standards ("IAS") 37 Provisions, Contingent Liabilities and Contingent Assets On May 14, 2020, the IASB issued Onerous Contracts – Cost of Fulfilling a Contract and amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets to specify which costs to include when assessing whether a contract will be loss-making. The amendments are effective for annual periods beginning on or after Jan. 1, 2022, and the Company adopted these amendments as of Jan. 1, 2022. The amendments are effective for contracts for which an entity has not yet fulfilled all its obligations on or after the effective date. No adjustments resulted on adoption of the amendments on Jan. 1, 2022. B. Future Accounting Changes The Company closely monitors both new accounting standards and amendments to existing accounting standards issued by the IASB. The following standard has been issued but is not yet in effect. Amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction On May 7, 2021, the IASB issued amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction . The amendments clarify that the initial recognition exemption under IAS 12 does not apply to transactions such as leases and decommissioning obligations. These transactions give rise to equal and offsetting temporary differences in which deferred tax should be recognized. The amendments are effective for annual periods beginning on or after Jan. 1, 2023, with early application permitted. The Company's current position aligns with the amendment and no financial impact is therefore expected upon adoption on the effective date. Amendments to IAS 1 Classification of Liabilities as Current or Non‐Current In October 2022, the IASB issued amendments to clarify how conditions with which an entity must comply within 12 months after the reporting period affect the classification of a liability, in addition to the amendment from January 2020 where the IASB issued amendments to IAS 1 Presentation of Financial Statements , to provide a more general approach to the presentation of liabilities as current or non‐current based on contractual arrangements in place at the reporting date. These amendments specify that the rights and conditions existing at the end of the reporting period are relevant in determining whether the Company has a right to defer settlement of a liability by at least 12 months, provided that management's expectations are not a relevant consideration as to whether the Company will exercise its rights to defer settlement of a liability and clarify when a liability is considered settled. The amendments are effective for annual periods beginning on or after Jan. 1, 2024, and are to be applied retrospectively. The Company has not yet determined the impact of these amendments on its consolidated financial statements. Amendments to IFRS 16 Lease Liability in a Sale-and-Leaseback In September 2022, the IASB issued Lease Liability in a Sale and Leaseback, which amends IFRS 16 Leases to provide additional specifications when subsequently measuring the lease liability that require the seller-lessee to determine lease payments and revised lease payments in a way that does not result in the seller-lessee recognizing any amount of the gain or loss that relates to the right of use it retains. The current effective date is Jan. 1, 2024. The Company is currently reviewing the impacts of this amendment on its consolidated financial statements. C. Comparative Figures Certain comparative figures have been reclassified to conform to the current period’s presentation. These reclassifications did not impact previously reported net earnings.

Business Acquisitions

Business Acquisitions	12 Months Ended
	Dec. 31, 2022
Business Combinations [Abstract]
Business Acquisitions	Business Acquisitions Acquisition of North Carolina Solar On Nov. 5, 2021, the Company closed the acquisition of a 100 per cent membership interest in CI-II Mitchell Holding LLC, owner of a 122 MW portfolio of operating solar sites located in North Carolina (collectively, “North Carolina Solar”), for cash consideration of US$99 million (including working capital adjustments) and the assumption of existing tax equity obligations. In accordance with IFRS 3 Business Combinations, the substance of the transactions described below constituted a business combination for TransAlta. The fair values of the identifiable assets and liabilities of the acquired entity in the business combinations as at the date of acquisition were: North Carolina Solar Assets Cash and cash equivalents 4 Accounts receivable 4 Property, plant and equipment 146 Right-of-use assets 13 Liabilities Accounts payable and accrued liabilities (4) Lease liabilities (13) Tax equity liability (20) Deferred taxes (3) Decommissioning provisions (4) Net assets acquired 123 Cash consideration 120 Working capital consideration 3 Total purchase consideration transferred 123

Revenue

Revenue	12 Months Ended
	Dec. 31, 2022
Disclosure of revenue from contracts with customers [Abstract]
Revenue	Revenue A. Disaggregation of Revenue The majority of the Company's revenues are derived from the sale of power, capacity and environmental attributes, leasing of power facilities and from asset optimization activities, which the Company disaggregates into the following groups for the purpose of determining how economic factors affect the recognition of revenue. Year ended Dec. 31, 2022 Hydro Wind and Gas Energy Transition Energy Corporate Total Revenues from contracts with customers Power and other 33 220 462 10 — — 725 Environmental attributes (1) 1 50 — — — — 51 Revenue from contracts with customers 34 270 462 10 — — 776 Revenue from leases (2) — — 32 — — — 32 Revenue from derivatives and other trading activities (3) — (87) (821) 243 160 (2) (507) Revenue from merchant sales 564 86 1,529 461 — — 2,640 Other 8 20 7 — — — 35 Total revenue 606 289 1,209 714 160 (2) 2,976 Revenues from contracts with customers Timing of revenue recognition At a point in time 1 50 — 12 — — 63 Over time 33 220 462 (2) — — 713 Total revenue from contracts with customers 34 270 462 10 — — 776 (1) The environmental attributes represent environmental attribute sales not bundled with power and other sales. (2) Total lease income from long-term contracts that meet the criteria of operating leases. (3) Represents realized and unrealized gains or losses from hedging and derivative positions. Year ended Dec. 31, 2021 Hydro Wind and Gas Energy Transition Energy Corporate Total Revenues from contracts with customers Power and other 28 207 395 24 — — 654 Environmental attributes (1) — 28 — — — — 28 Revenue from contracts with customers 28 235 395 24 — — 682 Revenue from leases (2) — — 19 — — — 19 Revenue from derivatives and other trading activities (3) — (14) (118) 138 211 4 221 Revenue from merchant sales 345 68 808 546 — — 1,767 Other 10 16 5 1 — — 32 Total revenue 383 305 1,109 709 211 4 2,721 Revenues from contracts with customers Timing of revenue recognition At a point in time — 28 2 23 — — 53 Over time 28 207 393 1 — — 629 Total revenue from contracts with customers 28 235 395 24 — — 682 (1) The environmental attributes represent environmental attribute sales not bundled with power and other sales. (2) Total lease income from long-term contracts that meet the criteria of operating leases. (3) Represents realized and unrealized gains or losses from hedging and derivative positions. Wind and Solar has been revised to present revenue classifications consistent with current period. Year ended Dec. 31, 2020 Hydro Wind and Gas Energy Transition Energy Corporate Total Revenues from contracts with customers Power and other 141 238 465 156 — — 1,000 Environmental attributes (1) — 23 — — — — 23 Revenue from contracts with customers 141 261 465 156 — — 1,023 Revenue from leases (2) — — 123 — — — 123 Revenue from derivatives and other trading activities (3) — 8 (8) 283 122 12 417 Revenue from merchant sales 3 49 200 264 — — 516 Other (4) 8 11 7 1 — (5) 22 Total revenue 152 329 787 704 122 7 2,101 Revenues from contracts with customers Timing of revenue recognition At a point in time — 25 7 26 — — 58 Over time 141 236 458 130 — — 965 Total revenue from contracts with customers 141 261 465 156 — — 1,023 (1) The environmental attributes represent environmental attribute sales not bundled with power and other sales. (2) Total lease income from certain PPAs and long-term contracts that meet the criteria of operating leases. (3) Represents realized and unrealized gains or losses from hedging and derivative positions. Wind and Solar has been revised to present revenue classifications consistent with current period. (4) Includes government incentives and other miscellaneous. B. Performance Obligations The performance obligations in the Company's contracts with its customers include the provision of electricity and steam capacity; the delivery of electricity, thermal energy, environmental attributes; the provision of operation and maintenance services and water management services; and the supply of byproducts from coal generation. The aggregate amount of transaction prices allocated to remaining performance obligations (contract revenues that have not yet been recognized) as at Dec. 31, 2022, is approximately $2,790 million, with approximately $465 million expected to be recognized during the period 2023-2025; $490 million for the period of 2026-2028; $750 million for the period of 2029-2033; and $1,085 million for 2034 and thereafter. These amounts exclude revenues related to contracts that qualify for the invoice practical expedient and future revenues that are related to constrained variable consideration. In many of the Company’s contracts, elements of the transaction price are considered constrained, such as for variable revenues dependent upon future production volumes that are driven by customer or market demand or market prices that are subject to factors outside the Company’s influence. As a result, the amounts of future revenues disclosed above represent only a portion of future revenues that are expected to be realized by the Company from its contractual portfolio.

Expenses by Nature

Expenses by Nature	12 Months Ended
	Dec. 31, 2022
Analysis of income and expense [abstract]
Expenses by Nature	Expenses by Nature Fuel, Purchased Power and Operations, Maintenance and Administration ("OM&A") Fuel and purchased power and OM&A expenses classified by nature are as follows: Year ended Dec. 31 2022 2021 2020 Fuel and OM&A Fuel and OM&A Fuel and OM&A Gas fuel costs 578 — 306 — 159 — Coal fuel costs (1) 141 — 164 — 269 — Royalty, land lease, other direct costs 25 — 19 — 20 — Purchased power 514 — 339 — 163 — Mine depreciation (2) — — 190 — 144 — Salaries and benefits 5 263 36 234 50 235 Other operating expenses (3) — 258 — 277 — 237 Total 1,263 521 1,054 511 805 472 (1) Included in coal fuel costs for 2021 and 2020 was $17 million and $15 million, respectively, related to the impairment of coal inventory. (2) Included in mine depreciation for 2021 and 2020 was $48 million and $22 million, respectively, related to mine depreciation that was initially recorded in the standard cost of coal inventory and then subsequently written down during 2021.

Asset Impairment Charges

Asset Impairment Charges	12 Months Ended
	Dec. 31, 2022
Disclosure of impairment of assets [Abstract]
Asset Impairment Charges	Asset Impairment Charges As part of the Company’s monitoring controls, long-range forecasts are prepared for each CGU. The long-range forecast estimates are used to assess the significance of potential indicators of impairment and provide criteria to evaluate adverse changes in operations. The Company also considers the relationship between its market capitalization and its book value, among other factors, when reviewing for indicators of impairment. When indicators of impairment are present, the Company estimates a recoverable amount (the higher of value in use or fair value less costs of disposal) for the affected CGUs using discounted cash flow projections. The valuations are subject to measurement uncertainty from assumptions and inputs to the discount rates, power price forecasts, useful lives of the assets (extending to the last planned asset retirement in 2072) and long-range forecasts, which includes changes to production, fuel costs, operating costs and capital expenditures. The Company recognized the following asset impairment charges (reversals): For year ended Dec. 31 2022 2021 2020 Segments: Hydro 21 5 2 Wind and Solar 43 12 — Gas — 5 — Energy Transition — 540 82 Corporate (2) 27 — Changes in decommissioning and restoration provisions on retired assets (1) (53) 32 — Intangible asset impairment charges - coal rights (2) — 17 — Project development costs (3) — 10 — Asset impairment charges 9 648 84 (1) Changes relate to changes in discount rates and cash flow revisions on retired assets in 2022 and cash flow revisions on retired assets in 2021. Refer to Note 24 for further details. (2) Impaired to nil in 2021, as no future coal will be extracted from this area of the mine. (3) During 2021, the Company recorded an impairment charge of $9 million in the Hydro segment for the balance of project development costs at one of our hydro facilities as there is uncertainty on timing of when the project will proceed and $1 million related to projects that are no longer proceeding. A. Hydro During 2022, the Company recorded net impairment charges of $21 million on four hydro facilities as a result of changes in key assumptions, that included significant increases in discount rates, changes in pricing and changes in estimated future cash flows. The recoverable amounts of $89 million in total for these four assets were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement. The carrying value of property, plant & equipment, right-of-use assets and intangible assets for these Hydro facilities was $88 million as at Dec. 31, 2022. B. Wind and Solar During 2022, the Company recorded net impairment charges of $43 million on five wind facilities and one solar facility as a result of changes in key assumptions, that included significant increases in discount rates, changes in pricing and changes in estimated future cash flows. The recoverable amounts of $754 million for these six assets were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement. The carrying value of property, plant & equipment, right-of-use assets and intangible assets for these Wind and Solar facilities was $748 million as at Dec. 31, 2022. During 2021, the Company recorded impairment charges of $10 million for a wind asset as a result of an increase in estimated decommissioning costs after the review of an engineering study commissioned for the wind sites. The resulting fair value measurement less costs of disposal is categorized as a Level III fair value measurement and the Company adjusted the expected value down to $65 million using discount rates of 5.0 per cent. Additionally, during 2021, the Company recognized impairment charges of $2 million related to the Kent Hills Wind LP tower failure. The Company's subsidiary, Kent Hills Wind LP, experienced a single tower failure at its 167 MW Kent Hills wind facility in Kent Hills, New Brunswick. The failure involved a collapsed tower located within the Kent Hills 2 site. The calculation of fair value less costs of disposal for all of the above facilities is most sensitive to the following assumptions: Location of assets Current year contract and merchant discount rates (1) Prior year contract and merchant discount rates (1) Wind and Solar Canada 6.4 and 7.1 per cent 5.0 and 5.0 per cent US 6.5 and 7.7 per cent 5.1 and 5.0 per cent Hydro Canada 5.9 and 6.4 per cent 3.6 and 4.9 per cent (1) Discount rates were related to the valuations performed for the Wind and Solar and Hydro segments in 2022. The prior year discount rates were related to the previous detailed valuation performed for the Wind and Solar segment in 2021 and for the Hydro segment in 2019. C. Energy Transition During 2021, the Company recognized asset impairment charges in the Energy Transition segment as a result of the decision to suspend the Sundance Unit 5 repowering project ($191 million) and planned retirements of Keephills Unit 1, effective Dec. 31, 2021 ($94 million), and Sundance Unit 4, effective April 1, 2022 ($56 million). Keephills Unit 1 and Sundance Unit 4 impairment assessments were based on the estimated salvage values of these units, which were in excess of the expected economic benefits from these units. For the Sundance Unit 5 repowering project, the recoverable amount was determined based on estimated fair value less costs of disposal of selling the assets under construction and estimated salvage value for the balance of the costs. The fair value measurement for assets under construction is categorized as a Level III fair value measurement. The total remaining estimated recoverable amount and salvage values for Sundance Unit 5 repowering project was $33 million. Discounting did not have a material impact to these asset impairmen ts. The asset retirement and project suspension decisions were based on the Company's assessment of future market conditions, the age and condition of in-service units, as well as TransAlta's strategic focus toward renewable energy solutions. During 2021, with the expected closure of the Highvale mine at the end of 2021, it was determined that the estimated salvage value exceeded the economic benefit to the Alberta Merchant CGU. The asset has been removed from the Alberta Merchant CGU for impairm ent purposes and was assessed for impairment as an individual asset, which resulted in the recognized impairment charge of $195 million in the E nergy Transition segment , with the asset being written down to salvage value. During 2020, the Company recognized impairment charges on Sundance Unit 3 in the amount of $70 million due to the Company's decision to retire the unit. As there were no estimated future cash flows from power generation expected to be derived from the unit, the unit was removed from the Alberta Merchant CGU and immediately written down to the salvage value of the scrap materials. In addition, the Company recognized an impairment of $9 million (US$7 million) due to a decrease in the fair value of land for the Centralia mine determined through a third-party appraiser. D. Corporate Energy Transfer Canada, formerly SemCAMS Midstream ULC, purported to terminate the agreements related to the development and construction of the Kaybob Cogeneration Project. As a result, during the first quarter of 2021, the Company recorded impairment charges of $27 million in the Corporate segment as this facility was not yet operational. The recoverable amount was based on estimated fair value less costs of disposal of reselling the equipment purchased to date. During the fourth quarter of 2022, the dispute has been settled. The Company reversed $2 million of the impairment loss previously recognized.

Net Other Operating (Income) Lo

Net Other Operating (Income) Loss	12 Months Ended
	Dec. 31, 2022
Analysis of income and expense [abstract]
Net Other Operating (Income) Loss	Net Other Operating (Income) Loss Net other operating (income) loss includes the following: Year ended Dec. 31 2022 2021 2020 Alberta Off-Coal Agreement (40) (40) (40) Liquidated damages recoverable (12) — — Insurance recoveries (7) — — Supplier and other contract settlements 5 34 — Onerous contract provisions — 14 29 Retail power contract amortization (Note 27) (4) — — Net other operating (income) loss (58) 8 (11) A. Alberta Off-Coal Agreement ("OCA") The Company receives payments from the Government of Alberta for the cessation of coal-fired emissions on or before Dec. 31, 2030. Under the terms of the agreement, the Company receives annual cash payments on or before July 31 of approximately $40 million ($37 million, net of the non-controlling interest related to Sheerness), which commenced Jan. 1, 2017, and will terminate at the end of 2030. The Company recognizes the off-coal payments evenly throughout the year. Receipt of the payments is subject to certain terms and conditions. The OCA’s main condition is the cessation of all coal-fired emissions on or before Dec. 31, 2030, which has been achieved effective Dec. 31, 2021. The affected plants are not, however, precluded from generating electricity at any time by any method, other than generation resulting in coal-fired emissions after Dec. 31, 2030. B. Liquidated Damages Recoverable During 2022, the Company recorded $12 million, related to requirements to be met by the contractor on turbine availability at the Windrise wind facility. C. Insurance Recoveries During 2022, the Company received insurance proceeds of $7 million related to the replacement costs for the single tower failure at the Kent Hills wind facilities. D. Supplier and Other Contract Settlements During 2022, $5 million was expensed related to contract settlements in the year. During 2021, $34 million was expensed related to decisions to no longer proceed with the Sundance Unit 5 repowering project and to retire Keephills Unit 1, including a deferred asset of $10 million (US$8 million) for which the Company is unlikely to incur sufficient capital or operating expenditures to utilize the remaining credit. E. Onerous Contract Provisions During 2021, an onerous contract provision for future royalty payments of $14 million was recognized with the shutdown of the Highvale mine.

Investments

Investments	12 Months Ended
	Dec. 31, 2022
Interests In Other Entities [Abstract]
Investments	Investments The change in investments is as follows: Skookumchuck EMG EIP Ekona Total Classification Equity-accounted Equity-accounted FVTPL FVTOCI Balance, Dec. 31, 2020 85 15 — — 100 Equity income (loss) 12 (3) — — 9 Distributions received (4) — — — (4) Balance, Dec. 31, 2021 93 12 — — 105 Investment — — 10 2 12 Equity income (loss) 10 (1) — — 9 Distributions received (5) — — — (5) Changes in foreign exchange rates 7 1 1 — 9 Net change in fair value recognized in OCI — — — (1) (1) Balance, Dec. 31, 2022 105 12 11 1 129 Equity-accounted Investments The Company’s investments in joint ventures and associates that are accounted for using the equity method consist of its investments in Skookumchuck and EMG. Skookumchuck Wind Project TransAlta holds a 49 per cent membership interest in SP Skookumchuck Investment, LLC. Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state. The project has a 20-year PPA with Puget Sound Energy. EMG International, LLC TransAlta holds a 30 per cent membership interest in EMG. During 2022, the contingent purchase price consideration of US$3.5 million was paid, which was calculated based on actual earnings metrics achieved in 2021 and did not differ from the estimated amount included in the initial purchase price. Summarized financial information on the results of operations relating to the Company’s pro-rata interests in Skookumchuck and EMG, is as follows: Year ended Dec. 31 2022 2021 2020 Results of operations Revenues and other operating income 24 19 3 Expenses (15) (10) (2) Proportionate share of net earnings 9 9 1 Other Investments Energy Impact Partners On May 6, 2022, the Company entered into a commitment to invest US$25 million over the next four years in Energy Impact Partners ("EIP") Deep Decarbonization Frontier Fund 1 (the “Frontier Fund”). The investment in the Frontier Fund provides the Company with a portfolio approach to investing in emerging technologies and the opportunity to identify, pilot, commercialize and bring to market emerging technologies that will facilitate the transition to net-zero emissions. During 2022, the Company invested $10 million (US$8 million). The investment is accounted for at FVTPL. Ekona Power Inc. On Feb. 1, 2022, the Company made an equity investment of $2 million in Ekona's Class B Preferred Shares. The investment will help support the commercialization of Ekona’s novel methane pyrolysis technology platform, which produces cleaner and lower-cost turquoise hydrogen. The Company has irrevocably elected to measure its investment in Ekona at FVTOCI. Joint arrangements at Dec. 31, 2022, included the following: Joint operations Segment Ownership (per cent) Description Sheerness Gas 50 Dual-fuel facility in Alberta, of which TA Cogen has a 50 per cent interest, operated by Heartland Generation Ltd., an affiliate of Energy Capital Partners Goldfields Power Gas 50 Gas-fired facility in Australia operated by TransAlta Fort Saskatchewan Gas 60 Cogeneration facility in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta Fortescue River Gas Pipeline Gas 43 Natural gas pipeline in Western Australia, operated by DBP Development Group McBride Lake Wind and Solar 50 Wind generation facility in Alberta operated by TransAlta Soderglen Wind and Solar 50 Wind generation facility in Alberta operated by TransAlta Pingston Hydro 50 Hydro facility in British Columbia operated by TransAlta Joint venture Segment Ownership (per cent) Description Skookumchuck Wind and Solar 49 Wind generation facility in Washington operated by Southern Power

Net Interest Expense

Net Interest Expense	12 Months Ended
	Dec. 31, 2022
Analysis of income and expense [abstract]
Net interest expense	Net Interest Expense The components of net interest expense are as follows: Year ended Dec. 31 2022 2021 2020 Interest on debt 164 163 158 Interest on exchangeable debentures (Note 26) 29 29 29 Interest on exchangeable preferred shares (Note 26) 28 28 5 Interest income (24) (11) (10) Capitalized interest (Note 19) (16) (14) (8) Interest on lease liabilities 7 7 8 Credit facility fees, bank charges and other interest 27 20 25 Tax shield on tax equity financing (Note 25) (1) (2) (9) 1 Accretion of provisions (Note 24) 49 32 30 Net interest expense 262 245 238 (1) The credit balance in 2021 primarily relates to the tax benefit associated with investment tax credits claimed in 2021 on the North Carolina Solar facility that was assigned to the tax equity investor. The tax equity investments are treated as debt under IFRS and the monetization of the tax attributes is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Taxes [Abstract]
Income Taxes	Income Taxes A. Consolidated Statements of Earnings I. Rate Reconciliation Year ended Dec. 31 2022 2021 2020 Earnings (loss) before income taxes 353 (380) (303) Net (earnings) loss attributable to non-controlling interests not subject to tax (94) (33) 2 Adjusted earnings (loss) before income taxes 259 (413) (301) Statutory Canadian federal and provincial income tax rate (%) 23.4 % 23.6 % 24.5 % Expected income tax expense (recovery) 61 (98) (74) Increase (decrease) in income taxes resulting from: Differences in effective foreign tax rates (1) 4 3 Non-deductible expense (1) 130 — — Taxable capital gain 18 — — Deferred income tax expense (recovery) related to temporary difference on investment in subsidiaries (2) — 9 Write-down (reversal of write-down) of unrecognized deferred income tax (24) 134 8 Statutory and other rate differences (3) 4 (7) Adjustments in respect of deferred income tax of previous years (2) 6 (4) (3) Other (2) 7 5 14 Income tax expense (recovery) 192 45 (50) Effective tax rate (%) 74 % (11 %) 17 % (1) This amount is related to current and prior period tax adjustments in the US to mitigate cash tax relating to the Base Erosion and Anti-Abuse Tax ("BEAT"). (2) During 2022, the 2021 and 2020 amounts were reclassified from Other to Adjustments in respect of deferred income tax of previous years to better represent the nature of items impacting income tax expense (recovery). These reclassifications did not impact prior years' total income tax expense (recovery) or net earnings (loss). II. Components of Income Tax Expense The components of income tax expense are as follows: Year ended Dec. 31 2022 2021 2020 Current income tax expense 65 56 35 Deferred income tax expense (recovery) related to the origination and reversal of temporary differences 153 (145) (95) Deferred income tax expense (recovery) related to temporary difference on investment in subsidiary (2) — 9 Deferred income tax recovery resulting from changes in tax rates or laws — — (7) Deferred income tax expense (recovery) arising from the unrecognized deferred income tax assets (1) (24) 134 8 Income tax expense (recovery) 192 45 (50) Year ended Dec. 31 2022 2021 2020 Current income tax expense 65 56 35 Deferred income tax expense (recovery) 127 (11) (85) Income tax expense (recovery) 192 45 (50) (1) During the year ended Dec. 31, 2022, the Company recognized deferred tax assets of $24 million (2021 – $134 million write-down, 2020 – $8 million write-down). The deferred income tax assets mainly relate to the tax benefits associated with tax losses related to the Company's directly owned US operations and other deductible differences. The Company has not recognized $361 million of deferred tax assets on the basis that it is not probable that sufficient future taxable income would be available to utilize these tax assets. The Company undertakes an analysis of the recoverability of its tax assets on an annual basis. B. Consolidated Statements of Changes in Equity The aggregate current and deferred income tax related to items charged or credited to equity are as follows: Year ended Dec. 31 2022 2021 2020 Income tax expense (recovery) related to: Net impact related to cash flow hedges (112) (57) (23) Net impact related to hedges of foreign operations (3) — — Net impact to net actuarial gains (losses) 12 11 (3) Income tax recovery reported in equity (103) (46) (26) C. Consolidated Statements of Financial Position Significant components of the Company’s deferred income tax assets (liabilities) are as follows: As at Dec. 31 2022 2021 Non-capital losses (1) 244 530 Future decommissioning and restoration costs 119 183 Property, plant and equipment (553) (651) Risk management assets and liabilities, net 193 (53) Employee future benefits and compensation plans 48 53 Interest deductible in future periods — 17 Foreign exchange differences on US-denominated debt 13 16 Other deductible temporary differences (5) (5) Net deferred income tax asset, before write-down of deferred income tax assets 59 90 Unrecognized deferred income tax assets (361) (380) Net deferred income tax liability, after write-down of deferred income tax assets (302) (290) (1) Non-capital losses expire between 2033 and 2042. Net operating losses from US operations have no expiration. The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows: As at Dec. 31 2022 2021 Deferred income tax assets (1) 50 64 Deferred income tax liabilities (352) (354) Net deferred income tax liability (302) (290) (1) The deferred income tax assets presented on the Consolidated Statements of Financial Position are recoverable based on estimated future earnings and tax planning strategies. The assumptions used in the estimate of future earnings are based on the Company’s long-range forecasts. D. Contingencies As of Dec. 31, 2022, the Company had recognized a net liability of nil (2021 – nil) related to uncertain tax positions. In 2022, the Canada Revenue Agency completed its examination of the Company's tax filings for the 2015 taxation year, including its review of an internal reorganization completed in 2015. Upon conclusion of the 2015 audit, no reassessment was issued.

Non-Controlling Interests

Non-Controlling Interests	12 Months Ended
	Dec. 31, 2022
Interests In Other Entities [Abstract]
Non-Controlling Interests	Non-Controlling Interests The Company’s subsidiaries and operations that have non-controlling interests are as follows: Subsidiary/Operation Non-controlling interest as at Dec. 31, 2022 TransAlta Cogeneration LP 49.99% — Canadian Power Holdings Inc. TransAlta Renewables 39.9% — Public shareholders Kent Hills Wind LP (1) 17% — Natural Forces Technologies Inc. (1) Owned by TransAlta Renewables. TransAlta Cogeneration, LP (“TA Cogen”) operates a portfolio of cogeneration facilities in Canada and owns 50 per cent of a dual-fuel generating facility. TransAlta Renewables ("RNW") owns and operates a portfolio of gas and renewable power generation facilities in Canada and owns economic interests in various other gas and renewable facilities of the Company. Kent Hills Wind LP, a subsidiary of TransAlta Renewables, owns and operates the 167 MW Kent Hills (1, 2 and 3) wind facilities located in New Brunswick. Summarized financial information relating to subsidiaries with significant non-controlling interests is as follows: A. TransAlta Renewables The net earnings, distributions and equity attributable to non-controlling interests include the 17 per cent non-controlling interest in Kent Hills Wind LP. Year ended Dec. 31 2022 2021 2020 Revenues 560 470 436 Net earnings 74 139 97 Total comprehensive income (loss) (67) 66 223 Amounts attributable to the non-controlling interests: Net earnings 20 50 40 Total comprehensive income (loss) (36) 21 90 Distributions paid to non-controlling interests 100 100 80 As at Dec. 31 2022 2021 Current assets 240 430 Long-term assets 2,989 3,319 Current liabilities (306) (593) Long-term liabilities (1,118) (1,033) Total equity (1,805) (2,123) Equity attributable to non-controlling interests (732) (869) Non-controlling interests’ share (per cent) 39.9 39.9 B. TA Cogen Year ended Dec. 31 2022 2021 2020 Revenues 347 265 146 Net earnings (loss) 143 103 (13) Total comprehensive income (loss) 143 103 (13) Amounts attributable to the non-controlling interest: Net earnings (loss) 91 62 (6) Total comprehensive income (loss) 91 62 (6) Distributions paid to Canadian Power Holdings Inc. 87 56 17 As at Dec. 31 2022 2021 Current assets 127 66 Long-term assets 253 312 Current liabilities (62) (52) Long-term liabilities (27) (36) Total equity (291) (290) Equity attributable to Canadian Power Holdings Inc. (147) (142) Non-controlling interest share (per cent) 49.99 49.99

Trade and Other Receivables

Trade and Other Receivables	12 Months Ended
	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Trade and Other Receivables	Trade and Other Receivables and Accounts Payable As at Dec. 31 2022 2021 Trade accounts receivable 1,165 499 Collateral provided (Note 15) 304 55 Current portion of finance lease receivables (Note 17) 52 40 Loan receivable (Note 23) 4 55 Income taxes receivable 64 2 Trade and other receivables 1,589 651 As at Dec. 31 2022 2021 Accounts payable and accrued liabilities 1,069 654 Interest payable 17 17 Collateral held (Note 15) 260 18 Accounts payable and accrued liabilities 1,346 689

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2022
Disclosure of detailed information about financial instruments [abstract]
Financial Instruments	Financial Instruments A. Financial Assets and Liabilities — Classification and Measurement Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost. The following table outlines the carrying amounts and classifications of the financial assets and liabilities: Carrying value as at Dec. 31, 2022 Derivatives Derivatives Amortized cost Other financial assets (FVTPL) Other financial assets (FVTOCI) Total Financial assets Cash and cash equivalents (1) — — 1,134 — — 1,134 Restricted cash — — 70 — — 70 Trade and other receivables — — 1,589 — — 1,589 Long-term portion of finance lease receivables — — 129 — — 129 Long-term portion of loan receivable (2) — — 33 — — 33 Other investments — — — 11 1 12 Risk management assets Current — 709 — — — 709 Long-term — 161 — — — 161 Financial liabilities Bank overdraft — — 16 — — 16 Accounts payable and accrued liabilities — — 1,346 — — 1,346 Dividends payable — — 68 — — 68 Risk management liabilities Current 271 858 — — — 1,129 Long-term 76 257 — — — 333 Credit facilities, long-term debt and lease liabilities (3) — — 3,653 — — 3,653 Exchangeable securities — — 739 — — 739 (1) Includes cash equivalents of nil. (2) Included in other assets. Refer to Note 23. (3) Includes current portion. Carrying value as at Dec. 31, 2021 Derivatives Derivatives Amortized cost Total Financial assets Cash and cash equivalents (1) — — 947 947 Restricted cash — — 70 70 Trade and other receivables — — 651 651 Long-term portion of finance lease receivables — — 185 185 Risk management assets Current 36 272 — 308 Long-term 252 147 — 399 Financial liabilities Accounts payable and accrued liabilities — — 689 689 Dividends payable — — 62 62 Risk management liabilities Current — 261 — 261 Long-term — 145 — 145 Credit facilities, long-term debt and lease liabilities (2) — — 3,267 3,267 Exchangeable securities — — 735 735 (1) Includes cash equivalents of nil. (2) Includes current portion. B. Fair Value of Financial Instruments The fair value of a financial instrument is the price that would be received when selling the asset or paid to transfer the associated liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by observing quoted prices for the instrument in active markets to which the Company has access. In the absence of an active market, the Company determines fair values based on valuation models or by reference to other similar products in active markets. Fair values determined using valuation models require the use of assumptions. In determining those assumptions, the Company looks primarily to external readily observable market inputs. However, if not available, the Company uses inputs that are not based on observable market data. I. Level I, II and III Fair Value Measurements The Level I, II and III classifications in the fair value hierarchy utilized by the Company are defined below. The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the lowest level input that is significant to the derivation of the fair value. The Level III classification is the lowest level classification in the fair value hierarchy. a. Level I Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date. In determining Level I fair values, the Company uses quoted prices for identically traded commodities obtained from active exchanges such as the New York Mercantile Exchange. b. Level II Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability. Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation and location differentials. The Company’s commodity risk management Level II financial instruments include over-the-counter derivatives with values based on observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and interpolation formulas, where the inputs are readily observable. In determining Level II fair values of other risk management assets and liabilities, the Company uses observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, the Company relies on similar interest or currency rate inputs and other third-party information such as credit spreads. c. Level III Fair values are determined using inputs for the assets or liabilities that are not readily observable. The Company may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair values are determined using valuation techniques such as mark-to-forecast and mark-to-model. For mark-to-model valuations, derivative pricing models, regression-based models and scenario analysis simulation models may be employed. The model inputs may be based on historical data such as unit availability, transmission congestion, demand profiles for individual non-standard deals and structured products and/or volatility and correlations between products derived from historical price relationships. For assets and liabilities that are recognized at fair value on a recurring basis, the Company determines whether transfers have occurred between levels in the hierarchy by re-assessing categorization (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period. The Company also has various commodity contracts with terms that extend beyond a liquid trading period. As forward market prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these contracts are classified in Level III. II. Commodity Risk Management Assets and Liabilities Commodity risk management assets and liabilities include risk management assets and liabilities that are used in the energy marketing and generation segments in relation to trading activities and certain contracting activities. To the extent applicable, changes in net risk management assets and liabilities for non-hedge positions are reflected within earnings of these businesses. Commodity risk management assets and liabilities classified by fair value levels as at Dec. 31, 2022, are as follows: Level I – $23 million net asset (2021 – $12 million net asset), Level II – $173 million net asset (2021 – $122 million net asset) and Level III – $782 million net liability (2021 – $159 million net asset). Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2022, are primarily attributable to volatility in market prices across multiple markets on both existing contracts and new contracts as well as contract settlements. The following table summarizes the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification during the years ended Dec. 31, 2022 and 2021, respectively: Year ended Dec. 31, 2022 Year ended Dec. 31, 2021 Hedge Non-hedge Total Hedge Non-hedge Total Opening balance 285 (126) 159 573 9 582 Changes attributable to: Market price changes on existing contracts (611) (298) (909) (181) 4 (177) Market price changes on new contracts — (124) (124) — (134) (134) Contracts settled (38) 118 80 (107) (5) (112) Change in foreign exchange rates 17 (5) 12 — — — Net risk management assets (liabilities) at end of year (347) (435) (782) 285 (126) 159 Additional Level III information: Losses recognized in other comprehensive loss (594) — (594) (181) — (181) Total gains (losses) included in earnings (loss) before income taxes 38 (427) (389) 107 (130) (23) Unrealized gains (losses) included in earnings (loss) before income taxes relating to net assets held at year end — (309) (309) — (135) (135) The Company has a Commodity Exposure Management Policy that governs both the commodity transactions undertaken in its proprietary trading business and those undertaken to manage commodity price exposures in its generation business. This Policy defines and specifies the controls and management responsibilities associated with commodity trading activities, as well as the nature and frequency of required reporting of such activities. The Company's risk management department determines methodologies and procedures regarding commodity risk management Level III fair value measurements. Level III fair values are primarily calculated within the Company’s energy trading risk management system. These calculations are based on underlying contractual data as well as observable and non-observable inputs. Development of non-observable inputs requires the use of judgment. To ensure reasonability, system-generated Level III fair value measurements are reviewed and validated by the risk management and finance departments. Review occurs formally on a quarterly basis or more frequently if daily review and monitoring procedures identify unexpected changes to fair value or changes to key parameters. As at Dec. 31, 2022, the total Level III risk management asset balance was $31 million (2021 – $305 million) and Level III risk management liability balance was $813 million (2021 – $146 million). The fair value of the level III long-term power sale - US contract as well as the long-term wind energy sales contracts have decreased mainly due to higher projected market prices within the next two years. The information on risk management contracts or groups of risk management contracts that are included in Level III measurements and the related unobservable inputs and sensitivities are outlined in the following table. These include the effects on fair value of discounting, liquidity and credit value adjustments; however, the potential offsetting effects of Level II positions are not considered. Sensitivity ranges for the base fair values are determined using reasonably possible alternative assumptions for the key unobservable inputs, which may include forward commodity prices, volatility in commodity prices and correlations, delivery volumes, escalation rates and cost of supply. As at Dec. 31, 2022 Description Sensitivity Valuation technique Unobservable input Reasonably possible change Long-term power sale – US +15 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$5 or price increase of US$55 -163 Coal +14 Numerical derivative valuation Illiquid future power prices (per MWh) Price decrease of US$5 or price increase of US$55 Volatility 80% to 120% -13 Rail rate escalation zero to 10% Full requirements +3 Scenario analysis (1) Volume 96% to 104% -21 Cost of supply Decrease of $0.50 per MWh or increase of $3.30 per MWh Long-term wind +22 Long-term price forecast Illiquid future power prices (per MWh) Price decrease or increase of US$6 -18 Illiquid future REC prices (per unit) Price decrease or increase of US$2 Wind discounts 0% decrease or 5% increase Long-term wind +47 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of C$85 or increase of C$5 -25 Wind discounts 28% decrease or 5% increase Long-term wind +74 Long-term price forecast Illiquid future power prices (per MWh) Price decrease or increase of US$2 -28 Wind discounts 2% decrease or 5% increase Others +18 -19 (1) The valuation technique for Full requirements - Eastern US was updated to scenario analysis to provide a more representative description and did not result in changes to the value. As at Dec. 31, 2021 Description Sensitivity Valuation technique Unobservable input Reasonably possible change Long-term power +22 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$3 or a price increase of US$20 -145 Coal +3 Numerical derivative valuation Illiquid future power prices (per MWh) Price decrease of US$3 or a price increase of US$20 Volatility 80% to 120% -18 Rail rate escalation zero to 4% Full requirements – Eastern US +9 Historical Bootstrap Volume 95% to 105% -9 Cost of supply (+/-) US$1 per MWh Long-term wind +17 Long-term price forecast Illiquid future power prices (per MWh) Price increase or decrease of US$6 -16 Illiquid future REC prices (per unit) Price decrease US$3 or increase of US$2 Long-term wind +21 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of C$24 or increase of C$5 -11 Wind discounts 5% decrease or 5% increase Long-term wind +27 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$2 or increase of US$3 -15 Wind discounts 3% decrease or 3% increase Others +6 -6 i. Long-Term Power Sale – US The Company has a long-term fixed price power sale contract in the US for delivery of power at the following capacity levels: 380 MW through Dec. 31, 2024, and 300 MW through Dec. 31, 2025. The contract is designated as an all-in-one cash flow hedge. For periods beyond 2024, market forward power prices are not readily observable. For these periods, fundamental-based forecasts and market indications have been used to determine proxies for base, high and low power price scenarios. The base price forecast has been developed by using a fundamental-based forecast (the provider is an independent and widely accepted industry expert for scenario and planning views). The contract is denominated in US dollars. The US dollar relative to the Canadian dollar strengthened from Dec. 31, 2021, to Dec. 31, 2022, resulting in a decrease in the base fair value and an increase in the sensitivity values by approximately $21 million and $9 million, respectively. The fair value of this contract at Dec. 31, 2022, decreased mainly due to higher forward power prices compared to previously estimated prices. ii. Coal Transportation – US The Company has a coal rail transport agreement that includes an upside sharing mechanism until Dec. 31, 2025. Option pricing techniques have been utilized to value the obligation associated with this component of the agreement. The key unobservable inputs used in the valuation include non-liquid power prices, option volatility and rail rate escalation. For periods beyond 2024, market forward power prices are not readily observable. For these periods, fundamental-based forecasts and market indications have been used to determine proxies for base, high and low power price scenarios. The base price forecast has been developed by using a fundamental-based forecast (the provider is an independent and widely accepted industry expert for scenario and planning views). Option volatility and rail rate escalation ranges have been determined based on historical data and professional judgment. iii. Full Requirements – Eastern US The Company has a portfolio of full requirement service contracts, whereby the Company agrees to supply specific utility customer needs for a range of products that may include electrical energy, capacity, transmission, ancillary services, renewable energy credits ("RECs") and independent system operator costs. The key unobservable inputs used in the portfolio valuation include delivered volume and supply cost. Hourly shaping of consumption will result in a realized cost that may be at a premium (or discount) relative to the average settled price. iv. Long-Term Wind Energy Sale – Eastern US The Company entered into a long-term contract for differences ("CFD") for the offtake of 100 per cent of the generation from its 90 MW Big Level wind facility. The CFD, together with the sale of electricity generated into the PJM Interconnection at the prevailing real-time energy market price, achieve the fixed contract price per MWh on proxy generation. Under the CFD, if the market price is lower than the fixed contract price the customer pays the company the difference and if the market price is higher than the fixed contract price the Company refunds the difference to the customer. The customer is also entitled to the physical delivery of environmental attributes. The contract matures in December 2034. The contract is accounted for as a derivative. Changes in fair value are presented in revenue. The key unobservable inputs used in the valuation of the contract are expected proxy generation volumes and non-liquid forward prices for power, RECs and wind discounts. v. Long-Term Wind Energy Sale – Canada The Company entered into two VPPAs for the offtake of 100 per cent of the generation from its 130 MW Garden Plain wind project. The VPPAs, together with the sale of electricity generated into the Alberta power market at the pool price, achieve the fixed contract prices per MWh. Under the VPPAs, if the pool price is lower than the fixed contract price the customer pays the Company the difference and if the pool price is higher than the fixed contract price the Company refunds the difference to the customer. The customer is also entitled to the physical delivery of environmental attributes. Both VPPAs commence on commercial operation of the facility and extend for a weighted average of approximately 17 years. The commercial operation date is expected to be in 2023. In addition to the VPPAs, the Company has entered into a bridge contract that initially was for 16 months from Sept. 1, 2021, through Dec. 31, 2022, and will remain in effect at one of the VPPAs price until the commercial operation date is achieved. The customer is also entitled to the physical delivery of environmental attributes. The energy component of these contracts is accounted for as derivatives. Changes in fair value are presented in revenue. The key unobservable inputs used in the valuations of the contracts are the non-liquid forward prices for power and monthly wind discounts. Under a separate agreement, Pembina Pipeline Corporation ("Pembina") has the option to purchase a 37.7 per cent equity interest in the project. The option can be exercised no later than 30 days after Pembina receives notice of the commercial operational date. vi. Long-Term Wind Energy Sale – Central US The Company entered into two long-term VPPAs for the offtake of 100 per cent of the generation from its 300 MW White Rock East and White Rock West wind power projects. The VPPAs, together with the sale of electricity generated into the US Southwest power market at the pool price, achieve the fixed contract prices per MWh. Under the VPPAs, if the pool price is lower than the fixed contract price the customer pays the Company the difference and if the pool price is higher than the fixed contract price the Company refunds the difference to the customer. The customer is also entitled to the physical delivery of environmental attributes. The VPPAs commence on commercial operation of the facilities, which is expected within the second half of 2023. The Company entered into a long-term VPPA for the offtake of 100 per cent of the generation from its 200 MW Horizon Hill wind project. The VPPA, together with the sale of electricity generated into the US Southwest power market at the pool price, achieve the fixed contract prices per MWh. Under the VPPA, if the pool price is lower than the fixed contract price the customer pays the Company the difference and if the pool price is higher than the fixed contract price the Company refunds the difference to the customer. The customer is also entitled to the physical delivery of environmental attributes. The VPPA commences on commercial operation of the facility, which is expected within the second half of 2023. The energy component of these contracts is accounted for as derivatives. Changes in fair value are presented in revenue. The key unobservable inputs used in the valuation of the contracts are the non-liquid forward prices for power and wind discounts. III. Other Risk Management Assets and Liabilities Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in managing exposures on non-energy marketing transactions such as interest rates, the net investment in foreign operations and other foreign currency risks. Hedge accounting is not always applied. Other risk management assets and liabilities with a total net liability fair value of $6 million as at Dec. 31, 2022 (2021 – $8 million net asset) are classified as Level II fair value measurements. The changes in other net risk management assets and liabilities during the year ended Dec. 31, 2022, are primarily attributable to unfavourable market price changes on existing contracts and unfavourable foreign exchange rates on new contracts entered into during 2022. IV. Other Financial Assets and Liabilities The fair value of financial assets and liabilities measured at other than fair value is as follows: Fair value (1) Total carrying value (1) Level I Level II Level III Total Exchangeable securities — Dec. 31, 2022 — 685 — 685 739 Long-term debt — Dec. 31, 2022 — 3,200 — 3,200 3,518 Loan receivable — Dec. 31, 2022 — 37 — 37 37 Exchangeable securities — Dec. 31, 2021 — 770 — 770 735 Long-term debt — Dec. 31, 2021 — 3,272 — 3,272 3,167 Loan receivable — Dec. 31, 2021 — 55 — 55 55 (1) Includes current portion. The fair values of the Company’s debentures, senior notes and exchangeable securities are determined using prices observed in secondary markets. Non-recourse and other long-term debt fair values are determined by calculating an implied price based on a current assessment of the yield to maturity. The carrying amount of other short-term financial assets and liabilities (cash and cash equivalents, restricted cash, trade accounts receivable, collateral provided, bank overdraft, accounts payable and accrued liabilities, collateral held and dividends payable) approximates fair value due to the liquid nature of the asset or liability. The fair values of the finance lease receivables (see Note 17) approximate the carrying amounts as the amounts receivable represent cash flows from repayments of principal and interest. C. Inception Gains and Losses The majority of derivatives traded by the Company are based on adjusted quoted prices on an active exchange or extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives are determined using inputs that are not readily observable. Refer to section B of this Note 14 above for fair value Level III valuation techniques used. In some instances, a difference may arise between the fair value of a financial instrument at initial recognition (the “transaction price”) and the amount calculated through a valuation model. This unrealized gain or loss at inception is recognized in net earnings (loss) only if the fair value of the instrument is evidenced by a quoted market price in an active market, observable current market transactions that are substantially the same, or a valuation technique that uses observable market inputs. Where these criteria are not met, the difference is deferred on the Consolidated Statements of Financial Position in risk management assets or liabilities and is recognized in net earnings (loss) over the term of the related contract. The difference between the transaction price and the fair value determined using a valuation model, yet to be recognized in net earnings (loss) and a reconciliation of changes is as follows: As at Dec. 31 2022 2021 2020 Unamortized net gain (loss) at beginning of year (1) (131) (33) 9 New inception loss (2) (37) (79) (13) Change in foreign exchange rates (10) — — Amortization recorded in net earnings during the year (35) (19) (29) Unamortized net loss at end of year (213) (131) (33) (1) In 2022, the day one valuation of certain PPAs in 2021 was revised for consistency with other fair value calculations. The reconciliation for the 2021 comparative period was restated. This did not impact the prior year financial statements as the inception completely offset the fair value at Dec. 31, 2021. (2) During 2022, the Company entered into a PPA for the Horizon Hill wind project (2021 – PPAs for the White Rock wind project) that resulted in a new inception loss due to the difference between the fixed PPA price and future estimated market prices. There are other key factors, such as project economics and incentives, that influence the long-term power price for renewable projects outside of the power price curve, which is not liquid for the majority of the duration of the PPA. During 2020, the Company entered into a coal rail transportation agreement that includes an upside sharing mechanism. Option pricing techniques have been utilized to value the obligation associated with this component of the deal.

Risk Management Activities

Risk Management Activities	12 Months Ended
	Dec. 31, 2022
Financial Instruments [Abstract]
Risk Management Activities	Risk Management Activities A. Risk Management Strategy The Company is exposed to market risk from changes in commodity prices, foreign exchange rates, interest rates, credit risk and liquidity risk. These risks affect the Company’s earnings and the value of associated financial instruments that the Company holds. In certain cases, the Company seeks to minimize the effects of these risks by using derivatives to hedge its risk exposures. The Company’s risk management strategy, policies and controls are designed to ensure that the risks it assumes comply with the Company’s internal objectives and its risk tolerance. The Company has two primary streams of risk management activities: (i) financial exposure management; and (ii) commodity exposure management. Within these activities, risks identified for management include commodity risk, interest rate risk, liquidity risk, equity price risk and foreign currency risk. The Company seeks to minimize the effects of commodity risk, interest rate risk and foreign currency risk by using derivative financial instruments to hedge risk exposures. Of these derivatives, the Company may apply hedge accounting to those hedging commodity price risk, interest rate risk and foreign currency risk. The use of financial derivatives is governed by the Company’s policies approved by the Board, which provide written principles on commodity risk, interest rate risk, liquidity risk, equity price risk and foreign currency risk, as well as the use of financial derivatives and non-derivative financial instruments. Liquidity risk, credit risk and equity price risk are managed through means other than derivatives or hedge accounting. The Company enters into various derivative transactions as well as other contracting activities that do not qualify for hedge accounting or where a choice was made not to apply hedge accounting. As a result, the related assets and liabilities are classified as derivatives at fair value through profit and loss. The net realized and unrealized gains or losses from changes in the fair value of these derivatives are reported in net earnings in the period the change occurs. The Company designates certain derivatives as hedging instruments to hedge commodity price risk, foreign currency exchange risk in cash flow hedges and hedges of net investments in foreign operations. Hedges of foreign exchange risk on firm commitments are accounted for as cash flow hedges. At the inception of the hedge relationship, the Company documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. At the inception of the hedge and on an ongoing basis, the Company also documents whether the hedging instrument is effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk, which is when the hedging relationships meet all of the following hedge effectiveness requirements: • There is an economic relationship between the hedged item and the hedging instrument; • The effect of credit risk does not dominate the value changes that result from that economic relationship; and • The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Company actually hedges and the quantity of the hedging instrument that the entity actually uses to hedge that quantity of hedged item. If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio, but the risk management objective for that designated hedging relationship remains the same, the Company adjusts the hedge ratio of the hedging relationship so that it continues to meet the qualifying criteria. B. Net Risk Management Assets and Liabilities Aggregate net risk management assets (liabilities) are as follows: As at Dec. 31, 2022 Cash flow Not Total Commodity risk management Current (271) (143) (414) Long-term (76) (96) (172) Net commodity risk management liabilities (347) (239) (586) Other Current — (6) (6) Long-term — — — Net other risk management liabilities — (6) (6) Total net risk management liabilities (347) (245) (592) As at Dec. 31, 2021 Cash flow Not Total Commodity risk management Current 33 12 45 Long-term 252 (4) 248 Net commodity risk management assets 285 8 293 Other Current 3 (1) 2 Long-term — 6 6 Net other risk management assets 3 5 8 Total net risk management assets 288 13 301 Netting Arrangements Information about the Company’s financial assets and liabilities that are subject to enforceable master netting arrangements or similar agreements is as follows: As at Dec. 31, 2022 Gross amounts of recognized financial assets (liabilities) Amounts set off Net amounts presented on the statement of financial position Master netting arrangements (1) Net amount Current risk management assets $ 1,602 $ (883) $ 688 $ (62) $ 626 Long-term risk management assets $ 204 $ (43) $ 157 $ (7) $ 150 Current risk management liabilities $ (1,953) $ 883 $ (1,033) $ 62 $ (971) Long-term risk management liabilities $ (449) $ 43 $ (402) $ 7 $ (395) Trade and other receivables (2) $ 1,330 $ (934) $ 396 $ (176) $ 220 Accounts payable and accrued liabilities (2) $ (1,344) $ 934 $ (411) $ 176 $ (235) As at Dec. 31, 2021 Gross amounts of recognized financial assets (liabilities) Amounts set off Net amounts presented on the statement of financial position Master netting arrangements (1) Net amount Current risk management assets $ 636 $ (307) $ 316 $ (92) $ 224 Long-term risk management assets $ 285 $ (16) $ 260 $ (23) $ 237 Current risk management liabilities $ (529) $ 307 $ (211) $ 92 $ (119) Long-term risk management liabilities $ (89) $ 16 $ (70) $ 23 $ (47) Trade and other receivables (2) $ 699 $ (571) $ 128 $ (35) $ 93 Accounts payable and accrued liabilities (2) $ (689) $ 571 $ (118) $ 35 $ (83) (1) Amounts not set off in the Consolidated Statements of Financial Position. (2) The trade and other receivables and accounts payable and accrued liabilities include amounts related to collateral provided and held. Refer to Note 15(F) below for further details. C. Nature and Extent of Risks Arising from Financial Instruments I. Market Risk a. Commodity Price Risk Management The Company has exposure to movements in certain commodity prices in both its electricity generation and proprietary trading businesses, including the market price of electricity and fuels used to produce electricity. Most of the Company’s electricity generation and related fuel supply contracts are considered to be contracts for delivery or receipt of a non-financial item in accordance with the Company’s expected own use requirements and are not considered to be financial instruments. As such, the discussion related to commodity price risk is limited to the Company’s proprietary trading business, the VPPAs and other long-term contracts that are derivatives and commodity derivatives used in hedging relationships associated with the Company’s electricity generating activities. To mitigate the risk of adverse commodity price changes, the Company uses three tools: • A framework of risk controls; • A predefined hedging plan, including fixed price financial power swaps and long-term physical power sale contracts to hedge commodity price for electricity generation; and • A committee dedicated to overseeing the risk and compliance program in trading and ensuring the existence of appropriate controls, processes, systems and procedures to monitor adherence to the program. The Company has executed commodity price hedges for its Centralia thermal facility, including a long-term physical power sale contract, and may, at times, execute hedges for its portfolio of merchant power exposure in Alberta using fixed price financial swaps or other similar instruments. Both hedging strategies fall under the Company’s risk management strategy used to hedge commodity price risk. Market risk exposures are measured using Value at Risk ("VaR") supplemented by sensitivity analysis. There has been no change to the Company’s exposure to market risks or the manner in which these risks are managed or measured. Position sizes and trade strategies were adjusted to remain within the Company's risk framework. i. Commodity Price Risk Management – Proprietary Trading The Company’s Energy Marketing segment conducts proprietary trading activities and uses a variety of instruments to manage risk, earn trading revenue and gain market information. In compliance with the Commodity Exposure Management Policy, proprietary trading activities are subject to limits and controls, including VaR limits. The Board approves the limit for total VaR from proprietary trading activities. VaR is the most commonly used metric employed to track and manage the market risk associated with trading positions. A VaR measure gives, for a specific confidence level, an estimated maximum pre-tax loss that could be incurred over a specified period of time. VaR is used to determine the potential change in value of the Company’s proprietary trading portfolio, over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations. VaR is estimated using the historical variance/covariance approach. VaR is a measure that has certain inherent limitations. The use of historical information in the estimate assumes that price movements in the past will be indicative of future market risk. As such, it may only be meaningful under normal market conditions. Extreme market events are not addressed by this risk measure. In addition, the use of a three-day measurement period implies that positions can be unwound or hedged within three days, although this may not be possible if the market becomes illiquid. Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes occur. VaR at Dec. 31, 2022, associated with the Company’s proprietary trading activities was $4 million (2021 – $2 million, 2020 – $1 million). ii. Commodity Price Risk – Generation The generation segments utilize various commodity contracts to manage the commodity price risk associated with electricity generation, fuel purchases, emissions and byproducts, as considered appropriate. A Commodity Exposure Management Policy is prepared and approved annually, which outlines the intended hedging strategies associated with the Company’s generation assets and related commodity price risks. Controls also include restrictions on authorized instruments, management reviews on individual portfolios and approval of asset transactions that could add potential volatility to the Company’s reported net earnings. VaR at Dec. 31, 2022, associated with the Company’s commodity derivative instruments used in generation hedging activities was $97 million (2021 – $33 million, 2020 – $12 million). For positions and economic hedges that do not meet hedge accounting requirements or for short-term optimization transactions such as buybacks entered into to offset existing hedge positions, these transactions are marked to the market value with changes in market prices associated with these transactions affecting net earnings in the period in which the price change occurs. VaR at Dec. 31, 2022, associated with these transactions was $54 million (2021 – $51 million, 2020 – $15 million), of which $26 million related to VPPAs (2021 – $14 million, 2020 – $3 million). iii. Commodity Price Risk Management – Hedges At Dec. 31, 2022, the Company had no outstanding commodity derivative instruments designated as hedging instruments, except for the long-term power sale - US contract. For further details on this contract, refer to Note 14(B)(II)(i). iv. Commodity Price Risk Management – Non-Hedges The Comp any’s outstanding commodity derivative instruments not designated as hedging instruments are as follows: As at Dec. 31 2022 2021 Type Notional Notional Notional Notional Electricity (MWh) 55,821 13,934 46,139 14,951 Natural gas (GJ) 23,464 162,384 7,501 173,898 Transmission (MWh) — 1,643 37 1,097 Emissions (MWh) 274 2,297 445 2,030 Emissions (tonnes) 300 300 350 350 Coal (tonnes) — 7,746 — 9,352 b. Interest Rate Risk Management Changes in interest rates can impact the Company’s borrowing costs and cost of capital. Changes in the cost of capital could affect the feasibility of new growth initiatives. Interest rate risk also arises as the fair value of future cash flows from a financial instrument fluctuates because of changes in market interest rates. The Company's credit facility, Term Facility ("Term Facility") and the Poplar Creek non-recourse bond are the only debt instruments subject to floating interest rates, which represent 15 per cent of the Company’s total long-term debt as at Dec. 31, 2022 (2021 – 3 per cent). Interest rate risk is managed with the use of derivatives. The Company's outstanding interest rate derivative instruments are as follows: The Company entered into two interest rate swaps agreements in October 2022 for $100 million each to manage interest rate risk related to a portion of its Term Facility. The Company pays a fixed blended rate of 4.70 per cent and receives one month Canadian Dollar Offered Rate ("CDOR") that resets monthly. The maturity date is Nov. 10, 2023. Interest rate swap agreements with a notional amount of US$150 million referencing the three-month London Interbank Offered Rate were replaced with swap agreements referencing the Secured Overnight Financing Rate ("SOFR"). These swaps were settled in 2022. In addition, the US$150 million bond lock agreement outstanding at Dec. 31, 2021, was settled in 2022. Interbank Offered Rate reform could impact interest rate risk with respect to the Company's credit facilities and the Poplar Creek non-recourse bond held by a TransAlta subsidiary. The credit facilities with $433 million outstanding (2021 – nil) reference the CDOR for Canadian-dollar drawings, but include appropriate fallback language to replace this benchmark rate in the event of a benchmark transition. The Poplar Creek non-recourse bond with a face value as at Dec. 31, 2022 of $95 million (2021 – $104 million) pays interest based upon the three-month CDOR. Cessation of the three-month CDOR is anticipated to occur mid-2024. c. Currency Rate Risk The Company has exposure to various currencies, such as the US dollar and the Australian dollar, as a result of investments and operations in foreign jurisdictions, the net earnings from those operations and the acquisition of equipment and services from foreign suppliers. The Company may enter into the following hedging strategies to mitigate currency rate risk, including: • Foreign exchange forward contracts to mitigate adverse changes in foreign exchange rates on project-related expenditures and distributions received in foreign currencies; • Foreign exchange forward contracts and cross-currency swaps to manage foreign exchange exposure on foreign-denominated debt not designated as a net investment hedge; and • Designating foreign currency debt as a hedge of the net investment in foreign operations to mitigate the risk due to fluctuating exchange rates related to certain foreign subsidiaries. The Company's target is to hedge a minimum of 60 per cent of our forecasted foreign operating cash flows over a four-year period, with a minimum of 90 per cent in the current year, 70 per cent in the next year, 50 per cent in the third year and 30 per cent in the fourth year. The US exposure will be managed with a combination of interest expense on our US-denominated debt and forward foreign exchange contracts and the Australian exposure will be managed with a combination of interest expense on our Australian-dollar denominated debt and forward foreign exchange contracts. i. Net Investment Hedges When designating foreign currency debt as a hedge of the Company’s net investment in foreign subsidiaries, the Company has determined that the hedge is effective if the foreign currency of the net investment is the same as the currency of the hedge and therefore an economic relationship is present. The Company’s hedges of its net investment in foreign operations were comprised of US-dollar-denominated long-term debt with a face value of US$370 million (2021 – US$370 million). ii. Non-Hedges The Company also uses foreign currency contracts to manage its expected foreign operating cash flows and foreign exchange forward contracts to manage foreign exchange exposure on foreign-denominated debt not designated as a net investment hedge. Hedge accounting is not applied to these foreign currency contracts. As at Dec. 31 2022 2021 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign exchange forward contracts – foreign-denominated receipts/expenditures AU183 CAD168 (1) 2023-2026 AU28 CAD26 (5) 2022-2025 US573 CAD761 (12) 2023-2025 US271 CAD357 8 2022-2025 US66 AU102 4 2023 — — — — Foreign exchange forward contracts – foreign-denominated debt CAD159 US120 3 2023 CAD191 US150 1 2022 iii. Impacts of Currency Rate Risk The possible effect on net earnings and OCI, due to changes in foreign exchange rates associated with financial instruments denominated in currencies other than the Company’s functional currency, is outlined below. The sensitivity analysis has been prepared using management’s assessment that an average three cents (2021 – three cents, 2020 – three cents) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter. Year ended Dec. 31 2022 2021 2020 Currency Net earnings decrease (1) OCI gain (1)(2) Net earnings increase (decrease) (1) OCI gain (1)(2) Net earnings decrease (1) OCI gain (1)(2) USD (12) — (13) 1 (8) 1 AUD (2) — 1 — (4) — Total (14) — (12) 1 (12) 1 (1) These calculations assume an increase in the value of these currencies relative to the Canadian dollar. A decrease would have the opposite effect. (2) The foreign exchange impact related to financial instruments designated as hedging instruments in net investment hedges has been excluded. II. Credit Risk Credit risk is the risk that customers or counterparties will cause a financial loss for the Company by failing to discharge their obligations and the risk to the Company associated with changes in creditworthiness of entities with which commercial exposures exist. The Company actively manages its exposure to credit risk by assessing the ability of counterparties to fulfil their obligations under the related contracts prior to entering into such contracts. The Company makes detailed assessments of the credit quality of all counterparties and, where appropriate, obtains corporate guarantees, cash collateral, third-party credit insurance and/or letters of credit to support the ultimate collection of these receivables. For commodity trading and origination, the Company sets strict credit limits for each counterparty and monitors exposures on a daily basis. TransAlta uses standard agreements that allow for the netting of exposures and often include margining provisions. If credit limits are exceeded, TransAlta will request collateral from the counterparty or halt trading activities with the counterparty. The Company uses external credit ratings, as well as internal ratings in circumstances where external ratings are not available, to establish credit limits for customers and counterparties. The following table outlines the Company’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at Dec. 31, 2022: Investment grade (Per cent) Non-investment grade (Per cent) Total (Per cent) Total Trade and other receivables (1)(2) 87 13 100 1,585 Long-term finance lease receivable 100 — 100 129 Risk management assets (1) 92 8 100 870 Loan receivable (2) — 100 100 37 Total 2,621 (1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts. (2) Includes $37 million loan receivable included within other assets with a counterparty that has no external credit rating. The current portion of $4 million was excluded from trade and other receivables as it is included in loan receivable in the table above. Refer to Note 23 for further details. An impairment analysis is performed at each reporting date using a provision matrix to measure expected credit losses. The provision rates are based on segment historical rates of default of trade receivables as well as incorporating forward-looking credit ratings and forecasted default rates. In addition to the calculation of expected credit losses, TransAlta monitors key forward-looking information as potential indicators that historical bad debt percentages, forward-looking S&P credit ratings and forecasted default rates would no longer be representative of future expected credit losses. The calculation reflects the probability-weighted outcome, the time value of money and reasonable and supportable information that is available at the reporting date about past events, current conditions and forecasts of future economic conditions. TransAlta evaluates the concentration of risk with respect to trade receivables as low, as its customers are located in several jurisdictions and industries. The Company did not have significant expected credit losses as at Dec. 31, 2022. The Company’s maximum exposure to credit risk at Dec. 31, 2022, without taking into account collateral held or right of set-off, is represented by the current carrying amounts of receivables and risk management assets as per the Consolidated Statements of Financial Position. Letters of credit and cash are the primary types of collateral held as security related to these amounts. The maximum credit exposure to any one customer for commodity trading operations and hedging, including the fair value of open trading, net of any collateral held, at Dec. 31, 2022, was $64 million (2021 – $37 million). III. Liquidity Risk Liquidity risk relates to the Company’s ability to access capital to be used for capital projects, debt refinancing, proprietary trading activities, commodity hedging and general corporate purposes. As at Dec. 31, 2022, TransAlta maintains an investment grade rating from one credit rating agency and below investment grade ratings from two credit rating agencies. Between 2023 and 2025, the Company has approximately $839 million of debt maturing, comprised of approximately $400 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments. Collateral is posted based on negotiated terms with counterparties, which can include the Company’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs. TransAlta manages liquidity risk by monitoring liquidity on trading positions; preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital; reporting liquidity risk exposure for proprietary trading activities on a regular basis to the Risk Management Committee, senior management and the Audit, Finance and Risk Committee (on behalf of the Board); and maintaining sufficient undrawn committed credit lines to support potential liquidity requirements. The Company does not use derivatives or hedge accounting to manage liquidity risk. A maturity analysis of the Company's financial liabilities as well as financial assets that are expected to generate cash inflows to meet cash outflows on financial liabilities, is as follows: 2023 2024 2025 2026 2027 2028 and thereafter Total Bank overdraft 16 — — — — — 16 Accounts payable and accrued liabilities 1,346 — — — — — 1,346 Long-term debt (1) Credit facilities (1) — 400 — 33 — — 433 Debentures — — — — — 251 251 Senior notes — — — — — 949 949 Non-recourse — Hydro 45 — — — — — 45 Non-recourse — Wind & Solar 63 66 69 67 70 363 698 Non-recourse — Gas 45 46 58 61 65 782 1,057 Tax equity financing 16 15 15 16 19 48 129 Other 1 — — — — — 1 Exchangeable securities (2) — — 750 — — — 750 Commodity risk management (assets) 415 182 (42) 15 8 8 586 Other risk management (assets) liabilities 7 (1) 1 — — (1) 6 Lease liabilities (3) (7) 4 4 3 4 127 135 Interest on long-term debt and lease liabilities (4) 205 192 166 158 150 836 1,707 Interest on exchangeable securities (2)(4) 52 62 — — — — 114 Dividends payable 68 — — — — — 68 Total 2,272 966 1,021 353 316 3,363 8,291 (1) Excludes impact of hedge accounting and derivatives. (2) The exchangeable securities can be exchanged, at the earliest, on Jan. 1, 2025. Refer to Note 26 for further details. (3) Lease liabilities include a lease incentive of $12 million expected to be received in 2023. (4) Not recognized as a financial liability on the Consolidated Statements of Financial Position. IV. Equity Price Risk Total Return Swaps The Company has certain compensation, deferred and restricted share unit programs, the values of which depend on the common share price of the Company. The Company has fixed a portion of the settlement cost of these programs by entering into a total return swap for which hedge accounting has not been applied. The total return swap is cash settled every quarter based upon the difference between the fixed price and the market price of the Company’s common shares at the end of each quarter. D. Hedging Instruments – Uncertainty of Future Cash Flows The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount, timing and uncertainty of future cash flows: Maturity 2023 2024 2025 2026 2027 2028 Cash flow hedges Commodity derivative instruments Electricity Notional amount (thousands of MWh) 3,329 3,338 2,628 — — — Average price ($ per MWh) 78.27 80.22 82.22 — — — E. Effects of Hedge Accounting on the Financial Position and Performance I. Effect of Hedges The impact of the hedging instruments on the statement of financial position is as follows: As at Dec. 31, 2022 Notional amount Carrying amount Line item in the statement of financial position Change in fair value used for measuring ineffectiveness Commodity price risk Cash flow hedges Physical power sales (1) 9,295 (347) Risk management liabilities (594) Foreign currency risk Net investment hedges Foreign-denominated debt US370 CAD502 Credit facilities, long-term debt and lease liabilities — (1) In thousands of MWh. As at Dec. 31, 2021 Notional amount Carrying amount Line item in the statement of financial position Change in fair value used for measuring ineffectiveness Commodity price risk Cash flow hedges Physical power sales (1) 12,624 285 Risk management assets (181) Interest rate risk Cash flow hedges Interest rate swap US300 3 Risk management assets 3 Foreign currency risk Cash flow hedges Foreign-denominated expenditures US8 — Risk management assets — Foreign-denominated expenditures US14 — Risk management assets — Net investment hedges Foreign-denominated debt US370 CAD473 Credit facilities, long-term debt and lease liabilities — (1) In thousands of MWh. The impact of the hedged items on the statement of financial position is as follows: As at Dec. 31 2022 2021 Change in fair value used for measuring ineffectiveness Cash flow hedge reserve (1) Change in fair value used for measuring ineffectiveness Cash flow hedge reserve (1) Commodity price risk Cash flow hedges Power forecast sales – (594) (279) (181) 226 Interest rate risk Cash flow hedges Interest expense on long- — — 3 2 Change in fair value used for measuring ineffectiveness Foreign currency translation reserve (1) Change in fair value used for measuring ineffectiveness Foreign currency translation reserve (1) Foreign currency risk Net investment hedges Net investment in foreign — (39) — (35) (1 Net of tax. Included in AOCI. The hedging gain or loss recognized in OCI before tax is equal to the change in fair value used for measuring effectiveness for the net investment hedge. There is no ineffectiveness recognized in profit or loss. The impact of designated cash flow hedges on OCI and net earnings is: Year ended Dec. 31, 2022 Effective portion Ineffective portion Derivatives in cash flow Pre-tax Location of (gain)loss reclassified Pre-tax Location of (gain) loss Pre-tax Commodity contracts (747) Revenue 124 Revenue — Forward starting interest rate 53 Interest expense 2 Interest expense — OCI impact (694) OCI impact 126 Net earnings impact — Over the next 12 months, the Company estimates that approximately $208 million of after-tax losses will be reclassified from AOCI to net earnings. These estimates assume constant natural gas and power prices, interest rates and exchange rates over time; however, the actual amounts that will be reclassified may vary based on changes in these factors. Year ended Dec. 31, 2021 Effective portion Ineffective portion Derivatives in cash flow Pre-tax Location of (gain) loss reclassified Pre-tax Location of (gain) loss Pre-tax Commodity contracts (268) Revenue (13) Revenue — Foreign exchange forwards — Property, plant 1 Foreign exchange — Forward starting interest rate 13 Interest expense 4 Interest expense — OCI impact (255) OCI impact (8) Net earnings impact — Year ended Dec. 31, 2020 Effective portion Ineffective portion Derivatives in cash flow Pre-tax Location of (gain) Pre-tax Location of (gain) loss reclassified Pre-tax Commodity contracts 41 Revenue (137) Revenue — Foreign exchange forwards (1) Property, plant and equipment — Foreign exchange — Forward starting interest rate (12) Interest expense (4) Interest expense — OCI impact 28 OCI impact (141) Net earnings impact — II. Effect of Non-Hedges For the year ended Dec. 31, 2022, the Company recognized a net unrealized loss of $384 million (2021 – gain of $97 million, 2020 – gain of $43 million) related to commodity derivatives. For the year ended Dec. 31, 2022, a gain of $20 million (2021 – gain of $6 million, 2020 – gain of $11 million) related to foreign exchange and other derivatives was recognized, which consists of net unrealized losses of $11 million (2021 – gain of $4 million, 2020 – loss of $2 million) and net realized gains of $31 million (2021 – gains of $2 million, 2020 — gains of $13 million), respectively. F. Collateral I. Financial Assets Provided as Collateral At Dec. 31, 2022, the Company provided $304 million (2021 — $55 million) in cash and cash equivalents as collateral to regulated clearing agents and certain utility customers as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents. The utility customers are obligated to pay interest on the outstanding balances. Collateral provided is included within trade and other receivables in the Consolidated Statements of Financial Position. II. Financial Assets Held as Collateral At Dec. 31, 2022, the Company held $260 million (2021 – $18 million) in cash collateral associated with counterparty obligations. Under the terms of the contracts, the Company may be obligated to pay interest on the outstanding balances and to return the principal when the counterparties have met their contractual obligations or when the amount of the obligation declines as a result of changes in market value. Interest payable to the counterparties on the collateral received is calculated in accordance with each contract. Collateral held is related to physical and financial derivative transactions in a net asset position and is included in accounts payable and accrued liabilities in the Consolidated Statements of Financial Position. III. Contingent Features in Derivative Instruments Collateral is posted in the normal course of business based on the Company’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs. At Dec. 31, 2022, the Company had posted collateral of $820 million (2021 – $356 million) in the form of letters of credit on physical and financial derivative transactions in a net liability position. Certain derivative agreements contain credit-risk-contingent features, which if triggered could result in the Company having to post an additional $656 million (2021 – $120 million) of collateral to its counterparties.

Inventory

Inventory	12 Months Ended
	Dec. 31, 2022
Disclosure of inventories [Abstract]
Inventory	Inventory The components of inventory are as follows: As at Dec. 31 2022 2021 Parts, materials and supplies 83 82 Coal 43 27 Emission credits 27 55 Natural gas 4 3 Total 157 167 No inventory is pledged as security for liabilities. During 2022, coal inventory increased primarily due to higher coal inventory volume at Centralia Unit 2 along with higher coal pricing. As at Dec. 31, 2022, the Company holds 963,068 emission credits in inventory purchased externally with a recorded book value of $27 million (Dec. 31, 2021 – 2,033,752 emission credits with a recorded book value of $55 million). The Company also has approximately 1,869,450 (Dec. 31, 2021 – 1,922,973) of internally generated eligible emission credits from the Company's Wind and Solar and Hydro segments with no recorded book value. These emission credits can be used to offset future emission obligations from our gas facilities located in Canada where the compliance price of carbon is expected to increase, resulting in a reduced cash cost for carbon compliance. In addition, the Company holds approximately 1,750,000 (Dec. 31, 2021 – 1,750,000) eligible emission performance credits ("EPCs") with no recorded book value generated from assets formerly subject to the Hydro Power Purchase Arrangement ("Hydro PPA") during the year. The Balancing Pool is asserting ownership of these EPCs, which the Company has disputed through an arbitration to be heard in May 2023. Refer to Note 37 for further details. During 2022, the Company utilized 1,169,333 emission credits with a carrying value of $35 million to settle the 2021 carbon compliance obligation of $47 million. The difference of $12 million has been recognized as a reduction in the Company's carbon compliance costs in the year.

Finance Lease Receivables

Finance Lease Receivables	12 Months Ended
	Dec. 31, 2022
Disclosure of maturity analysis of finance lease payments receivable [abstract]
Finance Lease Receivables	Finance Lease Receivables Amounts receivable under the Company’s finance leases associated with the Poplar Creek cogeneration facility and the Southern Cross Energy facilities are as follows: As at Dec. 31 2022 2021 Minimum Present value of Minimum Present value of Within one year 62 55 58 54 Second to fifth years inclusive 81 75 127 105 More than five years 60 51 80 66 203 181 265 225 Less: unearned finance lease income 22 — 40 — Total finance lease receivables 181 181 225 225 Included in the Consolidated Statements of Financial Position as: Current portion of finance lease receivables (Note 13) 52 40 Long-term portion of finance lease receivables 129 185 Total finance lease receivables 181 225

Assets Held for Sale

Assets Held for Sale	12 Months Ended
	Dec. 31, 2022
Assets Held for Sale [Abstract]
Assets Held for Sale	Assets Held for Sale The change in assets held for sale is as follows: 2022 2021 Balance, Jan 1 25 105 Transfers from property, plant and equipment 28 25 Disposals (31) (105) Balance, Dec. 31 22 25 Sale of Pioneer Pipeline On Oct. 1, 2020, the Company announced that it had entered into a definitive Purchase and Sale Agreement providing for the sale of its 50 per cent interest in the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. ("ATCO"). At Jan. 1, 2021, the assets held for sale included our interest in the Pioneer Pipeline and certain mining assets. On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO for the aggregate sale price of $255 million. The net cash proceeds to the Company from the sale of its 50 per cent interest, were approximately $128 million and the Company recognized a gain on sale of $31 million on the Consolidated Statements of Earnings (Loss). In addition, as part of the transaction, the natural gas transportation agreement with the Pioneer Pipeline Limited Partnership was terminated which resulted in a gain of $2 million. Other Held for Sale Assets In December 2021, the Company transferred certain gas generation assets of $25 million to assets held for sale. On Nov. 7, 2022, the Company closed the sale of the gas generation assets, received net cash proceeds of $45 million and recognized a gain on sale of $20 million on the Consolidated Statements of Earnings (Loss). In 2022, the Company transferred two Hydro assets to assets held for sale upon entering into a purchase and sale agreement. On Dec. 2, 2022, the Company closed the sale of these assets for the aggregate sale price and net cash proceeds of $6 million and recognized a gain on sale of $2 million on the Consolidated Statements of Earnings (Loss). During 2022, the Company transferred $22 million to assets held for sale for cogeneration equipment.

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2022
Disclosure of detailed information about property, plant and equipment [abstract]
Property, Plant, and Equipment	Property, Plant and Equipment A reconciliation of the changes in the carrying amount of PP&E is as follows: Assets under Land Hydro (1) Wind and Solar (1) Gas generation Energy Transition Capital spares and other (2) Total Cost As at Dec. 31, 2020 495 96 846 2,746 3,935 4,901 379 13,398 Additions (3) 477 — — — — — 2 479 Additions from development projects 1 — — — — — — 1 Acquisitions (Note 4) — — — 146 — — — 146 Disposals (2) (1) — — (2) (74) — (79) Impairment charges (Note 7) (4) (91) — (3) (12) (2) (468) (13) (589) Revisions/additions to decommissioning and restoration costs (Note 24) — — 1 128 6 — — 135 Retirement of assets — — (4) (11) (57) (49) — (121) Change in foreign exchange rates — — — 3 (25) 2 (7) (27) Transfers (to) from assets held for sale (Note 18) (25) — — — — 31 — 6 Transfers in (out) of PP&E (5) 5 — — (4) (5) 46 — 42 Transfer of assets upon commissioning (676) 1 27 280 237 124 5 (2) As at Dec. 31, 2021 184 96 867 3,276 4,087 4,513 366 13,389 Additions (3) 891 — — — — — 6 897 Additions from development projects 17 — — — — — 12 29 Disposals — (3) — — (1) (216) — (220) Impairment (charges) reversals (Note 7) (4) 2 — (21) (43) — — — (62) Revisions/additions to decommissioning and restoration costs (Note 24) — — (15) (59) (12) 10 2 (74) Retirement of assets — — (9) (9) (12) (7) (2) (39) Change in foreign exchange rates 13 — — 45 (4) 97 2 153 Transfers to assets held for sale (Note 18) (22) — (9) — — — — (31) Transfers in (out) of PPE (5) 16 — — (22) 437 (442) (13) (24) Transfer of assets upon commissioning (138) — 27 45 35 19 6 (6) As at Dec. 31, 2022 963 93 840 3,233 4,530 3,974 379 14,012 Accumulated depreciation As at Dec. 31, 2020 — — 447 969 2,058 3,933 169 7,576 Depreciation — — 24 130 184 264 12 614 Retirement of assets — — (3) (6) (55) (48) — (112) Disposals — — — — (1) (72) — (73) Change in foreign exchange rates — — — — (8) 2 (1) (7) Transfers to assets held for sale (Note 18) — — — — — 31 — 31 Transfers from right-of-use assets — — — — — 40 — 40 As at Dec. 31, 2021 — — 468 1,093 2,178 4,150 180 8,069 Depreciation — — 21 130 308 63 16 538 Retirement of assets — — (8) (6) (10) (7) (2) (33) Disposals — — — — (1) (211) — (212) Change in foreign exchange rates — — — 11 2 89 — 102 Transfers to assets held for sale (Note 18) — — (3) — — — — (3) Transfers in (out) of PP&E (5) — — — — 335 (340) — (5) As at Dec. 31, 2022 — — 478 1,228 2,812 3,744 194 8,456 Carrying amount As at Dec. 31, 2020 495 96 399 1,777 1,877 968 210 5,822 As at Dec. 31, 2021 184 96 399 2,183 1,909 363 186 5,320 As at Dec. 31, 2022 963 93 362 2,005 1,718 230 185 5,556 (1) The renewable generation that was previously disclosed has been separated by segment. (2) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance. (3) In 2022, the Company capitalized $16 million (2021 – $14 million) of interest to PP&E in at a weighted average rate of 6.0 per cent (2021 – 6.0 per cent). (4) The 2021 impairment charges, net of reversals exclude the changes in decommissioning and restoration provisions on assets. (5) Includes transfers between PP&E classifications, net of accumulated depreciation. Assets under Construction The Company commenced construction on the Horizon Hill wind project and White Rock wind projects in 2022. The Company also began its rehabilitation plan of the Kent Hills wind facilities during the second quarter of 2022 and capitalized additions of $77 million in 2022. Initial construction activities on the Garden Plain wind project started in the third quarter of 2021 and the Northern Goldfields Solar project in the fourth quarter of 2021, with construction activities continuing throughout 2022 for both projects. Change in Estimate - Useful Lives During 2022, the Company adjusted the useful lives of certain assets included in the Gas segment to reflect changes made based on the future operating expectations of the assets. This resulted in an increase of $132 million in depreciation expense that was recognized in the Consolidated Statement of Earnings (Loss) in 2022.

Right of Use Asset

Right of Use Asset	12 Months Ended
	Dec. 31, 2022
Disclosure of leases [Abstract]
Right of Use Assets	Right-of-Use Assets The Company leases various properties and types of equipment. Lease contracts are typically made for fixed periods. Leases are negotiated on an individual basis and contain a wide range of terms and conditions. The lease agreements do not impose covenants, but leased assets may not be used as security for borrowing purposes. A reconciliation of the changes in the carrying amount of the right-of-use assets is as follows: Land Buildings Vehicles Equipment Pipeline Total As at Dec. 31, 2020 58 24 1 16 42 141 Additions — 1 — — — 1 Acquisitions (Note 4) 13 — — — — 13 Depreciation (3) (5) — (2) (1) (11) Disposal of assets — — — — (41) (41) Transfers — — — (8) — (8) As at Dec. 31, 2021 68 20 1 6 — 95 Additions 36 — 1 3 — 40 Depreciation (4) (5) — (2) — (11) Change in foreign exchange 2 — — — — 2 As at Dec. 31, 2022 102 15 2 7 — 126 During 2022, the Company recognized additions of $36 million mainly related to land leases for the Horizon Hill and White Rock wind projects. On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO. As part of the transaction, the natural gas transportation agreement with the Pioneer Pipeline Limited Partnership was terminated, which resulted in the derecognition of the right-of-use asset of $41 million and lease liability of $43 million related to the pipeline, resulting in a gain of $2 million. For the year ended Dec. 31, 2022, TransAlta paid $16 million (2021 – $15 million) related to recognized lease liabilities, consisting of $9 million (2021 – $8 million) of principal repayments and $7 million (2021 – $7 million) of interest expense. Short-term leases (term of less than 12 months) and leases with total lease payments below the Company's capitalization threshold (low value leases) do not require recognition as lease liabilities and right-of-use assets. For the year ended Dec. 31, 2022, the Company expensed $2 million (2021 and 2020 – nil) related to short-term and low value leases.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2022
Disclosure of detailed information about intangible assets [abstract]
Intangible Assets	Intangible Assets A reconciliation of the changes in the carrying amount of intangible assets is as follows: Power Software Intangibles Coal rights Total Cost As at Dec. 31, 2020 269 412 3 149 833 Additions — — 9 — 9 Impairment charges (Note 7) — — — (17) (17) Change in foreign exchange rates — (2) — — (2) Transfers — 12 (8) — 4 As at Dec. 31, 2021 269 422 4 132 827 Additions (1) — — 31 — 31 Change in foreign exchange rates 3 3 1 — 7 Transfers — 12 (9) — 3 As at Dec. 31, 2022 272 437 27 132 868 Accumulated amortization As at Dec. 31, 2020 123 272 — 125 520 Amortization 17 27 — 7 51 As at Dec. 31, 2021 140 299 — 132 571 Amortization 17 26 — — 43 Change in foreign exchange rates 1 1 — — 2 As at Dec. 31, 2022 158 326 — 132 616 Carrying amount As at Dec. 31, 2020 146 140 3 24 313 As at Dec. 31, 2021 129 123 4 — 256 As at Dec. 31, 2022 114 111 27 — 252

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2022
Disclosure of detailed information about goodwill [Abstract]
Goodwill	Goodwill Goodwill acquired through business combinations has been allocated to groups of CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments is as follows: As at Dec. 31 2022 2021 Hydro 258 258 Wind and Solar 176 175 Energy Marketing 30 30 Total goodwill 464 463 For the purposes of the 2022 goodwill impairment review, the Company determined the recoverable amounts of the Hydro, Wind and Solar and Energy Marketing segments by calculating the fair value less costs of disposal using discounted cash flow projections based on the Company's long-range forecasts for the period extending to the last planned asset retirement in 2072. The resulting fair value measurement is categorized within Level III of the fair value hierarchy. No impairment of goodwill arose for any segment. The key assumptions impacting the determination of fair value for the Hydro, Wind and Solar and Energy Marketing segments are the following: • Discount rates used for the goodwill impairment calculation in 2022 for the Hydro, Wind and Solar, and Energy Marketing segments ranged from 5.9 per cent to 8.2 per cent (2021 – 5.0 per cent to 6.4 per cent). • Forecasts of electricity production for each facility are determined taking into consideration contracts for the sale of electricity, historical production, regional supply-demand balances and capital maintenance and expansion plans.

Other Assets

Other Assets	12 Months Ended
	Dec. 31, 2022
Disclosure of financial assets [abstract]
Other Assets	Other Assets The components of other assets are as follows: As at Dec. 31 2022 2021 Loan receivable 37 55 South Hedland prepaid transmission access and distribution costs 61 65 Long-term prepaids and other assets 56 48 Project development costs 10 29 Total Other assets 164 197 Included in the Consolidated Statements of Financial Position as: Total current other assets (Note 13) 4 55 Total long-term other assets 160 142 Total Other assets 164 197 The loan receivable of $37 million (2021 – $55 million) is an unsecured loan related to an advancement by the Company's subsidiary, Kent Hills Wind LP, of the net financing proceeds of the Kent Hills Wind Bond ("KH Bonds"), to its 17 per cent partner. On June 1, 2022, the loan receivable agreement was amended and its original maturity date of Oct. 2, 2022, was extended to October 2027, resulting in the classification of a portion of the loan receivable to non-current assets. The remaining terms of the original loan are unchanged and it continues to bear interest at 4.55 per cent, with interest payable quarterly. No scheduled principal repayments are required until maturity. However, repayments may be required for amounts associated with foundation replacement capital expenditures and for operating account funding, as outlined in the amendment made to the KH Bonds. During 2022, the Company received repayments of $18 million that were required as part of the waiver and amendment made to the KH Bonds. South Hedland prepaid transmission access and distribution costs are costs that are amortized on a straight-line basis over the South Hedland PPA contract life. Long-term prepaids and other assets include the funded portion of the TransAlta Energy Transition Bill commitments discussed in Note 37 (G), costs related to transmission infrastructure and other contractually required prepayments and deposits. During 2022, $16 million of costs related to transmission infrastructure at the Windrise wind facility were reclassified from PP&E to other assets (long-term prepaids and other assets) and will be amortized to net earnings (loss) over the useful life of the Windrise wind facility. Project development costs primarily include the pre-construction project costs for projects. The change in project development costs is as follows: As at Dec. 31 2022 2021 Balance, Jan 1 29 25 Additions 29 15 Transfers to PP&E (Note 19) (29) (1) Transfers to intangible assets (Note 21) (19) — Impairment charges (Note 7) — (10) Balance, Dec. 31 10 29

Decommissioning and Other Provi

Decommissioning and Other Provisions	12 Months Ended
	Dec. 31, 2022
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Decommissioning and Other Provisions	Decommissioning and Other Provisions The change in decommissioning and other provision balances is as follows: Decommissioning and Other provisions Total Balance, Dec. 31, 2020 608 65 673 Liabilities incurred 8 22 30 Liabilities settled (18) (62) (80) Accretion 32 — 32 Acquisition of liabilities 2 — 2 Revisions in estimated cash flows 167 12 179 Revisions in discount rates (6) — (6) Reversals — (3) (3) Balance, Dec. 31, 2021 793 34 827 Liabilities incurred 1 23 24 Liabilities settled (35) (12) (47) Accretion (Note 10) 49 — 49 Disposals (5) — (5) Revisions in estimated cash flows 95 5 100 Revisions in discount rates (225) — (225) Reversals — (9) (9) Change in foreign exchange rates 15 — 15 Balance, Dec. 31, 2022 688 41 729 Included in the Consolidated Statements of Financial Position as: As at Dec. 31, 2022 2021 Current portion 70 48 Non-current portion 659 779 Total Decommissioning and other provisions 729 827 A. Decommissioning and Restoration A provision has been recognized for all generating facilities and mines for which TransAlta is legally, or constructively, required to remove the facilities at the end of their useful lives and restore the sites to their original condition. TransAlta estimates that the undiscounted amount of cash flow required to settle these obligations is approximately $1.6 billion, which will be incurred between 2023 and 2072. The majority of the costs will be incurred between 2023 and 2050. During 2022, the Company accelerated the expected timing on decommissioning and restoration for certain facilities. This increased the decommissioning and restoration provision by $95 million, of which $46 million increased operating assets in PP&E and $49 million was recognized as an impairment charge in net earnings related to retired assets. In 2021, the Company increased the decommissioning and restoration provision by $167 million related to an engineering study on the decommissioning costs of the wind sites of $120 million and the Sundance and Keephills Units change in useful lives of $47 million. Of the total increase in decommissioning and restoration provisions,$133 million increased operating assets in PP&E and $34 million was recognized as an impairment charge in net earnings related to retired assets. During 2022, the decommissioning and restoration provision decreased by $225 million (2021 – $6 million) due to a significant increase in discount rates, largely driven by increases in market benchmark rates. On average, discount rates increased with rates ranging from 7.0 to 9.7 per cent as at Dec. 31, 2022 (2021 – 3.6 to 6.5 per cent). This has resulted in a corresponding decrease in PP&E of $123 million (2021 – $6 million) on operating assets and recognition of a $102 million (2021 – nil) impairment reversal in net earnings related to retired assets. At Dec. 31, 2022, the Company has provided a surety bond in the amount of US$147 million (2021 – US$147 million) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2022, the Company had provided a surety bond and letters of credit in the amount of $187 million (2021 – $188 million) in support of future decommissioning obligations at the Highvale mine. B. Other Provisions Other provisions include provisions arising from ongoing business activities, amounts related to commercial disputes between the Company and customers or suppliers and onerous contract provisions. Information about the expected timing of settlement and uncertainties that could impact the amount or timing of settlement has not been provided as this may impact the Company’s ability to settle the provisions in the most favourable manner. The onerous contract provisions occurred as a result of decisions to no longer operate on coal in Canada. Future royalty payments related to the extraction of coal at the Highvale mine will occur until 2023 under the royalty contract. Payments related to coal contracts for Sheerness are required until 2025. At Dec. 31, 2022, the remaining balance of the provision for the onerous royalty contract was $7 million and the remaining balance of the onerous coal contract was $10 million.

Credit Facilities, Long-Term De

Credit Facilities, Long-Term Debt and Lease Liabilities	12 Months Ended
	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Credit Facilities, Long-Term Debt and Lease Liabilities	Credit Facilities, Long-Term Debt and Lease Liabilities A. Amounts Outstanding The amounts outstanding are as follows: As at Dec. 31 2022 2021 Segment Maturity Currency Carrying Face Interest (1) Carrying Face Interest Credit facilities Committed syndicated bank facility (2) Corporate 2026 CAD 32 33 4.7 % — — — % Term Facility Corporate 2024 CAD 396 400 6.5 % — — — % Debentures 7.3% Medium term notes Corporate 2029 CAD 110 110 7.3 % 110 110 7.3 % 6.9% Medium term notes Corporate 2030 CAD 141 141 6.9 % 141 141 6.9 % Senior notes (3) 7.8% Senior notes (4) Corporate 2029 USD 533 542 7.8 % — — — % 6.5% Senior notes Corporate 2040 USD 401 407 6.5 % 378 383 6.5 % 4.5% Senior notes Corporate 2022 USD — — 4.5 % 510 511 4.5 % Non-recourse Melancthon Wolfe Wind LP bond Wind & Solar 2028 CAD 202 203 3.8 % 235 237 3.8 % New Richmond Wind LP Wind & Solar 2032 CAD 112 113 4.0 % 120 121 4.0 % Kent Hills Wind LP bond Wind & Solar 2033 CAD 206 209 4.5 % 221 221 4.5 % Windrise Wind LP bond Wind & Solar 2041 CAD 170 173 3.4 % 171 173 3.4 % Pingston bond Hydro 2023 CAD 45 45 3.0 % 45 45 3.0 % TAPC Holdings LP bond (Poplar Creek) Gas 2030 CAD 94 95 8.9 % 102 104 4.4 % TEC Hedland PTY Ltd bond (5) Gas 2042 AUD 711 720 4.1 % 732 742 4.1 % TransAlta OCP LP bond Gas 2030 CAD 241 242 4.5 % 263 265 4.5 % Tax equity financing Big Level & Antrim (6) Wind & Solar 2029 USD 102 108 6.6 % 106 112 6.6 % Lakeswind (7) Wind & Solar 2024 USD 15 15 10.5 % 18 18 10.5 % North Carolina Solar (8) Wind & Solar 2028 USD 6 6 7.3 % 11 11 7.3 % Other Corporate 2023 CAD 1 1 5.9 % 4 4 5.9 % Total long-term debt 3,518 3,563 3,167 3,198 Lease liabilities 135 100 Total long-term debt and lease liabilities 3,653 3,267 Less: current portion of long-term debt (170) (837) Less: current portion of lease liabilities (8) (7) Total current long-term debt and lease liabilities (178) (844) Total non-current credit facilities, long-term debt and lease 3,475 2,423 (1) Interest rate reflects the stipulated rate or the average rate weighted by principal amounts outstanding and is before the effect of hedging. (2) Composed of bankers’ acceptances and other commercial borrowings under long-term committed credit facilities. (3) US face value at Dec. 31, 2022 — US$700 million (2021 – US$700 million). (4) The effective interest rate for the senior notes is 5.98 per cent after the effects of gains realized on settled interest rate hedging instruments. (5) AU face value at Dec. 31, 2022 — AU$786 million (2021 – AU$800 million). (6) US face value at Dec. 31, 2022 — US$79 million (2021 – US$88 million). (7) US face value at Dec. 31, 2022 — US$11 million (2021 – US$14 million). (8) US face value at Dec. 31, 2022 — US$5 million (2021 – US$9 million). The Company's credit facilities are summarized in the table below: As at Dec. 31, 2022 Facility Utilized Available Maturity Credit Facilities Outstanding letters of credit (1) Cash drawings Committed TransAlta Corporation syndicated credit facility 1,250 738 — 512 Q2 2026 TransAlta Renewables syndicated credit facility 700 — 33 667 Q2 2026 TransAlta Corporation bilateral credit facilities 240 219 — 21 Q2 2024 TransAlta Corporation Term Facility 400 — 400 — Q3 2024 Total Committed 2,590 957 433 1,200 Non-Committed TransAlta Corporation demand facilities 250 120 — 130 n/a TransAlta Renewables demand facility 150 98 — 52 n/a Total Non-Committed 400 218 — 182 (1) TransAlta has obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase obligations. Letters of credit drawn against the non-committed facilities reduce the available capacity under the committed syndicated credit facilities. At Dec. 31, 2022, TransAlta provided cash collateral of $304 million. These facilities are the primary source for short-term liquidity after the cash flow generated from the Company's business. The TransAlta Corporation committed syndicated credit facility was converted into a Sustainability Linked Loan in 2021. During 2022, the Company closed a two-year $400 million floating rate Term Facility with its banking syndicate maturing on Sept. 7, 2024. In addition, the committed syndicated credit facilities were extended by one year to June 30, 2026 and the committed bilateral credit facilities were extended by one year to June 30, 2024. Interest rates on the credit facilities and Term Facility vary depending on the option selected (Canadian prime, bankers' acceptances, SOFR or US base rate, etc.) in accordance with a pricing grid that is standard for such facilities. The Company is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. In addition to the $1.0 billion available under the credit facilities, the Company also has $1.1 billion of available cash and cash equivalents, net of bank overdraft, and $17 million ($17 million principal portion) in cash restricted for repayment of the OCP bonds (refer to section E below). TransAlta has letters of credit of $218 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities. Senior Notes On Nov. 17, 2022, the Company issued US$400 million senior notes ("US$400 million Senior Green Bonds"), which have a fixed coupon rate of 7.75 per cent per annum and matures on Nov. 15, 2029. Including the effects of settled interest rate swaps, the notes have an effective yield of approximately 5.982 per cent. The notes are unsecured and rank equally in right of payment with all of our existing and future senior indebtedness and senior in right of payment to all of our future subordinated indebtedness. The interest payments on the bonds are made semi-annually, on November 15 and May 15 with the first payment commencing May 15, 2023. TransAlta will allocate an amount equal to the net proceeds from this offering to finance or refinance, new and/or existing eligible green projects in accordance with its Green Bond Framework ("the Framework"). The Framework received a second-party opinion from Sustainalytics, which verified that it aligned with the Green Bond Principles from the International Capital Markets Association. On Nov. 15, 2022, the Company repaid the US$400 million 4.50 per cent unsecured senior notes on its maturity in addition to related fees and expenses. A total of US$370 million (2021 – US$370 million) of the senior notes has been designated as a hedge of the Company’s net investment in US operations. Non-Recourse Debt On Dec. 6, 2021, TransAlta completed a secured green bond by way of private placement for approximately $173 million ("Windrise Wind LP Bond Offering"). Windrise Wind LP Bond Offering is secured by a first ranking charge over all assets of the issuer, Windrise Wind LP and the bonds amortize and bear interest from their date of issue at a rate of 3.41 per cent per annum and mature on Sept. 30, 2041. Payments on the bonds will be interest-only to and including Dec. 31, 2022, with quarterly blended payments of principal and interest commencing on March 31, 2023. TransAlta used the proceeds of the Windrise Wind LP Bond Offering to finance or refinance eligible green projects, including renewable energy facilities and to fund a construction reserve account. Tax Equity Tax equity financings are typically represented by the initial equity investments made by the project investors at each project (net of financing costs incurred), except for the Lakeswind and North Carolina Solar acquired tax equity financings, which were initially recognized at their fair values. Tax equity financing balances are reduced by the value of tax benefits (production tax credits, tax depreciation and investment tax credits) allocated to the investor and by cash distributions paid to the investor for their share of net earnings and cash flow generated at each project. Tax equity financing balances are increased by interest recognized at the implicit interest rate. The maturity dates of each financing are subject to change and are primarily dependent upon when the project investor achieves the agreed upon targeted rate of return. The Company anticipates the maturity dates of the tax equity financings will be: Big Level and Antrim in December 2029; Lakeswind in March 2024 and North Carolina Solar in December 2028. Other Other debt consists of an unsecured commercial loan obligation that bears interest at 5.9 per cent and matures in 2023, requiring annual payments of interest and principal. TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2022, the Company was in compliance with all debt covenants. B. Restrictions Related to Non-Recourse Debt and Other Debt The Melancthon Wolfe Wind LP, Pingston Power Inc., TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd notes, Windrise Wind LP and TransAlta OCP LP non-recourse bonds with a carrying value of $1.8 billion as at Dec. 31, 2022 (2021 – $1.9 billion) are subject to customary financing conditions and covenants that may restrict the Company’s ability to access funds generated by the facilities’ operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the fourth quarter of 2022 with the exception of Kent Hills Wind LP, as discussed below and TAPC Holdings LP, which has been impacted by higher interest rates in 2022. The funds in these entities that have accumulated since the fourth quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2023. At Dec. 31, 2022, $50 million (2021 – $67 million) of cash was subject to these financial restrictions. Proceeds received from the TEC Hedland Pty Ltd notes in the amount of $8 million (AU$9 million) are not able to be accessed by other corporate entities as the funds must be solely used by the project entities for the purpose of paying major maintenance costs. Additionally, certain non-recourse bonds require that certain reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit. Kent Hills Wind Bonds In the fourth quarter of 2021, the Company disclosed that events of default may have occurred under the trust indenture governing the terms of the KH Bonds. Accordingly, the Company classified the entire carrying value of the bonds as current as at Dec. 31, 2021. During the second quarter of 2022, the Company obtained a waiver and entered into a supplemental indenture that facilitated the rehabilitation of the Kent Hills 1 and 2 wind facilities. Upon receipt of the waiver, the Company reclassified a portion of the carrying value outstanding for the KH Bonds to non-current liabilities with the exception of the scheduled principal repayments due within the next 12 months. In accordance with the supplemental indenture, Kent Hills Wind LP cannot make any distributions to its partners until the foundation replacement work has been completed. A foundation replacement reserve account was set up in accordance with the supplemental indenture, with funds in the account being used to pay foundation replacement costs. The account is funded quarterly with the last funding requirement on April 1, 2023. The balance in the account is $65 million as at Dec. 31, 2022 (nil – Dec. 31, 2021). C. Security Non-recourse debts totalling $1.4 billion as at Dec. 31, 2022 (2021 – $1.5 billion) are each secured by a first ranking charge over all of the respective assets of the Company’s subsidiaries that issued the bonds, which include PP&E with total carrying amounts of $1.5 billion at Dec. 31, 2022 (2021 – $1.5 billion) and intangible assets with total carrying amounts of $70 million (2021 – $78 million). At Dec. 31, 2022, a non-recourse bond of approximately $94 million (2021 – $103 million) was secured by a first ranking charge over the equity interests of the issuer that issued the non-recourse bond. The TransAlta OCP bonds have a carrying value of $241 million (2021 – $263 million) and are secured by the assets of TransAlta OCP, including the right to annual capital contributions and OCA payments from the Government of Alberta. Under the OCA, the Company receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million, net to the Company), commencing on Jan. 1, 2017 and terminating at the end of 2030. D. Principal Repayments 2023 2024 2025 2026 2027 2028 and thereafter Total Principal repayments (1) 170 527 142 177 154 2,393 3,563 Lease liabilities (2) (7) 4 4 3 4 127 135 (1) Excludes impact of hedge accounting and derivatives. (2) Lease liabilities include a lease incentive of $12 million, expected to be received in 2023. E. Restricted Cash The Company had $17 million (2021 – $17 million) of restricted cash related to the TransAlta OCP bonds, which is required to be held in a debt service reserve account to fund scheduled future debt repayments. The Company also had $53 million (2021 – $53 million) of restricted cash related to the TEC Hedland Pty Ltd bond; reserves are required to be held under commercial arrangements and for debt service. Cash reserves may be replaced by letters of credit in the future. F. Letters of Credit Letters of credit issued by TransAlta are drawn on its $1.3 billion committed syndicated credit facility, its $240 million bilateral committed credit facilities and its $250 million uncommitted demand facilities. TransAlta has drawn $738 million on its committed syndicated credit facility, $219 million on its bilateral committed credit facilities and $120 million on its uncommitted demand facilities. Letters of credit issued by TransAlta Renewables are drawn on its $700 million committed syndicated credit facility and its $150 million uncommitted demand facility. TransAlta Renewables has drawn letters of credit of $98 million on its uncommitted demand facility. Letters of credit are issued to counterparties under various contractual arrangements with the Company and certain subsidiaries of the Company. If the Company or its subsidiary does not perform under such contracts, the counterparty may present its claim for payment to the financial institution through which the letter of credit was issued. Any amounts owed by the Company or its subsidiaries under these contracts are reflected in the Consolidated Statements of Financial Position. All letters of credit expire within one year and are expected to be renewed, as needed, in the normal course of business. The total outstanding letters of credit as at Dec. 31, 2022, was $1,175 million (2021 – $902 million) with no (2021 – nil) amounts exercised by third parties under these arrangements. G. Currency Impacts The strengthening of the US dollar has increased the US-denominated long-term debt balances, mainly the senior notes and tax equity financing, by $41 million as at Dec. 31, 2022 ( 2021 – $1 million). Almost all of the US-denominated debt is hedged either through financial contracts or net investments in the US operations. Additionally, the weakening of the Australian dollar has decreased the Australian-denominated non-recourse senior secured notes balance by approximately $9 million as at Dec. 31, 2022 (2021 – $40 million). As this debt is issued by an Australian subsidiary, the foreign currency translation impacts are recognized within other comprehensive income (loss).

Exchangeable Securities

Exchangeable Securities	12 Months Ended
	Dec. 31, 2022
Exchangeable Securities [Abstract]
Exchangeable Securities	Exchangeable Securities On March 22, 2019, the Company entered into an Investment Agreement whereby Brookfield Renewable Partners or its affiliates (collectively "Brookfield") agreed to invest $750 million in TransAlta through the purchase of exchangeable securities, which are exchangeable into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Alberta Hydro Assets’ future-adjusted EBITDA ("Option to Exchange"). A. $750 Million Exchangeable Securities As at Dec. 31, 2022 Dec. 31, 2021 Carrying value Face value Interest Carrying value Face value Interest Exchangeable debentures – due May 1, 2039 (1) 339 350 7 % 335 350 7 % Exchangeable preferred shares (2) 400 400 7 % 400 400 7 % Total exchangeable securities 739 750 735 750 (1) On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for seven per cent unsecured subordinated debentures due May 1, 2039. (2) On Oct. 30, 2020, Brookfield invested the second tranche of $400 million in exchange for redeemable, retractable first preferred shares (Series 1). Exchangeable preferred share dividends are reported as interest expense. On Dec. 12, 2022, the Company declared a dividend of $7 million in aggregate for Exchangeable Preferred Shares at the fixed rate of 1.764 per cent, per share, payable on Feb. 28, 2023. The Exchangeable Preferred Shares are considered debt for accounting purposes and as such, dividends are reported as interest expense (Note 10). B. Option to Exchange As at Dec. 31, 2022 Dec. 31, 2021 Description Base fair value Sensitivity Base fair value Sensitivity Option to exchange – embedded derivative — +nil -25 — +nil -32 The Investment Agreement allows Brookfield the option to exchange all of the outstanding exchangeable securities after Dec. 31, 2024, into an equity ownership interest of up to a maximum 49 per cent in an entity that has been formed to hold TransAlta’s Alberta Hydro Assets. The fair value of the option to exchange is considered a Level III fair value measurement as there is no available market-observable data. It is therefore valued using a mark-to-forecast model with inputs that are based on historical data and changes in underlying discount rates only when it represents a long-term change in the value of the option to exchange. Sensitivity ranges for the base fair value are determined using reasonably possible alternative assumptions for key unobservable inputs, which is mainly the change in the implied discount rate of the future cash flow. The sensitivity analysis has been prepared using the Company’s assessment that a change in the implied discount rate of the future cash flow of 1 per cent is a reasonably possible change. The maximum equity interest Brookfield can own with respect to the Hydro Assets is 49 per cent. If Brookfield’s ownership interest is less than 49 per cent at conversion, Brookfield has a one-time option payable in cash to increase its ownership to up to 49 per cent, exercisable up until Dec. 31, 2028, and provided Brookfield holds at least 8.5 per cent of TransAlta’s common shares. Under this top-up option, Brookfield will be able to acquire an additional 10 per cent interest in the entity holding the Hydro Assets, provided the 20-day volume-weighted average price (“VWAP”) of TransAlta’s common shares is not less than $14 per share prior to the exercise of the option and up to the full 49 per cent if the 20-day VWAP of TransAlta’s common shares at that time is not less than $17 per share. To the extent the value of the investment would exceed a 49 per cent equity interest, Brookfield will be entitled to receive the balance of the redemption price in cash. Under the terms of the Investment Agreement, Brookfield committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to not less than nine per cent by May 1, 2021. As of Dec. 31, 2022, Brookfield, through its affiliates, held, owned or had control over an aggregate of 35,456,023 common shares, representing approximately 13.2 per cent of the issued and outstanding common shares, calculated on an undiluted basis. In connection with the Investment Agreement, Brookfield is entitled to nominate two directors for election to the Board.

Defined Benefit Obligation and

Defined Benefit Obligation and Other Long-Term Liabilities	12 Months Ended
	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Defined Benefit Obligation and Other Long-Term Liabilities	Defined Benefit Obligation and Other Long-Term Liabilities The components of defined benefit obligation and other long-term liabilities are as follows: As at Dec. 31 2022 2021 Defined benefit obligation (Note 32) 150 228 Long-term incentive accruals (Note 31) 8 4 Retail power contract liability 126 — Other 10 21 Total 294 253 The liability for pension and post-employment benefits and associated costs included in compensation expenses are impacted by estimates related to changes in key actuarial assumptions, including discount rates. The defined benefit obligation has decreased by $78 million to $150 million as at Dec. 31, 2022, from $228 million as at Dec. 31, 2021. The decrease is primarily driven by increases in discount rates in 2022, largely driven by increases in market benchmark rates and the voluntary contribution of $35 million made to the Sunhills Mining Ltd. Pension Plan, partially offset by a decrease in plan assets due to poor market returns. The Company made a voluntary contribution of $35 million during 2022 to further improve the funded status of the Sunhills Mining Ltd. Pension Plan for the Highvale mine and to support the employees affected by the closure of the Highvale mine in 2021 and our transition off-coal to cleaner sources. The contribution reduces the amount of the Company's future funding obligations, including amounts secured by the letters of credit. A 1 per cent increase in discount rates would result in a $39 million decrease in the defined benefit obligation. Refer to Note 32 for additional sensitivities impacting the defined benefit obligation.

Common Shares

Common Shares	12 Months Ended
	Dec. 31, 2022
Share Capital, Reserves And Other Equity Interest [Abstract]
Common Shares	Common Shares A. Issued and Outstanding TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value. As at Dec. 31 2022 2021 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 271.0 2,901 269.8 2,896 Purchased and cancelled under the NCIB (4.3) (46) — — Effects of share-based payment plans 0.9 5 — (3) Stock options exercised 0.5 3 1.2 8 Issued and outstanding, end of year 268.1 2,863 271.0 2,901 B. Normal Course Issuer Bid ("NCIB") Program Shares purchased by the Company under the NCIB are recognized as a reduction to share capital equal to the average carrying value of the common shares. Any difference between the aggregate purchase price and the average carrying value of the common shares is recorded in deficit. The following are the effects of the Company's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2022 2021 Total shares purchased (1) 4,342,300 — Average purchase price per share 12.48 — Total cost (millions) 54 — Weighted average book value of shares cancelled 46 — Amount recorded in deficit (8) — (1) As at Dec. 31, 2022, includes 164,300 (2021 – nil) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. The Company paid $52 million in 2022 and the remaining amount was paid subsequent to the year end. 2022 On May 24, 2022, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 17, 2022. Any common shares purchased under the NCIB are cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2022, and ends on May 30, 2023. 2021 On May 25, 2021, the Company announced that the TSX accepted the notice filed by the Company to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. No common shares were repurchased in 2021 under the current and previous NCIB. C. Shareholder Rights Plan The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 28, 2022. As required, the Shareholder Rights Plan must be put before the Company’s shareholders every three years for approval. It was last approved on April 28, 2022, and will need to be approved at the annual meeting of shareholders in 2025. The primary objective of the Shareholder Rights Plan is to encourage a potential acquirer to meet certain minimum standards designed to promote the fair and equal treatment of all common shareholders. When an acquiring shareho lder acquires 20 per cent or more of the Company’s common shares, except in limited circumstances including by way of a “permitted bid” or a "competing permitted bid" (as defined in the Shareholder Rights Plan), the rights granted under the Shareholder Rights Plan become exercisable by all shareholders except those held by the acquiring shareholder. Each right will entitle a shareholder, other than the acquiring shareholder, to purchase additional common shares at a significant discount to market, thus exposing the person acquiring 20 per cent or more of the shares to substantial dilution of their holdings. D. Earnings per Share Year ended Dec. 31 2022 2021 2020 Net earnings (loss) attributable to common shareholders 4 (576) (336) Basic and diluted weighted average number of common shares outstanding 271 271 275 Net earnings (loss) per share attributable to common shareholders, basic and diluted 0.01 (2.13) (1.22) E. Dividends On Dec. 12, 2022, the Company declared a quarterly dividend of $0.055 per common share, payable on April 1, 2023. There have been no other transactions involving common shares between the reporting date and the date of completion of these consolidated financial statements. A. Issued and Outstanding All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares. As at Dec. 31 2022 2021 Series (1) Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 9.6 235 Series B 2.4 58 2.4 58 Series C 10.0 243 11.0 269 Series D 1.0 26 — — Series E 9.0 219 9.0 219 Series G 6.6 161 6.6 161 Issued and outstanding, end of year 38.6 942 38.6 942 (1) Series 1 Preferred Shares are accounted for as long-term debt. Refer to Note 26. I. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On March 31, 2021, the Company converted 1,417,338 of its 10.2 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") and 871,871 of its 1.8 million Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares"), on a one-for-one basis, into Series B Shares and Series A Shares. II. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion On June 30, 2022, the Company converted 1,044,299 of its 11.0 million Cumulative Redeemable Rate Reset First Preferred Shares, Series C (“Series C Shares”), on a one-for-one basis, into Cumulative Redeemable Floating Rate First Preferred Shares, Series D (“Series D Shares”). The Series C Shares will pay fixed cumulative preferential cash dividends on a quarterly basis, for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The annual fixed dividend rate of 5.854 per cent, being equal to the five-year Government of Canada bond yield of 2.754 per cent determined as of May 31, 2022, plus 3.10 per cent, in accordance with the terms of the Series C Shares. The Series D Shares will pay quarterly floating rate cumulative preferential cash dividends for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The quarterly dividend rate for the Series D Shares will be established each quarter, being equal to the annual rate for the auction of 90-day Government of Canada Treasury Bills, plus 3.10 per cent, in accordance with the terms of the Series D Shares. III. Series E Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On Sept. 21, 2022, the Company announced that, after taking into account all election notices received for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series E (the "Series E shares") into Cumulative Redeemable Floating Rate Preferred Shares Series F (the "Series F Shares"), there were 89,945 Series E Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series F Shares. Therefore, none of the Series E Shares were converted into Series F Shares. As a result, the Series E Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series E Shares for the five-year period from and including Sept. 30, 2022, to but excluding Sept. 30, 2027, will be 6.894 per cent, which is equal to the five-year Government of Canada bond yield of 3.244 per cent, determined as of Aug. 31, 2022, plus 3.65 per cent, in accordance with the terms of the Series E Shares. Preferred Share Series Information The holders are entitled to receive cumulative fixed quarterly cash dividends at specified rates, as approved by the Board. After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed rate resets to the sum of the then five-year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified spread. Upon each Rate Reset Date, the shares are also: • Redeemable at the option of the Company, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. • Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Company and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2022, are as follows: Series Rate during term Annual dividend rate per share ($) (1) Next Rate spread over benchmark (per cent) Convertible to A Fixed 0.71924 March 31, 2026 2.03 B B Floating 1.10295 March 31, 2026 2.03 A C Fixed 1.34933 Jun. 30, 2027 3.10 D D Floating 1.40030 Jun. 30, 2027 3.10 C E Fixed 1.51102 Sept. 30, 2027 3.65 F F Floating — — 3.65 E G Fixed 1.24700 Sept. 30, 2024 3.80 H H Floating — — 3.80 G (1) The annual dividend rate per share represents dividends declared in 2022. B. Dividends The following table summarizes the value of the preferred share dividends declared in 2022 and 2021: Total dividends declared Series 2022 (1) 2021 (1) A 7 7 B (2) 3 1 C 14 11 D (3) 1 — E 13 12 G 8 8 Total for the year 46 39 (1) No dividends were declared in the first quarter of the year as the quarterly dividend related to the period covering the first quarter was declared in December of the prior year. (2) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.0 per cent. (3) Series D Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 3.1 per cent. TransAlta’s capital is comprised of the following: As at Dec. 31 2022 2021 Increase/ Long-term debt (1) 3,653 3,267 386 Exchangeable securities 739 735 4 Bank overdraft 16 — 16 Equity Common shares 2,863 2,901 (38) Preferred shares 942 942 — Contributed surplus 41 46 (5) Deficit (2,514) (2,453) (61) Accumulated other comprehensive income (loss) (222) 146 (368) Non-controlling interests 879 1,011 (132) Less: available cash and cash equivalents (1,134) (947) (187) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (17) (17) — Less: fair value asset of hedging instruments on long-term debt (4) (3) (2) (1) Total capital 5,243 5,629 (386) (1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt. (2) The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed internally and evaluated by management using a net debt position. In this regard, these funds may be available and used to facilitate repayment of debt. (3) The Company includes the principal portion of restricted cash on TransAlta OCP bonds as this cash is restricted specifically to repay outstanding debt. (4) The Company includes the fair value of economic and designated hedging instruments on debt in an asset, or liability, position as a reduction, or increase, in the calculation of capital, as the carrying value of the related debt has either increased, or decreased, due to changes in foreign exchange rates.

Preferred Shares

Preferred Shares	12 Months Ended
	Dec. 31, 2022
Share Capital, Reserves And Other Equity Interest [Abstract]
Preferred Shares	Common Shares A. Issued and Outstanding TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value. As at Dec. 31 2022 2021 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 271.0 2,901 269.8 2,896 Purchased and cancelled under the NCIB (4.3) (46) — — Effects of share-based payment plans 0.9 5 — (3) Stock options exercised 0.5 3 1.2 8 Issued and outstanding, end of year 268.1 2,863 271.0 2,901 B. Normal Course Issuer Bid ("NCIB") Program Shares purchased by the Company under the NCIB are recognized as a reduction to share capital equal to the average carrying value of the common shares. Any difference between the aggregate purchase price and the average carrying value of the common shares is recorded in deficit. The following are the effects of the Company's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2022 2021 Total shares purchased (1) 4,342,300 — Average purchase price per share 12.48 — Total cost (millions) 54 — Weighted average book value of shares cancelled 46 — Amount recorded in deficit (8) — (1) As at Dec. 31, 2022, includes 164,300 (2021 – nil) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. The Company paid $52 million in 2022 and the remaining amount was paid subsequent to the year end. 2022 On May 24, 2022, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 17, 2022. Any common shares purchased under the NCIB are cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2022, and ends on May 30, 2023. 2021 On May 25, 2021, the Company announced that the TSX accepted the notice filed by the Company to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. No common shares were repurchased in 2021 under the current and previous NCIB. C. Shareholder Rights Plan The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 28, 2022. As required, the Shareholder Rights Plan must be put before the Company’s shareholders every three years for approval. It was last approved on April 28, 2022, and will need to be approved at the annual meeting of shareholders in 2025. The primary objective of the Shareholder Rights Plan is to encourage a potential acquirer to meet certain minimum standards designed to promote the fair and equal treatment of all common shareholders. When an acquiring shareho lder acquires 20 per cent or more of the Company’s common shares, except in limited circumstances including by way of a “permitted bid” or a "competing permitted bid" (as defined in the Shareholder Rights Plan), the rights granted under the Shareholder Rights Plan become exercisable by all shareholders except those held by the acquiring shareholder. Each right will entitle a shareholder, other than the acquiring shareholder, to purchase additional common shares at a significant discount to market, thus exposing the person acquiring 20 per cent or more of the shares to substantial dilution of their holdings. D. Earnings per Share Year ended Dec. 31 2022 2021 2020 Net earnings (loss) attributable to common shareholders 4 (576) (336) Basic and diluted weighted average number of common shares outstanding 271 271 275 Net earnings (loss) per share attributable to common shareholders, basic and diluted 0.01 (2.13) (1.22) E. Dividends On Dec. 12, 2022, the Company declared a quarterly dividend of $0.055 per common share, payable on April 1, 2023. There have been no other transactions involving common shares between the reporting date and the date of completion of these consolidated financial statements. A. Issued and Outstanding All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares. As at Dec. 31 2022 2021 Series (1) Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 9.6 235 Series B 2.4 58 2.4 58 Series C 10.0 243 11.0 269 Series D 1.0 26 — — Series E 9.0 219 9.0 219 Series G 6.6 161 6.6 161 Issued and outstanding, end of year 38.6 942 38.6 942 (1) Series 1 Preferred Shares are accounted for as long-term debt. Refer to Note 26. I. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On March 31, 2021, the Company converted 1,417,338 of its 10.2 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") and 871,871 of its 1.8 million Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares"), on a one-for-one basis, into Series B Shares and Series A Shares. II. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion On June 30, 2022, the Company converted 1,044,299 of its 11.0 million Cumulative Redeemable Rate Reset First Preferred Shares, Series C (“Series C Shares”), on a one-for-one basis, into Cumulative Redeemable Floating Rate First Preferred Shares, Series D (“Series D Shares”). The Series C Shares will pay fixed cumulative preferential cash dividends on a quarterly basis, for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The annual fixed dividend rate of 5.854 per cent, being equal to the five-year Government of Canada bond yield of 2.754 per cent determined as of May 31, 2022, plus 3.10 per cent, in accordance with the terms of the Series C Shares. The Series D Shares will pay quarterly floating rate cumulative preferential cash dividends for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The quarterly dividend rate for the Series D Shares will be established each quarter, being equal to the annual rate for the auction of 90-day Government of Canada Treasury Bills, plus 3.10 per cent, in accordance with the terms of the Series D Shares. III. Series E Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On Sept. 21, 2022, the Company announced that, after taking into account all election notices received for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series E (the "Series E shares") into Cumulative Redeemable Floating Rate Preferred Shares Series F (the "Series F Shares"), there were 89,945 Series E Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series F Shares. Therefore, none of the Series E Shares were converted into Series F Shares. As a result, the Series E Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series E Shares for the five-year period from and including Sept. 30, 2022, to but excluding Sept. 30, 2027, will be 6.894 per cent, which is equal to the five-year Government of Canada bond yield of 3.244 per cent, determined as of Aug. 31, 2022, plus 3.65 per cent, in accordance with the terms of the Series E Shares. Preferred Share Series Information The holders are entitled to receive cumulative fixed quarterly cash dividends at specified rates, as approved by the Board. After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed rate resets to the sum of the then five-year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified spread. Upon each Rate Reset Date, the shares are also: • Redeemable at the option of the Company, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. • Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Company and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2022, are as follows: Series Rate during term Annual dividend rate per share ($) (1) Next Rate spread over benchmark (per cent) Convertible to A Fixed 0.71924 March 31, 2026 2.03 B B Floating 1.10295 March 31, 2026 2.03 A C Fixed 1.34933 Jun. 30, 2027 3.10 D D Floating 1.40030 Jun. 30, 2027 3.10 C E Fixed 1.51102 Sept. 30, 2027 3.65 F F Floating — — 3.65 E G Fixed 1.24700 Sept. 30, 2024 3.80 H H Floating — — 3.80 G (1) The annual dividend rate per share represents dividends declared in 2022. B. Dividends The following table summarizes the value of the preferred share dividends declared in 2022 and 2021: Total dividends declared Series 2022 (1) 2021 (1) A 7 7 B (2) 3 1 C 14 11 D (3) 1 — E 13 12 G 8 8 Total for the year 46 39 (1) No dividends were declared in the first quarter of the year as the quarterly dividend related to the period covering the first quarter was declared in December of the prior year. (2) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.0 per cent. (3) Series D Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 3.1 per cent. TransAlta’s capital is comprised of the following: As at Dec. 31 2022 2021 Increase/ Long-term debt (1) 3,653 3,267 386 Exchangeable securities 739 735 4 Bank overdraft 16 — 16 Equity Common shares 2,863 2,901 (38) Preferred shares 942 942 — Contributed surplus 41 46 (5) Deficit (2,514) (2,453) (61) Accumulated other comprehensive income (loss) (222) 146 (368) Non-controlling interests 879 1,011 (132) Less: available cash and cash equivalents (1,134) (947) (187) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (17) (17) — Less: fair value asset of hedging instruments on long-term debt (4) (3) (2) (1) Total capital 5,243 5,629 (386) (1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt. (2) The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed internally and evaluated by management using a net debt position. In this regard, these funds may be available and used to facilitate repayment of debt. (3) The Company includes the principal portion of restricted cash on TransAlta OCP bonds as this cash is restricted specifically to repay outstanding debt. (4) The Company includes the fair value of economic and designated hedging instruments on debt in an asset, or liability, position as a reduction, or increase, in the calculation of capital, as the carrying value of the related debt has either increased, or decreased, due to changes in foreign exchange rates.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2022
Disclosure of analysis of other comprehensive income by item [abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) The components of and changes in, accumulated other comprehensive income (loss) are as follows: 2022 2021 Currency translation adjustment Opening balance, Jan. 1 (35) (21) Losses (gains) on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax 21 (14) Gains (losses) on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax (1) (25) — Balance, Dec. 31 (39) (35) Cash flow hedges Opening balance, Jan. 1 228 436 Losses on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax (2) (456) (208) Balance, Dec. 31 (228) 228 Employee future benefits Opening balance, Jan. 1 (29) (66) Net actuarial gains on defined benefit plans, net of tax (3) 37 37 Balance, Dec. 31 8 (29) Other Opening balance, Jan. 1 (18) (47) Intercompany and third-party investments at FVTOCI 55 29 Balance, Dec. 31 37 (18) Accumulated other comprehensive income (loss) (222) 146 (1) Net of income tax recovery of $3 million for the year ended Dec. 31, 2022 (2021 – nil). (2) Net of income tax recovery of $112 million for the year ended Dec. 31, 2022 (2021 – $57 million). (3) Net of income tax expense of $12 million for the year ended Dec. 31, 2022 (2021 – $11 million).

Share-Based Payment Plans

Share-Based Payment Plans	12 Months Ended
	Dec. 31, 2022
Share-based payment arrangements [Abstract]
Share-Based Payment Plans	Share-Based Payment Plans The Company has the following share-based payment plans: A. Performance Share Unit (“PSU”) and Restricted Share Unit (“RSU”) Plan Under the Share Unit Plan, grants of PSUs and RSUs may be made annually, but are measured and assessed over a three-year performance period. Grants are determined as a percentage of participants’ base pay and are converted to PSUs or RSUs on the basis of the Company’s common share price at the time of grant. Vesting of PSUs is subject to achievement over a three-year period of specific performance measures that are established at the time of each grant. RSUs are subject to a three-year cliff-vesting requirement. RSUs and PSUs track the Company’s share price over the three-year period and accrue dividends as additional units at the same rate as dividends paid on the Company’s common shares. The pre-tax compensation expense related to PSUs and RSUs in 2022 was $20 million (2021 – $14 million, 2020 – $15 million), which is included in OM&A in the Consolidated Statements of Earnings (Loss). B. Deferred Share Unit (“DSU”) Plan Under the Share Unit Plan, members of the Board and executives may, at their option, purchase DSUs using certain components of their fees or pay. A DSU is a notional share that has the same value as one common share of the Company and fluctuates based on the changes in the value of the Company’s common shares in the marketplace. DSUs accrue dividends as additional DSUs at the same rate as dividends are paid on the Company’s common shares. DSUs are redeemable in cash and may not be redeemed until the termination or retirement of the director or executive from the Company. The Company accrues a liability and expense for the appreciation in the common share value in excess of the DSU’s purchase price and for dividend equivalents earned. The pre-tax compensation expense related to the DSU's was nil in 2022 (2021 – $3 million expense, 2020 – $1 million expense). C. Stock Option Plan In 2022, the Company granted executive officers of the Company a total of 0.3 million stock options with a weighted average exercise price of $12.66 that vest over a three-year period and expire 7 years after issuance (2021 – 0.7 million stock options at $9.86; 2020 – 0.7 million stock options at $9.17). The expense recognized relating to these grants during 2022 was approximately $1 million (2021 – approximately $2 million, 2020 – approximately $2 million). The total options outstanding and exercisable under the Stock Option Plan at Dec. 31, 2022, are outlined below: Options outstanding Range of exercise prices (1) ($ per share) Number of options (millions) Weighted average remaining contractual life (years) Weighted average exercise price ($ per share) 5.00-12.00 3.0 3.89 8.41 (1) Options currently exercisable as at Dec. 31, 2022.

Employee Future Benefits

Employee Future Benefits	12 Months Ended
	Dec. 31, 2022
Employee Benefits [Abstract]
Employee Future Benefits	Employee Future Benefits A. Description The Company sponsors registered pension plans in Canada and the US covering substantially all employees of the Company in these countries and specific named employees working internationally. These plans have defined benefit and defined contribution options and in Canada there is an additional non-registered supplemental plan for eligible employees whose annual earnings exceed the Canadian income tax limit. Except for the Highvale pension plan acquired in 2013, the Canadian and US defined benefit pension plans are closed to new entrants. The US defined benefit pension plan was frozen effective Dec. 31, 2010, resulting in no future benefits being earned. The supplemental pension plan was closed as of Dec. 31, 2015, and a new defined contribution supplemental pension plan commenced for executive members effective Jan. 1, 2016. Current executives as of Dec. 31, 2015, were grandfathered into the old supplemental plan. The latest actuarial valuation for accounting purposes of the US pension plan was at Jan. 1, 2022. The latest actuarial valuation for accounting purposes of the Highvale and Canadian pension plans was at Dec. 31, 2021. The measurement date used for all plans to determine the fair value of plan assets and the present value of the defined benefit obligation was Dec. 31, 2022. Funding of the registered pension plans complies with applicable regulations that require actuarial valuations of the pension funds at least once every three years in Canada, or more, depending on funding status and every year in the US. The supplemental pension plan is solely the obligation of the Company. The Company is not obligated to fund the supplemental plan but is obligated to pay benefits under the terms of the plan as they come due. The Company posted a letter of credit in March 2022 in the amount of $96 million to secure the obligations under the supplemental plan. The Company provides other health and dental benefits to the age of 65 for both disabled members and retired members through its other post-employment benefits plans. The latest actuarial valuations for accounting purposes of the Canadian and US plans were as at Dec. 31, 2021 and Jan. 1, 2022, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2022. The Company provides several defined contribution plans, including an Australian superannuation plan and a US 401(k) savings plan, that provide for company contributions from 5 per cent to 11 per cent, depending on the plan. Optional employee contributions are allowed for all the defined contribution plans. B. Costs Recognized The costs recognized in net earnings during the year on the defined benefit, defined contribution and other post-employment benefits plans are as follows: Year ended Dec. 31, 2022 Registered Supplemental Other Total Current service cost 1 1 — 2 Administration expenses 1 — — 1 Interest cost on defined benefit obligation 13 3 — 16 Interest on plan assets (9) — — (9) Defined benefit expense 6 4 — 10 Defined contribution expense 11 — — 11 Net expense 17 4 — 21 Year ended Dec. 31, 2021 Registered Supplemental Other Total Current service cost 3 2 1 6 Administration expenses 1 — — 1 Interest cost on defined benefit obligation 12 2 — 14 Interest on plan assets (8) — — (8) Curtailment and amendment gain (7) — — (7) Defined benefit expense 1 4 1 6 Defined contribution expense 8 — — 8 Net expense 9 4 1 14 Year ended Dec. 31, 2020 Registered Supplemental Other Total Current service cost 5 2 1 8 Administration expenses 1 — — 1 Interest cost on defined benefit obligation 16 3 1 20 Interest on plan assets (11) (1) — (12) Curtailment and amendment gain (2) — — (2) Defined benefit expense 9 4 2 15 Defined contribution expense 9 — — 9 Net expense 18 4 2 24 C. Status of Plans The status of the defined benefit pension and other post-employment benefit plans is as follows: Year ended Dec. 31, 2022 Registered Supplemental Other Total Fair value of plan assets 274 15 — 289 Present value of defined benefit obligation (345) (85) (17) (447) Funded status – plan deficit (71) (70) (17) (158) Amount recognized in the consolidated financial statements: Accrued current liabilities (1) (6) (1) (8) Other long-term liabilities (70) (64) (16) (150) Total amount recognized (71) (70) (17) (158) Year ended Dec. 31, 2021 Registered Supplemental Other Total Fair value of plan assets 339 14 — 353 Present value of defined benefit obligation (469) (101) (23) (593) Funded status – plan deficit (130) (87) (23) (240) Amount recognized in the consolidated financial statements: Accrued current liabilities (4) (6) (2) (12) Other long-term liabilities (126) (81) (21) (228) Total amount recognized (130) (87) (23) (240) D. Plan Assets The fair value of the plan assets of the defined benefit pension and other post-employment benefit plans is as follows: Registered Supplemental Other Total As at Dec. 31, 2020 367 14 — 381 Interest on plan assets 8 — — 8 Net return (loss) on plan assets 14 (1) — 13 Contributions 5 6 1 12 Benefits paid (54) (5) (1) (60) Administration expenses (1) — — (1) As at Dec. 31, 2021 339 14 — 353 Interest on plan assets 9 — — 9 Net loss on plan assets (55) — — (55) Contributions (1) 38 6 — 44 Benefits paid (57) (5) — (62) Administration expenses (1) — — (1) Change in foreign exchange rates 1 — — 1 As at Dec. 31, 2022 274 15 — 289 (1) The Company made a voluntary contribution of $35 million to further improve the funded status of the Sunhills Mining Ltd. Pension Plan for the Highvale mine. The contribution reduces the amount of the Company's future funding obligations, including amounts secured by the letters of credit. The fair value of the Company’s defined benefit plan assets by major category is as follows: As at Dec. 31, 2022 Level I Level II Level III Total Equity securities Canadian — 18 — 18 US 12 5 — 17 International 38 41 — 79 Private — — 1 1 Bonds AAA — 24 — 24 AA — 38 — 38 A — 26 — 26 BBB 1 18 — 19 Below BBB — 6 — 6 Loans A — 1 — 1 BBB — 1 — 1 Alternative funds (1) — — 39 39 Money market and cash and cash equivalents — 20 — 20 Total 51 198 40 289 (1) Alternative funds include investments in infrastructure and real estate funds. As at Dec. 31, 2021 Level I Level II Level III Total Equity securities Canadian — 29 4 33 US — 20 — 20 International 47 79 — 126 Private — — 1 1 Bonds AAA — 28 — 28 AA — 54 — 54 A — 36 — 36 BBB 1 24 — 25 Below BBB — 10 — 10 Money market and cash and cash equivalents — 20 — 20 Total 48 300 5 353 Plan assets do not include any common shares of the Company at Dec. 31, 2022 and Dec. 31, 2021. E. Defined Benefit Obligation The present value of the obligation for the defined benefit pension and other post-employment benefit plans is as follows: Registered Supplemental Other Total Present value of defined benefit obligation as at Dec. 31, 2020 542 109 24 675 Current service cost 3 2 1 6 Interest cost 12 2 — 14 Benefits paid (54) (5) (1) (60) Curtailment (7) — — (7) Actuarial gain arising from financial assumptions (26) (7) (1) (34) Actuarial gain arising from experience adjustments (1) — — (1) Present value of defined benefit obligation as at Dec. 31, 2021 469 101 23 593 Current service cost 1 1 — 2 Interest cost 13 3 — 16 Benefits paid (57) (5) 1 (61) Actuarial gain arising from financial assumptions (83) (22) (5) (110) Actuarial loss (gain) arising from experience adjustments 1 7 (2) 6 Change in foreign exchange rates 1 — — 1 Present value of defined benefit obligation as at Dec. 31, 2022 345 85 17 447 The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2022, is 9.9 years. F. Contributions The expected employer contributions for 2023 for the defined benefit pension and other post-employment benefit plans are as follows: Registered Supplemental Other Total Expected employer contributions 1 6 2 9 G. Assumptions The significant actuarial assumptions used in measuring the Company’s defined benefit obligation for the defined benefit pension and other post-employment benefit plans are as follows: 2022 2021 As at Dec. 31 (per cent) Registered Supplemental Other Registered Supplemental Other Accrued benefit obligation Discount rate 4.7 5.0 5.0 2.8 2.8 2.7 Rate of compensation increase 2.6 3.0 — 2.9 3.0 — Assumed health-care cost trend rate Health-care cost escalation (1)(3) — — 7.1 — — 6.8 Dental-care cost escalation — — 4.2 — — 4.0 Benefit cost for the year Discount rate 2.8 2.8 2.7 2.4 2.3 2.3 Rate of compensation increase 2.9 3.0 — 2.9 3.0 — Assumed health-care cost trend rate Health-care cost escalation (2)(4) — — 6.8 — — 7.1 Dental-care cost escalation — — 4.7 — — 4.0 (1) 2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2032 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada. (2) 2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2031 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada. (3) 2021 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada. (4) 2021 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada. H. Sensitivity Analysis The following table outlines the estimated increase in the net defined benefit obligation assuming certain changes in key assumptions: Canadian plans US plans Year ended Dec. 31, 2022 Registered Supplemental Other Pension 1% decrease in the discount rate 31 10 2 2 1% increase in the salary scale 1 — — — 1% increase in the health-care cost trend rate — — 1 — 10% improvement in mortality rates 12 2 — 1

Joint Arrangements

Joint Arrangements	12 Months Ended
	Dec. 31, 2022
Disclosure of interests in other entities [Abstract]
Joint arrangements	Investments The change in investments is as follows: Skookumchuck EMG EIP Ekona Total Classification Equity-accounted Equity-accounted FVTPL FVTOCI Balance, Dec. 31, 2020 85 15 — — 100 Equity income (loss) 12 (3) — — 9 Distributions received (4) — — — (4) Balance, Dec. 31, 2021 93 12 — — 105 Investment — — 10 2 12 Equity income (loss) 10 (1) — — 9 Distributions received (5) — — — (5) Changes in foreign exchange rates 7 1 1 — 9 Net change in fair value recognized in OCI — — — (1) (1) Balance, Dec. 31, 2022 105 12 11 1 129 Equity-accounted Investments The Company’s investments in joint ventures and associates that are accounted for using the equity method consist of its investments in Skookumchuck and EMG. Skookumchuck Wind Project TransAlta holds a 49 per cent membership interest in SP Skookumchuck Investment, LLC. Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state. The project has a 20-year PPA with Puget Sound Energy. EMG International, LLC TransAlta holds a 30 per cent membership interest in EMG. During 2022, the contingent purchase price consideration of US$3.5 million was paid, which was calculated based on actual earnings metrics achieved in 2021 and did not differ from the estimated amount included in the initial purchase price. Summarized financial information on the results of operations relating to the Company’s pro-rata interests in Skookumchuck and EMG, is as follows: Year ended Dec. 31 2022 2021 2020 Results of operations Revenues and other operating income 24 19 3 Expenses (15) (10) (2) Proportionate share of net earnings 9 9 1 Other Investments Energy Impact Partners On May 6, 2022, the Company entered into a commitment to invest US$25 million over the next four years in Energy Impact Partners ("EIP") Deep Decarbonization Frontier Fund 1 (the “Frontier Fund”). The investment in the Frontier Fund provides the Company with a portfolio approach to investing in emerging technologies and the opportunity to identify, pilot, commercialize and bring to market emerging technologies that will facilitate the transition to net-zero emissions. During 2022, the Company invested $10 million (US$8 million). The investment is accounted for at FVTPL. Ekona Power Inc. On Feb. 1, 2022, the Company made an equity investment of $2 million in Ekona's Class B Preferred Shares. The investment will help support the commercialization of Ekona’s novel methane pyrolysis technology platform, which produces cleaner and lower-cost turquoise hydrogen. The Company has irrevocably elected to measure its investment in Ekona at FVTOCI. Joint arrangements at Dec. 31, 2022, included the following: Joint operations Segment Ownership (per cent) Description Sheerness Gas 50 Dual-fuel facility in Alberta, of which TA Cogen has a 50 per cent interest, operated by Heartland Generation Ltd., an affiliate of Energy Capital Partners Goldfields Power Gas 50 Gas-fired facility in Australia operated by TransAlta Fort Saskatchewan Gas 60 Cogeneration facility in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta Fortescue River Gas Pipeline Gas 43 Natural gas pipeline in Western Australia, operated by DBP Development Group McBride Lake Wind and Solar 50 Wind generation facility in Alberta operated by TransAlta Soderglen Wind and Solar 50 Wind generation facility in Alberta operated by TransAlta Pingston Hydro 50 Hydro facility in British Columbia operated by TransAlta Joint venture Segment Ownership (per cent) Description Skookumchuck Wind and Solar 49 Wind generation facility in Washington operated by Southern Power

Cash Flow Information

Cash Flow Information	12 Months Ended
	Dec. 31, 2022
Disclosure of cash flow statement [Abstract]
Cash Flow Information	Cash Flow Information A. Change in Non-Cash Operating Working Capital Year ended Dec. 31 2022 2021 2020 (Use) source: Accounts receivable (869) (28) (79) Prepaid expenses — 9 2 Income taxes receivable (61) — (4) Inventory 6 42 6 Accounts payable, accrued liabilities and provisions 548 153 160 Income taxes payable 60 (2) 4 Change in non-cash operating working capital (316) 174 89 B. Changes in Liabilities from Financing Activities Balance Dec. 31, 2021 Cash issuances (1) Repayments and dividends paid (2) New leases Dividends declared Foreign exchange impact Other Balance Dec. 31, 2022 Long-term debt and lease liabilities 3,267 981 (630) 40 — 39 (28) 3,669 Exchangeable securities 735 — — — — — 4 739 Dividends payable (common and preferred) 62 — (97) — 103 — — 68 Total liabilities from 4,064 981 (727) 40 103 39 (24) 4,476 (1) Includes $449 million net increase in borrowings under credit facilities and an increase in issuance of long-term debt of $532 million. (2) Includes a decrease of $621 million related to the repayment of long-term debt and a decrease in finance lease obligations of $9 million. Balance Dec. 31, 2020 Cash issuances (1) Repayments and dividends paid (2) New leases Dividends declared Foreign exchange impact Other Balance Dec. 31, 2021 Long-term debt and lease liabilities 3,361 173 (214) 1 — (39) (15) 3,267 Exchangeable securities 730 — — — — — 5 735 Dividends payable (common and preferred) 59 — (87) — 90 — — 62 Total liabilities from financing activities 4,150 173 (301) 1 90 (39) (10) 4,064 (1) Includes an increase in issuance of long-term debt of $173 million. (2) Includes a net decrease of $114 million in borrowings under credit facilities, a decrease of $92 million related to the repayment of long-term debt and a decrease in finance lease obligations of $8 million.

Capital

Capital	12 Months Ended
	Dec. 31, 2022
Disclosure of notes and other explanatory information [Abstract]
Capital	Capital TransAlta’s capital is comprised of the following: As at Dec. 31 2022 2021 Increase/ Long-term debt (1) 3,653 3,267 386 Exchangeable securities 739 735 4 Bank overdraft 16 — 16 Equity Common shares 2,863 2,901 (38) Preferred shares 942 942 — Contributed surplus 41 46 (5) Deficit (2,514) (2,453) (61) Accumulated other comprehensive income (loss) (222) 146 (368) Non-controlling interests 879 1,011 (132) Less: available cash and cash equivalents (1,134) (947) (187) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (17) (17) — Less: fair value asset of hedging instruments on long-term debt (4) (3) (2) (1) Total capital 5,243 5,629 (386) (1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt. (2) The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed internally and evaluated by management using a net debt position. In this regard, these funds may be available and used to facilitate repayment of debt. (3) The Company includes the principal portion of restricted cash on TransAlta OCP bonds as this cash is restricted specifically to repay outstanding debt. (4) The Company includes the fair value of economic and designated hedging instruments on debt in an asset, or liability, position as a reduction, or increase, in the calculation of capital, as the carrying value of the related debt has either increased, or decreased, due to changes in foreign exchange rates. The Company’s overall capital management strategy and its objectives in managing capital are as follows: A. Maintain a Strong Financial Position The Company operates in a long-cycle and capital-intensive commodity business and it is therefore a priority to maintain a strong financial position that enables the Company to access capital markets at reasonable interest rates. Maintaining a strong balance sheet also allows our commercial team to contract the Company’s portfolio with a variety of counterparties on terms and prices that are favourable to the Company’s financial results and provides the Company with better access to capital markets through commodity and credit cycles. The Company has an investment grade credit rating from DBRS Morningstar ("DBRS") (stable outlook). In 2022, Moody's reaffirmed the Company's Long Term Rating of Ba1 with a stable outlook. DBRS reaffirmed the Company's issuer rating and Unsecured Debt/Medium-Term Notes rating of BBB (low) and the Company's Preferred Shares rating of Pfd-3 (low), all with stable outlook. In addition, S&P Global Ratings reaffirmed the Company's Senior Unsecured Debt rating and Issuer Credit Rating of BB+ with stable outlook. The Company remains focused on maintaining a strong financial position and cash flow coverage ratios. Credit ratings provide information relating to the Company's financing costs, liquidity and operations and affect the Company's ability to obtain short-term and long-term financing and/or the cost of such financing. Management routinely monitors forecasted net earnings, cash flows, capital expenditures and scheduled repayment of debt with a goal of meeting the above ratio targets and to meet dividend and PP&E expenditure requirements. B. Liquidity For the years ended Dec. 31, 2022 and 2021, cash inflows and outflows are summarized below. The Company manages variations in working capital using existing liquidity under credit facilities to ensure sufficient cash and credit are available to fund operations, pay dividends, distribute payments to subsidiaries' non-controlling interests and invest in PP&E. Year ended Dec. 31 2022 2021 Increase Cash flow from operating activities 877 1,001 (124) Change in non-cash working capital 316 (174) 490 Cash flow from operations before changes in working capital 1,193 827 366 Dividends paid on common shares (54) (48) (6) Dividends paid on preferred shares (43) (39) (4) Distributions paid to subsidiaries’ non-controlling interests (187) (156) (31) Property, plant and equipment expenditures (918) (480) (438) Inflow (outflow) (9) 104 (113) TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2022, $1.0 billion (2021 – $1.3 billion) of the Company’s credit facilities were fully available. From time to time, TransAlta accesses capital markets, as required, to help fund some of these periodic net cash outflows to maintain its available liquidity and maintain its capital structure and credit metrics within targeted ranges.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
Related Party [Abstract]
Related Party Transactions	Related-Party Transactions Details of the Company’s principal operating subsidiaries at Dec. 31, 2022, are as follows: Subsidiary Country Ownership Principal activity TransAlta Generation Partnership Canada 100 Generation and sale of electricity TransAlta Cogeneration, L.P. Canada 50.01 Generation and sale of electricity TransAlta Centralia Generation, LLC US 100 Generation and sale of electricity TransAlta Energy Marketing Corp. Canada 100 Energy marketing TransAlta Energy Marketing (U.S.), Inc. US 100 Energy marketing TransAlta Energy (Australia), Pty Ltd. Australia 100 Generation and sale of electricity TransAlta Renewables Inc. Canada 60.1 Generation and sale of electricity Associate or joint venture Country Ownership Principal activity SP Skookumchuck Investment, LLC US 49 Generation and sale of electricity EMG International, LLC US 30 Wastewater treatment and biogas fuel to generate electricity Transactions between the Company and its subsidiaries have been eliminated on consolidation and are not disclosed. Associates and joint ventures have been equity accounted for by the Company. A. Transactions with Key Management Personnel TransAlta’s key management personnel include the President and Chief Executive Officer ("CEO") and members of the senior management team that report directly to the President and CEO and the members of the Board. Key management personnel compensation is as follows: Year ended Dec. 31 2022 2021 2020 Total compensation 23 30 27 Comprised of: Short-term employee benefits 11 14 12 Post-employment benefits 1 1 2 Share-based payments 11 15 13 B. TransAlta Renewables Acquisitions North Carolina Solar On Nov. 5, 2021, TransAlta completed the sale of a 100 per cent economic interest in the 122 MW portfolio of solar facilities in North Carolina for US$102 million. Pursuant to the transaction, a TransAlta subsidiary owns the North Carolina Solar facility directly and another subsidiary issued tracking preferred shares to TransAlta Renewables reflecting the economic interest in the facilities. Ada and Skookumchuck On April 1, 2021, the Company completed the sale of its 100 per cent economic interest in the 29 MW Ada cogeneration facility and its 49 per cent economic interest in the 137 MW Skookumchuck wind facility to TransAlta Renewables for $43 million and $103 million, respectively. Pursuant to the transaction, a TransAlta subsidiary owns Ada and Skookumchuck directly and another subsidiary issued tracking preferred shares to TransAlta Renewables reflecting the economic interest in the facilities. Big Level and Antrim During 2021, TransAlta Renewables subscribed for additional tracking preferred shares in Big Level and Antrim for $7 million (US$6 million). In addition, TransAlta Renewables repaid a portion of the total outstanding promissory notes to the Company related to the Big Level and Antrim wind facilities in the amount of $18 million (US$14 million). Windrise Wind On Feb. 26, 2021, TransAlta completed the sale of its 100 per cent direct interest in the 206 MW Windrise wind facility to TransAlta Renewables, for $213 million. WindCharger On Aug. 1, 2020, the WindCharger battery storage project was sold to TransAlta Renewables for $12 million. C. Repayment of the TransAlta Energy (Australia) ("TEA") loan On Oct. 23, 2022, the outstanding intercompany loan balance of AU$157 million, plus all accrued and unpaid interest, between TransAlta Renewables and TEA was fully repaid. The funds repaid will be reserved within TEA and restricted to fund future growth in Australia that TransAlta Renewables has elected to participate in, including the Northern Goldfields Solar and Battery project and the Mount Keith 132kV expansion project. D. Transactions with Associates In connection with the exchangeable securities issued to Brookfield, the investment agreement entitles Brookfield to nominate two directors to the TransAlta Board. This allows Brookfield to participate in the financial and operating policy decisions of the Company, and as such, they are considered associates of the Company. In addition to the exchangeable securities disclosed in Note 26, the Company may, in the normal course of operations, enter into transactions on market terms with related parties that have been measured at exchange value and recognized in the consolidated financial statements, including power purchase and sale agreements, derivative contracts and asset management fees. Transactions and balances between the Company and associates do not eliminate. Transactions with Brookfield include the following: Year ended Dec. 31 2022 2021 2020 Power sales 127 27 10 Purchased power 12 3 3 Asset management fees paid 2 2 1

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
Disclosure of other provisions, contingent liabilities and contingent assets [Abstract]
Commitments and Contingencies	Commitments and Contingencies In addition to commitments disclosed elsewhere in the financial statements, the Company has incurred the following additional contractual commitments, either directly or through its interests in joint operations. Approximate future payments under these agreements are as follows: 2023 2024 2025 2026 2027 2028 and thereafter Total Natural gas, transportation and other contracts 56 47 45 45 46 457 696 Transmission 10 7 7 3 1 39 67 Coal supply agreements 83 87 71 — — — 241 Long-term service agreements 51 49 35 32 21 140 328 Operating leases 3 3 3 2 2 29 42 Growth 446 — — — — — 446 TransAlta Energy Transition Bill 6 — — — — — 6 Total 655 193 161 82 70 665 1,826 Commitments A. Natural Gas, Transportation and Other Contracts The Company has fixed price or volume natural gas purchase and transportation contracts. Included in these contracts are 15-year natural gas transportation agreements for a total of 400 terajoules ("TJ") per day on a firm basis to 2036 and an eight-year natural gas transportation agreement for 75 TJ per day related to the Sheerness facility that is expected to end in 2030. B. Transmission The Company has several agreements to purchase transmission network capacity in Canada and the Pacific Northwest. Provided certain conditions for delivering the service are met, the Company is committed to the transmission at the supplier’s tariff rate whether it is awarded immediately, or delivered in the future, after additional facilities are constructed. C. Coal Supply Agreements Various coal supply and associated rail transport contracts are in place to provide coal for use in production at the Centralia thermal facility. The coal supply agreements allow TransAlta to take delivery of coal at fixed volumes with dates extending to 2025. D. Long-Term Service Agreements TransAlta has various service agreements in place, primarily for inspections, repairs and maintenance that may be required on natural gas facilities, equipment for gas and turbines at various wind facilities. E. Operating Leases Operating leases include lease commitments not recognized under IFRS 16 and lease commitments that have not yet commenced, mainly related to buildings, vehicles and land. F. Growth Commitments for growth relate to the following projects: Horizon Hill wind project, White Rock wind projects, Garden Plain wind project, Northern Goldfields Solar project and the Mount Keith 132kV expansion. The current estimate of the capital expenditures related to the Kent Hills rehabilitation is approximately $120 million, inclusive of insurance proceeds. Refer to Note 19 for amounts spent in 2022. G. TransAlta Energy Transition Bill Commitments As part of the TransAlta Energy Transition Bill signed into law in the State of Washington and the subsequent Memorandum of Agreement ("MOA"), the Company has committed to fund US$55 million in total over the remaining life of the Centralia coal plant to support economic and community development, promote energy efficiency and develop energy technologies related to the improvement of the environment. The MOA contains certain provisions for termination and in the event of the termination and certain circumstances, this funding or portion thereof would no longer be required. As of Dec. 31, 2022, the Company has funded approximately US$50 million of the commitment, which is recognized in other assets in the Consolidated Statements of Financial Position. Contingencies TransAlta is occasionally named as a party in various claims and legal and regulatory proceedings that arise during the normal course of its business. TransAlta reviews each of these claims, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in the Company’s favour or that such claims may not have a material adverse effect on TransAlta. Inquiries from regulatory bodies may also arise in the normal course of business, to which the Company responds as required. The Company conducts internal reviews of its offers and offer behaviour in both the energy and ancillary services markets in Alberta on an ongoing basis and will self-report suspected contraventions or respond to inquiries from regulatory agencies as required. There currently is no certainty that any particular matter will be resolved in the Company’s favour or that such matters may not have a material adverse effect on TransAlta. I. Brazeau Facility - Claim against the Government of Alberta On Sept. 9, 2022, the Company filed a Statement of Claim against the Government of Alberta in the Alberta Court of King’s Bench seeking a declaration that: (i) granting mineral leases within five kilometres of the Brazeau facility is a breach of a 1960 agreement between the Company and the Government of Alberta; and (ii) the Government of Alberta is required to indemnify the Company for any costs or damages that result from the risks of hydraulic fracturing near the Brazeau facility. On Sept. 29, 2022, the Government of Alberta filed its Statement of Defence, which asserts, among other things, that the Company: (i) is trying to usurp the jurisdiction of the Alberta Energy Regulator ("AER"); and (ii) is out of time under the Limitations Act (Alberta). The trial is scheduled to take place during the first quarter of 2024. II. Brazeau Facility - Well License Applications to Consider Hydraulic Fracturing The AER issued a subsurface order on May 27, 2019 that does not permit any hydraulic fracturing within three kilometres of the Brazeau facility but permits fracking in all formations (except the Duvernay) from three-to-five kilometres of the Brazeau facility. Subsequently, two oil and gas operators submitted applications to the AER for approval of 10 well licences (which include hydraulic fracturing activities) within three-to-five kilometres of the Brazeau facility. The regulatory hearing to consider the applications - Proceeding 379 - is currently scheduled to be heard between Feb. 27 and March 10, 2023. The Company's position is that hydraulic fracturing activities within any formation within five kilometres of the Brazeau Facility pose an unacceptable risk and that the applications should be denied. III. Hydro PPA - Emission Performance Credits Balancing Pool is claiming entitlement to the Emission Performance Credits ("EPCs") earned by the Alberta Hydro facilities as a result of those facilities being opted into the Carbon Competitiveness Incentive Regulation and Technology Innovation and Emissions Reduction Regulation from 2018 to 2020, inclusive. The Balancing Pool claims ownership of the EPCs because it believes the change-in-law provisions under the Hydro Power Purchase Arrangement require the EPCs to be passed through to the Balancing Pool. TransAlta has not received any benefit from the EPCs nor from any purported change-in-law and believes that the Balancing Pool has no rights to these credits. An arbitration has commenced and the hearing was scheduled for Feb. 6 to 10, 2023. However, due to the resignation of one of the panel members, the hearing has been adjourned. A new panel member has been appointed and a two-week hearing will be held from May 18 to June 1, 2023. TransAlta holds approximately 1,750,000 EPCs with no recorded book value that were created between 2018 and 2020, which are at risk as a result of the Balancing Pool's claim. IV. Sundance A Decommissioning TransAlta filed an application with the Alberta Utilities Commission ("AUC") seeking payment from the Balancing Pool for TransAlta’s decommissioning costs for Sundance A, including its proportionate share of the Highvale mine. The Balancing Pool and Utilities Consumer Advocate are participating as interveners because they take issue with the decommissioning costs claimed by TransAlta. Due to various factors, including the COVID-19 pandemic and significant information requests from the Balancing Pool, the application has been delayed. While a hearing date has not been set, the application will likely be heard in the second half of 2023.

Segments Disclosures

Segments Disclosures	12 Months Ended
	Dec. 31, 2022
Disclosure of operating segments [abstract]
Segments Disclosures	Segment Disclosures A. Description of Reportable Segments The Company has six reportable segments as described in Note 1. The following tables provides each segment's results in the format that the TransAlta’s President and Chief Executive Officer (the chief operating decision maker) ("CODM"), review the Company's segments to make operating decisions and assess performance. The CODM assesses the performance of the operating segments based on a measure of adjusted EBITDA. This measurement basis represents earnings before income taxes, adjusted for the effects of: depreciation of property, plant and equipment and amortization of intangibles, depreciation of right‐of‐use assets, finance lease income, unrealized mark-to-market gains or losses, gains and losses related to closed positions effectively settled by offsetting positions with exchanges recorded in the year the positions are settled, unrealized foreign exchange gains or losses on commodity transactions, depreciation on our mining equipment included in fuel and purchased power, interest income recorded on the prepaid funds, write-down of coal inventory and parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities, going off-coal which resulted in the remaining coal supply payments on the existing coal supply agreement being recognized as an onerous contract, impairment charges, share of (profit) loss of joint venture and other costs or income adjustments. The tables below show the reconciliation of the total segmented results and adjusted EBITDA to the statement of earnings (loss) reported under IFRS. Prior periods have been adjusted for comparable purposes. For internal reporting purpose, the earnings information from the Company's investment in Skookumchuck has been presented in the Wind and Solar segment on a proportionate basis. Information on a proportionate basis reflects the Company's share of Skookumchuck's statement of earnings on a line-by-line basis. Proportionate financial information is not and is not intended to be, presented in accordance with IFRS. Under IFRS, the investment in Skookumchuck has been accounted for as a joint venture using the equity method. B. Reported Adjusted Segment Earnings (Loss) and Segment Assets I. Reconciliation of Adjusted EBITDA to Earnings before Income Tax Year ended Dec. 31, 2022 Hydro Wind & Solar (1) Gas Energy Transition Energy Corporate Total Equity accounted investments (1) Reclass adjustments IFRS financials Revenues 606 303 1,209 714 160 (2) 2,990 (14) — 2,976 Reclassifications and adjustments: Unrealized mark-to-market 1 104 251 10 12 — 378 — (378) — Realized (gain) loss on — — (4) — 47 — 43 — (43) — Decrease in finance lease — — 46 — — — 46 — (46) — Finance lease income — — 19 — — — 19 — (19) — Unrealized foreign exchange — — — — (1) — (1) — 1 — Adjusted revenues 607 407 1,521 724 218 (2) 3,475 (14) (485) 2,976 Fuel and purchased power 22 31 641 566 — 3 1,263 — — 1,263 Reclassifications and adjustments: Australian interest income — — (4) — — — (4) — 4 — Adjusted fuel and purchased 22 31 637 566 — 3 1,259 — 4 1,263 Carbon compliance — 1 83 (1) — (5) 78 — — 78 Gross margin 585 375 801 159 218 — 2,138 (14) (489) 1,635 OM&A 55 68 195 69 35 101 523 (2) — 521 Taxes, other than income 3 12 15 4 — 1 35 (2) — 33 Net other operating (income) — (23) (38) — — — (61) 3 — (58) Insurance recovery — 7 — — — — 7 — (7) — Adjusted net other operating — (16) (38) — — — (54) 3 (7) (58) Adjusted EBITDA (2) 527 311 629 86 183 (102) 1,634 Equity income 9 Finance lease income 19 Depreciation and amortization (599) Asset impairment charges (9) Net interest expense (262) Foreign exchange gain 4 Gain on sale of assets and other 52 Earnings before income taxes 353 (1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment. (2) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Year ended Dec. 31, 2021 Hydro Wind & Solar (1) Gas Energy Transition Energy Corporate Total Equity accounted investments (1) Reclass adjustments IFRS financials Revenues 383 323 1,109 709 211 4 2,739 (18) — 2,721 Reclassifications and adjustments: Unrealized mark-to-market — 25 (40) 19 (38) — (34) — 34 — Realized (gain) loss on closed exchange positions (2) — — (6) — 29 — 23 — (23) — Decrease in finance lease — — 41 — — — 41 — (41) — Finance lease income — — 25 — — — 25 — (25) — Unrealized foreign exchange — — (3) — — — (3) — 3 — Adjusted revenues 383 348 1,126 728 202 4 2,791 (18) (52) 2,721 Fuel and purchased power 16 17 457 560 — 4 1,054 — — 1,054 Reclassifications and adjustments: Australian interest income — — (4) — — — (4) — 4 — Mine depreciation — — (79) (111) — — (190) — 190 — Coal inventory write-down — — — (17) — — (17) — 17 — Adjusted fuel and purchased 16 17 374 432 — 4 843 — 211 1,054 Carbon compliance — — 118 60 — — 178 — — 178 Gross margin 367 331 634 236 202 — 1,770 (18) (263) 1,489 OM&A 42 59 175 117 36 84 513 (2) — 511 Reclassifications and adjustments: Parts and materials — — (2) (26) — — (28) — 28 — Curtailment gain — — — 6 — — 6 — (6) — Adjusted OM&A 42 59 173 97 36 84 491 (2) 22 511 Taxes, other than income 3 10 13 6 — 1 33 (1) — 32 Net other operating loss — — (40) 48 — — 8 — — 8 Reclassifications and adjustments: Royalty onerous contract and — — — (48) — — (48) — 48 — Adjusted net other operating — — (40) — — — (40) — 48 8 Adjusted EBITDA (3) 322 262 488 133 166 (85) 1,286 Equity income 9 Finance lease income 25 Depreciation and amortization (529) Asset impairment charges (648) Net interest expense (245) Foreign exchange gain 16 Gain on sale of assets and 54 Loss before income taxes (380) (1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment. (2) In 2022, our adjusted EBITDA composition was adjusted to include the impact of closed positions that are effectively settled by offsetting positions with the same counterparty to reflect the performance of the assets and the Energy Marketing segment in the period in which the transactions occur. (3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Year ended Dec. 31, 2020 Hydro Wind & Solar (1) Gas Energy Transition Energy Corporate Total Equity accounted investments (1) Reclass adjustments IFRS financials Revenues 152 332 787 704 122 7 2,104 (3) — 2,101 Reclassifications and adjustments: Unrealized mark-to-market — 2 33 (14) 21 — 42 — (42) — Realized gain on closed exchange positions (2) — — — — (10) — (10) — 10 — Decrease in finance lease — — 17 — — — 17 — (17) — Finance lease income — — 7 — — — 7 — (7) — Unrealized foreign — — 4 — — — 4 — (4) — Adjusted revenues 152 334 848 690 133 7 2,164 (3) (60) 2,101 Fuel and purchased power 8 25 325 435 — 12 805 — — 805 Reclassifications and adjustments: Australian interest income — — (4) — — — (4) — 4 — Mine depreciation — — (100) (46) — — (146) — 146 — Coal inventory write-down — — — (37) — — (37) — 37 — Adjusted fuel and purchased power 8 25 221 352 — 12 618 — 187 805 Carbon compliance — — 120 48 — (5) 163 — — 163 Gross margin 144 309 507 290 133 — 1,383 (3) (247) 1,133 OM&A 37 53 166 106 30 80 472 — — 472 Taxes, other than income 2 8 13 9 — 1 33 — — 33 Net other operating income — — (11) — — — (11) — — (11) Reclassifications and adjustments: Impact of Sheerness going — — (28) — — — (28) — 28 — Adjusted net other operating — — (39) — — — (39) — 28 (11) Adjusted EBITDA (3) 105 248 367 175 103 (81) 917 Equity income 1 Finance lease income 7 Depreciation and (654) Asset impairment charges (84) Net interest expense (238) Foreign exchange gain 17 Gain on sale of assets and 9 Loss before income taxes (303) (1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment. (2) In 2022, our adjusted EBITDA composition was adjusted to include the impact of closed positions that are effectively settled by offsetting positions with the same counterparty to reflect the performance of the assets and the Energy Marketing segment in the period in which the transactions occur. (3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. II. Selected Consolidated Statements of Financial Position Information As at Dec. 31, 2022 Hydro Wind Gas Energy Transition Energy Corporate Total PP&E 437 2,837 1,858 313 — 111 5,556 Right-of-use assets 6 98 6 2 — 14 126 Intangible assets 2 157 49 5 8 31 252 Goodwill 258 176 — — 30 — 464 As at Dec. 31, 2021 Hydro Wind Gas Energy Transition Energy Corporate Total PP&E 466 2,304 2,036 481 — 33 5,320 Right-of-use assets 5 64 7 1 — 18 95 Intangible assets 3 147 56 9 5 36 256 Goodwill 258 175 — — 30 — 463 III. Selected Consolidated Statements of Cash Flows Information Additions to non-current assets are as follows: Year ended Dec. 31, 2022 Hydro Wind Gas Energy Transition Energy Corporate Total Additions to non-current assets: PP&E 36 745 43 19 — 75 918 Intangible assets — 19 — — 3 9 31 Year ended Dec. 31, 2021 Hydro Wind Gas Energy Transition Energy Corporate Total Additions to non-current assets: PP&E 29 166 167 90 — 28 480 Intangible assets — — — 1 — 8 9 Year ended Dec. 31, 2020 Hydro Wind Gas Energy Transition Energy Corporate Total Additions to non-current assets: PP&E 22 174 199 78 — 13 486 Intangible assets — — — 1 — 13 14 IV. Depreciation and Amortization on the Consolidated Statements of Cash Flows The reconciliation between depreciation and amortization reported on the Consolidated Statements of Earnings (Loss) and the Consolidated Statements of Cash Flows is presented below: Year ended Dec. 31 2022 2021 2020 Depreciation and amortization expense on the Consolidated Statements of 599 529 654 Depreciation included in fuel and purchased power (Note 6) — 190 144 Depreciation and amortization on the Consolidated Statements of Cash Flows 599 719 798 C. Geographic Information I. Revenues Year ended Dec. 31 2022 2021 2020 Canada 1,905 1,854 1,227 US 940 731 716 Australia 131 136 158 Total revenue 2,976 2,721 2,101 II. Non-Current Assets Property, plant and Right-of-use assets Intangible assets Other assets As at Dec. 31 2022 2021 2022 2021 2022 2021 2022 2021 Canada 3,817 4,051 49 52 123 141 62 15 US 1,307 860 74 39 101 85 34 61 Australia 432 409 3 4 28 30 64 66 Total 5,556 5,320 126 95 252 256 160 142 D. Significant Customer For the year ended Dec. 31, 2022, sales to the AESO represented 60 per cent of the Company’s total revenue (2021 – sales to the AESO represented 35 per cent of the Company’s total revenue). There were no other companies that accounted for more than 10 per cent of the Company's total revenue.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2022
Disclosure of events after reporting period [Abstract]
Subsequent Events	Subsequent EventsEarly-Stage Pumped Hydro Development ProjectOn Feb. 16, 2023, the Company announced that it had entered into a definitive agreement to acquire a 50 per cent interest in the Tent Mountain Renewable Energy Complex (“Tent Mountain”), an early-stage 320 MW pumped hydro energy storage development project, located in southwest Alberta, currently owned by Montem Resources Limited (“Montem”). The acquisition includes the land rights, fixed assets and intellectual property associated with the pumped hydro development project. The Company will pay Montem approximately $8 million upon closing the transaction with additional payments of up to $17 million (approximately $25 million total) contingent on the achievement of specific development and commercial milestones. The Company and Montem will form a partnership and jointly manage the project, with the Company acting as project developer. The acquisition also includes the intellectual property associated with a 100 MW offsite green hydrogen electrolyser and a 100 MW offsite wind development project. The closing of the transaction remains subject to customary closing conditions, including receipt by Montem of shareholder approval, with closing expected to occur in March 2023.

Material Accounting Policies (P

Material Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Basis of Preparation	Basis of Preparation These consolidated financial statements have been prepared by management in compliance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The consolidated financial statements have been prepared on a historical cost basis except for financial instruments, which are measured at fair value, as explained in the following accounting policies. These consolidated financial statements were authorized for issue by TransAlta's Board of Directors (the "Board") on Feb. 22, 2023.
Basis of Consolidation	Basis of Consolidation The consolidated financial statements include the accounts of the Company and the subsidiaries that it controls. Control exists when the Company is exposed, or has rights, to variable returns from its involvement with the subsidiary and has the ability to affect the returns through its power over the subsidiary. The financial statements of the subsidiaries are prepared for the same reporting period and apply consistent accounting policies as the parent company.
Revenue Recognition	venue Recognition I. Revenue from Contracts with Customers The majority of the Company’s revenues from contracts with customers are derived from the sale of generation capacity, electricity, thermal energy, environmental attributes and byproducts of power generation. The Company evaluates whether the contracts it enters into meet the definition of a contract with a customer at the inception of the contract and on an ongoing basis if there is an indication of significant changes in facts and circumstances. Contract modifications are accounted for as separate contracts when the consideration for the additional promised goods reflects a stand-alone selling price. Otherwise, contract modifications are accounted for as part of the existing contract. If the additional goods are not considered distinct the transaction price can be affected and adjustments to previously recognized revenue can occur. If the additional goods are distinct, the existing and modified contracts are treated together as a new contract, with impacts reflected prospectively from the modification date. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the goods or services are transferred to the customer. For certain contracts, revenue may be recognized at the invoiced amount, as permitted using the invoice practical expedient, if such amount corresponds directly with the Company’s performance to date. The Company excludes amounts collected on behalf of third parties from revenue. Performance Obligations Each promised good or service is accounted for separately as a performance obligation if it is distinct. The Company’s contracts may contain more than one performance obligation. Transaction Price The Company allocates the transaction price in the contract to each performance obligation. Transaction price allocated to performance obligations may include variable consideration. Variable consideration is included in the transaction price for each performance obligation when it is highly probable that a significant reversal of the cumulative variable revenue will not occur. Variable consideration that has previously been constrained is assessed at each reporting period to determine whether the constraint is lifted. The consideration contained in some of the Company's contracts with customers is primarily variable and may include both variability in quantity and pricing, such as: revenues can be dependent upon future production volumes that are driven by customer or market demand or by the operational ability of the plant; revenues can be dependent upon the variable cost of producing the energy; revenues can be dependent upon market prices; and revenues can be subject to various indices and escalators. When multiple performance obligations are present in a contract, the transaction price is allocated to each performance obligation in an amount that depicts the consideration the Company expects to be entitled to in exchange for transferring the good or service. The Company estimates the amount of the transaction price to allocate to individual performance obligations based on their relative stand-alone selling prices, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions. Recognition The nature, timing of recognition of satisfied performance obligations and payment terms for the Company’s goods and services are described below: Good or service Description Capacity Capacity refers to the availability of an asset to deliver goods or services. Customers typically pay for capacity for each defined time period (e.g., monthly) in an amount representative of the availability of the asset for the defined time period. Obligations to deliver capacity are satisfied over time and revenue is recognized using a time-based measure. Contracts for capacity are typically long term in nature. Payments are typically received from customers on a monthly basis. Contract power The sale of contract power refers to the delivery of units of electricity to a customer under the terms of a contract. Customers pay a contractually specified price for the output at the end of predefined contractual periods (e.g., monthly). Obligations to deliver electricity are satisfied over time and revenue is recognized using a units-based output measure (i.e., megawatt hours). Contracts for power are typically long term in nature and payments are typically received on a monthly basis. Thermal energy Thermal energy refers to the delivery of units of steam to a customer under the terms of a contract. Customers pay a contractually specified price for the output at the end of predefined contractual periods (e.g., monthly). Obligations to deliver steam are satisfied over time and revenue is recognized using a units-based output measure (i.e., gigajoules). Contracts for thermal energy are typically long term in nature. Payments are typically received from customers on a monthly basis. Environmental attributes Environmental attributes refers to the delivery of renewable energy certificates, green attributes and other similar items. Customers may contract for environmental attributes in conjunction with the purchase of power, in which case the customer pays for the attributes in the month subsequent to the delivery of the power. Alternatively, customers pay upon delivery of the environmental attributes. Obligations to deliver environmental attributes are satisfied at a point in time, generally upon delivery of the item. Generation byproducts Generation byproducts refers to the sale of byproducts from the use of coal in the Company’s US coal operations and the sale of coal to third parties. O bligations to deliver byproducts are satisfied at a point in time, generally upon delivery of the item. Payments are received upon satisfaction of delivery of the byproducts. A contract liability is recorded when the Company receives consideration before the performance obligations have been satisfied. A contract asset is recorded when the Company has rights to consideration for the completion of a performance obligation before it has invoiced the customer. The Company recognizes unconditional rights to consideration separately as a receivable. Contract assets and receivables are evaluated at each reporting period to determine whether there is any objective evidence that they are impaired. II. Revenue from Other Sources Merchant Revenue Revenues from non-contracted capacity (i.e., merchant) comprise energy payments, at market price, for each MWh produced and are recognized upon delivery. Lease Revenue In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Revenues associated with non-lease elements are recognized as goods or services revenues as outlined above. Where the terms and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income. Where the Company retains the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including contingent rents where applicable, is recognized over the term of the contract. Revenue from Derivatives Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales contracts, futures contracts and options, which are used to earn revenues and to gain market information. The Company also enters into contracts for differences and Virtual Power Purchase Agreements ("VPPA"). Contracts for differences are financial contracts whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh. A VPPA is whereby the Company receives the difference between the fixed contract price per MWh and the settled market price. These arrangements are option-based derivatives and judgment is applied to determine if the contract meets the "own use" exemption or if derivative treatment is required.
Financial Instruments and Hedges	Financial Instruments and Hedges I. Financial Instruments Classification and Measurement IFRS 9 introduced the requirement to classify and measure financial assets based on their contractual cash flow characteristics and the Company’s business model for the financial asset. All financial assets and financial liabilities, including derivatives, are recognized at fair value on the Consolidated Statements of Financial Position when the Company becomes party to the contractual provisions of a financial instrument or non-financial derivative contract. Financial assets must be classified and measured at either amortized cost, at fair value through profit or loss (“FVTPL”), or at fair value through other comprehensive income (loss) (“FVTOCI”). Financial assets with contractual cash flows arising on specified dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows, are subsequently measured at amortized cost. Financial assets measured at FVTOCI are those that have contractual cash flows, arising on specific dates, consisting solely of principal and interest and that are held within a business model whose objective is to collect the contractual cash flows and to sell the financial asset and investments in equity instruments. All other financial assets are subsequently measured at FVTPL. Financial liabilities are classified as FVTPL when the financial liability is held for trading. All other financial liabilities are subsequently measured at amortized cost. Funds received under tax equity investment arrangements are classified as long-term debt. These arrangements are used in the US where project investors acquire an equity investment in the project entity and in return for their investment, are allocated substantially all of the earnings, cash flows and tax benefits (such as production tax credits, investment tax credits, accelerated tax depreciation, as applicable) until they have achieved the agreed upon target rate of return. Once achieved, the arrangements flip, with the Company then receiving the majority of earnings, cash flows and tax benefits. At that time, the tax equity financings will be classified as a non-controlling interest. In applying the effective interest method to tax equity financings, the Company has made an accounting policy choice to recognize the impacts of the tax attributes in net interest expense. The Company enters into a variety of derivative financial instruments to manage its exposure to commodity price risk, interest rate risk and foreign currency exchange risk, including fixed price financial swaps, long-term physical power sale contracts, foreign exchange forward contracts and designating foreign currency debt as a hedge of net investments in foreign operations. Derivatives are initially recognized at fair value at the date the derivative contracts are entered into and are subsequently remeasured to their fair value at the end of each reporting period. The resulting gain or loss is recognized in net earnings immediately, unless the derivative is designated and effective as a hedging instrument, in which case the timing of the recognition in net earnings is dependent on the nature of the hedging relationship. Derivatives embedded in non-derivative host contracts that are not financial assets within the scope of IFRS 9 (e.g., financial liabilities) are treated as separate derivatives when they meet the definition of a derivative, their risks and characteristics are not closely related to those of the host contracts and the host contracts are not measured at FVTPL. Derivatives embedded in hybrid contracts that contain financial asset hosts within the scope of IFRS 9 are not separated and the entire contract is measured at either FVTPL or amortized cost, as appropriate. Financial assets are derecognized when the contractual rights to receive cash flows expire. Financial liabilities are derecognized when the obligation is discharged, cancelled or expired. Financial assets are also derecognized when the Company has transferred its rights to receive cash flows from the asset or has assumed an obligation to pay the received cash flows to a third party under a "pass-through" arrangement and either transferred substantially all the risks and rewards of the asset, or transferred control of the asset. TransAlta will continue to recognize the asset and any associated liability if TransAlta retains substantially all of the risks and rewards of the asset, or retains control of the asset. Continuing involvement that takes the form of a guarantee over the transferred asset is measured at the lower of the original carrying amount of the asset and the maximum amount of consideration that TransAlta could be required to repay. Financial assets and financial liabilities are offset and the net amount is reported in the Consolidated Statements of Financial Position if there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis or to realize the assets and settle the liabilities simultaneously. Transaction costs are expensed as incurred for financial instruments classified or designated as FVTPL. For other financial instruments, such as debt instruments, transaction costs are recognized as part of the carrying amount of the financial instrument. The Company uses the effective interest method of amortization for any transaction costs or fees, premiums or discounts earned or incurred for financial instruments measured at amortized cost. Impairment of Financial Assets TransAlta recognizes an allowance for expected credit losses for financial assets measured at amortized cost as well as certain other instruments. The loss allowance for a financial asset is measured at an amount equal to the lifetime expected credit loss if its credit risk has increased significantly since initial recognition or if the financial asset is a purchased or originated credit-impaired financial asset. If the credit risk on a financial asset has not increased significantly since initial recognition, its loss allowance is measured at an amount equal to the 12-month expected credit loss. For trade receivables, lease receivables and contract assets recognized under IFRS 15, TransAlta applies a simplified approach for measuring the loss allowance. Therefore, the Company does not track changes in credit risk but instead recognizes a loss allowance at an amount equal to the lifetime expected credit losses at each reporting date. The assessment of the expected credit loss is based on historical data and adjusted by forward-looking information. Forward-looking information utilized includes third-party default rates over time, dependent on credit ratings. II. Hedges Where hedge accounting can be applied and the Company chooses to seek hedge accounting treatment, a hedge relationship is designated as a fair value hedge, a cash flow hedge or a hedge of foreign currency exposures of a net investment in a foreign operation. A relationship qualifies for hedge accounting if, at inception, it is formally designated and documented as a hedge and the hedging instrument and the hedged item have values that generally move in opposite direction because of the hedged risk. The documentation includes identification of the hedging instrument and hedged item or transaction, the nature of the risk being hedged, the Company’s risk management objectives and strategy for undertaking the hedge and how hedge effectiveness will be assessed. The process of hedge accounting includes linking derivatives to specific recognized assets and liabilities or to specific firm commitments or highly probable anticipated transactions. The Company formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives used are highly effective in offsetting changes in fair values or cash flows of hedged items. If hedge criteria are not met or the Company does not apply hedge accounting, the derivative is recognized at fair value on the Consolidated Statements of Financial Position, with subsequent changes in fair value recorded in net earnings in the period of change. Fair Value Hedges In a fair value hedging relationship, the carrying amount of the hedged item is adjusted for changes in fair value attributable to the hedged risk, with the changes being recognized in net earnings. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging derivative, which is also recorded in net earnings. For fair value hedges relating to items carried at amortized cost, any adjustment to carrying value is amortized through profit or loss over the remaining term of the hedge using the effective interest rate ("EIR") method. The EIR amortization may begin as soon as an adjustment exists and no later than when the hedged item ceases to be adjusted for changes in its fair value attributable to the risk being hedged. If the hedged item is derecognized, the unamortized fair value is recognized immediately in profit or loss. Cash Flow Hedges In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in other comprehensive income (loss) ("OCI") while any ineffective portion is recognized in net earnings. The cash flow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item. If cash flow hedge accounting is discontinued, the amounts previously recognized in accumulated other comprehensive income (loss) ("AOCI") must remain in AOCI if the hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately reclassified to net earnings as a reclassification adjustment. After discontinuation, once the hedged cash flow occurs, any amount remaining in AOCI must be accounted for depending on the nature of the underlying transaction. Hedges of Foreign Currency Exposures of a Net Investment in a Foreign Operation In hedging of a foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instrument is recognized in OCI and the ineffective portion is recognized in net earnings. The related fair values are recorded in risk management assets or liabilities, as appropriate. The amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in the hedged net investment as a result of a disposal, partial disposal or loss of control.
Cash and Cash Equivalents	Cash and Cash EquivalentsCash and cash equivalents comprises cash and highly liquid investments with original maturities of three months or less.
Inventory	Inventory I. Fuel The Company’s inventory balance is composed of coal and natural gas used as fuel, which is measured at the lower of weighted average cost and net realizable value. The cost of natural gas and purchased coal inventory includes all applicable expenditures and charges incurred in bringing the inventory to its existing condition and location. II. Energy Marketing Commodity inventories held in the Energy Marketing segment for trading purposes are measured at fair value less costs to sell. Changes in fair value less costs to sell are recognized in net earnings in the period of change. III. Parts, Materials and Supplies Parts, materials and supplies are recorded at the lower of cost and measured at moving average costs and net realizable value. IV. Emission Credits and Allowances Emission credits and allowances are recorded as inventory at cost. Those purchased for use by the Company are recorded at cost and are carried at the lower of weighted average cost and net realizable value. For emission credits that are not ordinarily interchangeable, the Company records the credits using the specific identification method. Credits granted to, or internally generated by, TransAlta are recorded at nil. Emission liabilities are recorded using the best estimate of the amount required by the Company to settle its obligation in excess of government-established caps and targets. To the extent compliance costs are recoverable under the terms of contracts with third parties, the amounts are recognized as revenue in the period of recovery. Emission credits and allowances that are held for trading and that meet the definition of a derivative are accounted for using the fair value method of accounting. Emission credits and allowances that do not satisfy the criteria of a derivative are accounted for using the accrual method.
Property, Plant and Equipment	Property, Plant and Equipment The Company’s investment in property, plant and equipment (“PP&E”) is initially measured at the original cost of each component at the time of construction, purchase or acquisition. A component is a tangible portion of an asset that can be separately identified and depreciated over its own expected useful life and is expected to provide a benefit for a period in excess of one year. Original cost includes items such as materials, labour, borrowing costs and other directly attributable costs, including the initial estimate of the cost of decommissioning and restoration. Costs are recognized as PP&E if it is probable that future economic benefits will be realized and the cost of the item can be measured reliably. The cost of major spare parts is capitalized and classified as PP&E, as these items can only be used in connection with an item of PP&E. Planned maintenance is performed at regular intervals. Planned major maintenance includes inspection, repair and maintenance of existing components and the replacement of existing components. Costs incurred for planned major maintenance activities are capitalized in the period maintenance activities occur and are amortized on a straight-line basis over the term until the next major maintenance event. Expenditures incurred for the replacement of components during major maintenance are capitalized and amortized over the estimated useful life of such components. The cost of routine repairs and maintenance and the replacement of minor parts is charged to net earnings as incurred. Subsequent to initial recognition and measurement at cost, all classes of PP&E continue to be measured using the cost model and are reported at cost less accumulated depreciation and impairment losses, if any. An item of PP&E or a component is derecognized upon disposal or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition is included in net earnings when the asset is derecognized. The estimate of the useful life of each component of PP&E is based on current facts and past experience and takes into consideration existing long-term sales agreements and contracts, current and forecasted demand and the potential for technological obsolescence. The useful life is used to estimate the rate at which the component of PP&E is depreciated. PP&E assets are subject to depreciation when the asset is considered to be available for use, which is typically upon commencement of commercial operations. Insurance spares that are designated as critical for uninterrupted operation in a particular facility are depreciated over the life of that facility, even if the item is not in service. Capital spares begin to be depreciated when the item is put into service. Each significant component of an item of PP&E is depreciated to its residual value over its estimated useful life, generally using straight-line or unit-of-production methods. Estimated useful lives, residual values and depreciation methods are reviewed annually and are subject to revision based on new or additional information. The effect of a change in useful life, residual value or depreciation method is accounted for prospectively. Estimated remaining useful lives of the components of depreciable assets, categorized by asset class, are as follows: Hydro generation 2-50 years Wind and Solar generation 2-30 years Gas generation 2-35 years Energy Transition 1-10 years Capital spares and other 2-50 years TransAlta capitalizes borrowing costs on capital invested in projects under construction. Upon commencement of commercial operations, capitalized borrowing costs, as a portion of the total cost of the asset, are depreciated over the estimated useful life of the related asset.
Intangible Assets	Intangible Assets Intangible assets acquired in a business combination are recognized separately from goodwill at their fair value at the date of acquisition. Intangible assets acquired separately are recognized at cost. Internally generated intangible assets arising from development projects are recognized when certain criteria related to the feasibility of internal use or sale and probable future economic benefits of the intangible asset, are demonstrated. Intangible assets are initially recognized at cost, which is comprised of all directly attributable costs necessary to create, produce and prepare the intangible asset to be capable of operating in the manner intended by management. Subsequent to initial recognition, intangible assets continue to be measured using the cost model and are reported at cost less accumulated amortization and impairment losses, if any. Amortization is included in depreciation and amortization in the Consolidated Statements of Earnings (Loss). Amortization commences when the intangible asset is available for use and is computed on a straight-line basis over the intangible asset’s estimated useful life. Estimated useful lives of intangible assets may be determined, for example, with reference to the term of the related contract or licence agreement. The estimated useful lives and amortization methods are reviewed annually with the effect of any changes being accounted for prospectively. Intangible assets consist of power sale contracts with fixed prices higher than market prices at the date of acquisition, software and intangibles under development. Estimated remaining useful lives of intangible assets are as follows: Software 1-7 years Power sale contracts 1-18 years
Impairment of Tangible and Intangible Assets Excluding Goodwill	Impairment of Tangible and Intangible Assets Excluding Goodwill At the end of each reporting period, the Company assesses whether there is any indication that PP&E and finite life intangible assets are impaired. Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected operating results; significant changes in the manner in which an asset is used, or in the Company’s overall business strategy; or significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations where the Company is not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.
Goodwill	Goodwill Goodwill arising in a business combination is recognized as an asset at the date control is acquired. Goodwill is measured as the cost of an acquisition plus the amount of any non-controlling interest in the acquiree (if applicable) less the fair value of the related identifiable assets acquired and liabilities assumed. Goodwill is not subject to amortization, but is tested for impairment at least annually, or more frequently, if an analysis of events and circumstances indicates that a possible impairment may exist. These events could include a significant change in financial position of the CGUs or groups of CGUs to which the goodwill relates or significant negative industry or economic trends. For impairment purposes, goodwill is allocated to each of the Company’s CGUs or groups of CGUs that are expected to benefit from the synergies of the business combination in which the goodwill arose. Accordingly, the Company performs its test for impairment, where the recoverable amount of the CGUs or groups of CGUs to which the goodwill relates is compared to its carrying amount for each operating segment. If the recoverable amount is less than the carrying amount, an impairment charge is recognized in net earnings immediately, by first reducing the carrying amount of the goodwill and then by reducing the carrying amount of the other assets in the unit. An impairment charge recognized for goodwill is not reversed in subsequent periods.
Income Taxes	Income TaxesThe Company uses the liability method of accounting for income taxes. Under the liability method, deferred income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and their respective income tax basis (temporary differences). A deferred income tax asset may also be recognized for the benefit expected from unused tax credits and losses available for carryforward, to the extent that it is probable that future taxable earnings will be available against which the tax credits and losses can be applied. Deferred income tax assets and liabilities are measured based on income tax rates and tax laws that are enacted or substantively enacted by the end of the reporting period and that are expected to apply in the years in which temporary differences are expected to be realized or settled. Deferred income tax is charged or credited to net earnings, except when related to items charged or credited to either OCI or directly to equity. The carrying amount of deferred income tax assets is evaluated at the end of each reporting period and is reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be realized. Unrecognized deferred tax assets are re-assessed at each reporting date and are recognised to the extent that it has become probable that future taxable income will allow the deferred income tax asset to be recovered.Deferred income tax liabilities are recognized for taxable temporary differences arising on investments in subsidiaries, except where the Company is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.
Employee Future Benefits	Employee Future Benefits The Company has defined benefit pension and other post-employment benefit plans. The current service cost of providing benefits under the defined benefit plans is determined using the projected unit credit method prorated based on service. The net interest cost is determined by applying the discount rate to the net defined benefit liability. The discount rate used to determine the present value of the defined benefit obligation and the net interest cost, is determined by reference to market yields at the end of the reporting period on high-quality corporate bonds with terms and currencies that match the estimated terms and currencies of the benefit obligations. Remeasurements, which include actuarial gains and losses and the return on plan assets (excluding net interest), are recognized through OCI in the period in which they occur. Actuarial gains and losses arise from experience adjustments and changes in actuarial assumptions. Remeasurements are not reclassified to profit or loss, from OCI, in subsequent periods. Gains or losses arising from either a curtailment or settlement of a defined benefit plan are recognized when the curtailment or settlement occurs. When the restructuring of a benefit plan gives rise to a curtailment and a settlement of obligations, the curtailment is accounted for prior to the settlement. In determining whether statutory minimum funding requirements of the Company’s defined benefit pension plans give rise to recording an additional liability, letters of credit provided by the Company as security are considered to alleviate the funding requirements. No additional liability results in these circumstances. Contributions payable under defined contribution pension plans are recognized as a liability and an expense in the period in which the services are rendered.
Provisions	Provisions Provisions are recognized when the Company has a present obligation (legal or constructive) as a result of a past event, it is probable that the Company will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. A legal obligation can arise through a contract, legislation or other operation of law. A constructive obligation arises from an entity’s actions whereby through an established pattern of past practice, published policies or a sufficiently specific current statement, the entity has indicated it will accept certain responsibilities and has thus created a valid expectation that it will discharge those responsibilities. The amount recognized as a provision is the best estimate, remeasured at each period-end, of the expenditures required to settle the present obligation, considering the risks and uncertainties associated with the obligation. Where expenditures are expected to be incurred in the future, the obligation is measured at its present value using a current market-based, risk-adjusted interest rate. The Company records a decommissioning and restoration provision for all generating facilities and mine sites for which it is legally or constructively required to remove the facilities at the end of their useful lives and restore the plant or mine sites. For some hydro facilities, the Company is required to remove the generating equipment, but is not required to remove the structures. Initial decommissioning provisions are recognized at their present value when incurred. Each reporting date, the Company determines the present value of the provision using the current discount rates that reflect the time value of money and associated risks. The Company recognizes the initial decommissioning and restoration provisions, as well as changes resulting from revisions to cost estimates and period-end revisions to the market-based, risk-adjusted discount rate, as a cost of the related PP&E (see Note 2(E)) to the extent the related PP&E asset is still in use. Where the related PP&E asset has reached the end of its useful life, changes in the decommissioning and restoration provision are recognized in net earnings. The accretion of the net present value discount is charged to net earnings each period and is included in net interest expense. Where the Company expects to receive reimbursement from a third party for a portion of future decommissioning costs, the reimbursement is recognized as a separate asset when it is virtually certain that the reimbursement will be received. Changes in other provisions resulting from revisions to estimates of expenditures required to settle the obligation or period-end revisions to the market-based, risk-adjusted discount rate are recognized in net earnings. The accretion of the net present value discount is charged to net earnings each period and is included in net interest expense.
Leases	Leases Under IFRS 16, a contract contains a lease when the customer obtains the right to control the use of an identified asset for a period of time in exchange for consideration. I. Lessee The Company enters into lease arrangements with respect to land, building and office space, vehicles and site machinery and equipment. For all contracts that meet the definition of a lease under IFRS 16 in which the Company is the lessee and which are not exempt as short-term or low-value leases, the Company: • Recognizes right-of-use assets and lease liabilities in the Consolidated Statements of Financial Position; • Recognizes depreciation of the right-of-use assets and interest expense on lease liabilities in the Consolidated Statements of Earnings (Loss); and • Recognizes the principal repayments on lease liabilities as financing activities and interest payments on lease liabilities as operating activities in the Consolidated Statements of Cash Flows. For short-term and low-value leases, the Company recognizes the lease payments as operating expenses. Variable lease payments that do not depend on an index or a rate are not included in the measurement of the lease liability and the right-of-use asset and are recognized as an expense in the period in which the event or condition that triggers the payments occurs. Right-of-use assets are initially measured at an amount equal to the lease liability and adjusted for any payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset, or to restore the underlying asset or the site on which it is located, less any lease incentives received. Lease liabilities are initially measured at the present value of the lease payments that are not paid at commencement and discounted using the Company's incremental borrowing rate or the rate implicit in the lease. The lease liability is remeasured when there is a change in future lease payments arising from a change in an index or rate, or if there is a change in the Company’s estimate or assessment of whether it will exercise an extension, termination or purchase option. A corresponding adjustment is made to the carrying amount of the right-of-use asset, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero. The lease term includes periods covered by an option to extend if the Company is reasonably certain to exercise that option and periods covered by an option to terminate if the Company is reasonably certain not to exercise that option. Right-of-use assets are depreciated over the shorter period of either the lease term or the useful life of the underlying asset. If a lease transfers ownership of the underlying asset or the cost of the right-of-use asset reflects that the Company expects to exercise the purchase option, the related right-of-use asset is depreciated over the useful life of the underlying asset. The Company has elected to apply the practical expedient that permits a lessee not to separate non-lease components and instead account for any lease and associated non-lease components as a single arrangement. II. Lessor Power Purchase Agreements ("PPAs") and other long-term contracts may contain, or may be considered, leases where the fulfillment of the arrangement is dependent on the use of a specific asset (e.g., a generating unit) and the arrangement conveys to the customer the right to control the use of that asset. Where the Company determines that the contractual provisions of a contract contain, or are, a lease and result in the customer assuming the principal risks and rewards of ownership of the asset, the arrangement is a finance lease. Assets subject to finance leases are not reflected as PP&E and the net investment in the lease, represented by the present value of the amounts due from the lessee, is recorded in the Consolidated Statements of Financial Position as a financial asset, classified as a finance lease receivable. The payments considered to be part of the leasing arrangement are apportioned between a reduction in the lease receivable and finance lease income. The finance lease income element of the payments is recognized using a method that results in a constant rate of return on the net investment in each period and is reflected in finance lease income on the Consolidated Statements of Earnings (Loss). Where the Company determines that the contractual provisions of a contract contain, or are, a lease and result in the Company retaining the principal risks and rewards of ownership of the asset, the arrangement is an operating lease. For operating leases, the asset is, or continues to be, capitalized as PP&E and depreciated over its useful life. When the Company has subleased all or a portion of an asset it is leasing and for which it remains the primary obligor under the lease, it accounts for the head lease and the sublease as two separate contracts. The sublease is classified as a finance lease by reference to the right-of-use asset arising from the head lease.
Non-Controlling Interests	Non-Controlling Interests Non-controlling interests arise from business combinations in which the Company acquires less than a 100 per cent interest. Non-controlling interests are initially measured at either fair value or at the non-controlling interest’s proportionate share of the acquiree’s identifiable net assets. The Company determines on a transaction-by-transaction basis for which the measurement method is used. Non-controlling interests also arise from other contractual arrangements between the Company and other parties, whereby the other party has acquired an equity interest in a subsidiary and the Company retains control. Subsequent to acquisition, the carrying amount of non-controlling interests is increased or decreased by the non-controlling interest’s share of subsequent changes in equity and payments to the non-controlling interest. Total comprehensive income (loss) is attributed to the non-controlling interests even if this results in the non-controlling interests having a negative balance.
Joint Arrangements	Joint Arrangements A joint arrangement is a contractual arrangement that establishes the terms by which two or more parties agree to undertake and jointly control an economic activity. The Company's joint arrangements are generally classified as two types: joint operations and joint ventures. A joint operation arises when the parties that have joint control have rights to the assets and obligations for the liabilities relating to the arrangement. Generally, each party takes a share of the output from the asset and each bears an agreed upon share of the costs incurred in respect of the joint operation. The Company reports its interests in joint operations in its consolidated financial statements using the proportionate consolidation method by recognizing its share of the assets, liabilities, revenues and expenses in respect of its interest in the joint operation. In a joint venture, the venturers do not have rights to individual assets or obligations of the venture. Rather, each venturer has rights to the net assets of the arrangement. The Company reports its interests in joint ventures using the equity method. Under the equity method, the investment is initially recognized at cost and the carrying amount is increased or decreased to recognize the Company’s share of the joint venture’s net earnings or loss after the date of acquisition. The impact of transactions between the Company and joint ventures is eliminated based on the Company’s ownership interest. Distributions received from joint ventures reduce the carrying amount of the investment. Any excess of the cost of an acquisition less the fair value of the recognized identifiable assets, liabilities and contingent liabilities of an acquired joint venture is recognized as goodwill and is included in the carrying amount of the investment and is assessed for impairment as part of the investment.
Business Combinations	Business Combinations Transactions in which the acquisition constitutes a business are accounted for using the acquisition method. Identifiable assets acquired and liabilities assumed are measured at their acquisition date fair values. A business consists of inputs and processes applied to those inputs that have the ability to contribute to the creation of outputs. Goodwill is measured as the excess of the fair value of consideration transferred less the fair value of the identifiable assets acquired and liabilities assumed. Acquisition-related costs to effect the business combination, with the exception of costs to issue debt or equity securities, are recognized in net earnings as incurred.The optional fair value concentration test is applied on a transaction-by-transaction basis to permit a simplified assessment of whether an acquired set of activities and assets are not a business. Where substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, the Company may elect to treat the acquisition as an asset acquisition and not as a business combination.
Significant Accounting Judgments and Key Sources of Estimation Uncertainty	Significant Accounting Judgments and Key Sources of Estimation Uncertainty The preparation of financial statements requires management to make judgments, estimates and assumptions that could affect the reported amounts of assets, liabilities, revenues, expenses and disclosures of contingent assets and liabilities during the period. These estimates are subject to uncertainty. Actual results could differ from those estimates due to factors such as fluctuations in interest rates, foreign exchange rates, inflation and commodity prices and changes in economic conditions, legislation and regulations. In the process of applying the Company’s accounting policies, management has to make judgments and estimates about matters that are highly uncertain at the time the estimate is made and that could significantly affect the amounts recognized in the consolidated financial statements. Different estimates with respect to key variables used in the calculations, or changes to estimates, could potentially have a material impact on the Company’s financial position or performance. The key judgments and sources of estimation uncertainty are described below: I. Impairment of PP&E and Goodwill Impairment exists when the carrying amount of an asset, CGU or group of CGUs to which goodwill relates exceeds its recoverable amount, which is the higher of its fair value less costs of disposal and its value in use. An assessment is made at each reporting date as to whether there is any indication that an impairment charge may exist or that a previously recognized impairment charge may no longer exist or may have decreased. In determining fair value less costs of disposal, information about third-party transactions for similar assets is used and if none is available, other valuation techniques, such as discounted cash flows, are used. Value in use is computed using the present value of management’s best estimates of future cash flows based on the current use and present condition of the asset. In estimating either fair value less costs of disposal or value in use using discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel consumed, capital expenditures, retirement costs and other related cash inflows and outflows over the life of the facilities, which can range from three Discount rates are determined by employing a weighted average cost of capital methodology that is based on capital structure, cost of equity and cost of debt assumptions based on comparable companies with similar risk characteristics and market data as the asset, CGU or group of CGUs subject to the test. These estimates and assumptions are susceptible to change from period to period and actual results can and often do, differ from the estimates and can have either a positive or negative impact on the estimate of the impairment charge and may be material. The impairment outcome can also be impacted by the determination of CGUs or groups of CGUs for asset and goodwill impairment testing. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets and goodwill is allocated to each CGU or group of CGUs that is expected to benefit from the synergies of the acquisition from which the goodwill arose. The allocation of goodwill is reassessed upon changes in the composition of segments, CGUs or groups of CGUs. In respect of determining CGUs, significant judgment is required to determine what constitutes independent cash flows between power plants that are connected to the same system. The Company evaluates the market design, transmission constraints and the contractual profile of each facility, as well as the Company’s own commodity price risk management plans and practices, in order to inform this determination. With regard to the allocation or reallocation of goodwill, significant judgment is required to evaluate synergies and their impacts. Minimum thresholds also exist with respect to segmentation and internal monitoring activities. The Company evaluates synergies with regard to opportunities from combined talent and technology, functional organization and future growth potential and considers its own performance measurement processes in making this determination. Information regarding significant judgments and estimates in respect of impairment during 2020 to 2022 is disclosed in Notes 7, 19 and 22. II. Leases In determining whether the Company’s contracts contain, or are, leases, management must use judgment in assessing whether the contract provides the customer with the right to substantially all of the economic benefits from the use of the asset during the lease term and whether the customer obtains the right to direct the use of the asset during the lease term. For those agreements considered to contain, or be, leases, further judgment is required to determine the lease term by assessing whether termination or extension options are reasonably certain to be exercised. Judgment is also applied in identifying in-substance fixed payments (included) and variable payments that are based on usage or performance factors (excluded) and in identifying lease and non-lease components (services that the supplier performs) of contracts and in allocating contract payments to lease and non-lease components. For leases where the Company is a lessor, judgment is required to determine if substantially all of the significant risks and rewards of ownership are transferred to the customer or remain with the Company to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant and impact how the Company classifies amounts related to the arrangement as either PP&E or as a finance lease receivable on the Consolidated Statements of Financial Position and therefore the amount of certain items of revenue and expense is dependent upon such classifications. III. Income Taxes Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of the jurisdictions in which the Company operates. The process also involves making an estimate of income taxes currently payable and income taxes expected to be payable or recoverable in future periods, referred to as deferred income taxes. Deferred income taxes result from the effects of temporary differences due to items that are treated differently for tax and accounting purposes. The tax effects of these differences are reflected in the Consolidated Statements of Financial Position as deferred income tax assets and liabilities. An assessment must also be made to determine the likelihood that the Company’s future taxable income will be sufficient to permit the recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be reduced. Management uses the Company’s long-range forecasts as a basis for evaluation of recovery of deferred income tax assets. Management must exercise judgment in its assessment of continually changing tax interpretations, regulations and legislation to ensure deferred income tax assets and liabilities are complete and fairly presented. Differing assessments and applications than the Company’s estimates could materially impact the amounts recognized for deferred income tax assets and liabilities. Information regarding the impacts of the Company’s tax policies is disclosed in Note 11. IV. Financial Instruments and Derivatives The Company’s financial instruments and derivatives are accounted for at fair value, with the initial and subsequent changes in fair value affecting earnings in the period the change occurs. The fair values of financial instruments and derivatives are classified within three levels, with Level III fair values determined using inputs for the asset or liability that are not readily observable. These fair value levels are outlined and discussed in more detail in Note 14. Some of the Company’s fair values are included in Level III because they are not traded on an active exchange or have terms that extend beyond the time period for which exchange-based quotes are available and require the use of internal valuation techniques or models to determine fair value. The determination of the fair value of these contracts and derivative instruments can be complex and relies on judgments and estimates concerning future prices, volatility and liquidity, among other factors. These fair value estimates may not necessarily be indicative of the amounts that could be realized or settled and changes in these assumptions could affect the reported fair value of financial instruments. Fair values can fluctuate significantly and can be favourable or unfavourable depending on current market conditions. Judgment is also used in determining whether a highly probable forecasted transaction designated in a cash flow hedge is expected to occur based on the Company’s estimates of pricing and production to allow the future transaction to be fulfilled. When the Company enters into contracts to buy or sell non-financial items, such as certain commodities, and the contracts can be settled net in cash, the Company must use judgment to evaluate whether such contracts were entered into and continue to be held for the purposes of the receipt or delivery of the commodity in accordance with the Company's expected purchase, sale or usage requirements (i.e., normal purchase and sale). If this assertion cannot be supported, initially at contract inception and on an ongoing basis, the contracts must be accounted for as derivatives and measured at fair value, with changes in fair value recognized in net earnings. In supporting the normal purchase and sale assertion, the Company considers the nature of the contracts, the forecasted demand and supply requirements to which the contracts relate and its past practice of net settling other similar contracts, which may taint the normal purchase and sale assertion. The Company also enters into PPAs and contracts for differences and judgment is applied to determine if the contract meets the "own use" exemption or if derivative treatment is required. V. Project Development Costs Project development costs are recognized in operating expenses until construction of a facility or acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable and that efforts will result in future value to the Company, at which time the costs incurred subsequently are included in PP&E or other assets. The appropriateness of capitalization of these costs is evaluated each reporting period and amounts capitalized for projects no longer probable of occurring or when there is uncertainty of timing of when the projects will proceed are charged to net earnings. Management is required to use judgment to determine if there is reason to believe that future costs are recoverable and that efforts will result in future value to the Company when determining the amount to be capitalized. Information regarding project development costs is disclosed in Note 23 and information on the write-off of project development costs is disclosed in Note 7. VI. Provisions for Decommissioning and Restoration Activities TransAlta recognizes provisions for decommissioning and restoration obligations as outlined in Note 2(K). Initial decommissioning provisions and subsequent changes thereto, are determined using the Company’s best estimate of the required cash expenditures, adjusted to reflect the risks and uncertainties inherent in the timing and amount of settlement. The estimated cash expenditures are present valued using a current, risk-adjusted, market-based, pre-tax discount rate. A change in estimated cash flows, market interest rates or timing could have a material impact on the carrying amount of the provision. Information regarding significant judgments and estimates made during 2020 to 2022 in respect of decommissioning and restoration provisions is disclosed in Notes 7, 19 and 24. VII. Useful Life of PP&E Each significant component of an item of PP&E is depreciated over its estimated useful life. Estimated useful lives are determined based on current facts and past experience and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological obsolescence and regulations. The useful lives of PP&E are reviewed at least annually to ensure they continue to be appropriate. Information on changes in useful lives of facilities is disclosed in Note 19. VIII. Employee Future Benefits The Company provides pension and other post-employment benefits, such as health and dental benefits, to employees. The cost of providing these benefits is dependent upon many factors, including actual plan experience and estimates and assumptions about future experience. The liability for pension and post-employment benefits and associated costs included in annual compensation expenses are impacted by estimates related to: • Employee demographics, including age, compensation levels, employment periods, the level of contributions made to the plans and earnings on plan assets; • The effects of changes to the provisions of the plans; and • Changes in key actuarial assumptions, including rates of compensation and health-care cost increases and discount rates. Due to the complexity of the valuation of pension and post-employment benefits, a change in the estimate of any one of these factors could have a material effect on the carrying amount of the liability for pension and other post-employment benefits or the related expense. These assumptions are reviewed annually to ensure they continue to be appropriate. Disclosures on employee future benefits are disclosed in Note 32. IX. Other Provisions Where necessary, the Company recognizes provisions arising from ongoing business activities, such as interpretation and application of contract terms, ongoing litigation and force majeure claims. These provisions and subsequent changes thereto, are determined using the Company’s best estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially from the amount recognized. More information is disclosed in Notes 8 and 24 with respect to other provisions. X. Revenue from Contracts with Customers Where contracts contain multiple promises for goods or services, management exercises judgment in determining whether goods or services constitute distinct goods or services or a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer. The determination of a performance obligation affects whether the transaction price is recognized at a point in time or over time. Management considers both the mechanics of the contract and the economic and operating environment of the contract in determining whether the goods or services in a contract are distinct. In determining the transaction price and estimates of variable consideration, management considers the past history of customer usage in estimating the goods and services to be provided to the customer. The Company also considers the historical production levels and operating conditions for its variable generating assets. The Company’s contracts generally outline a specific amount to be invoiced to a customer associated with each performance obligation in the contract. Where contracts do not specify amounts for individual performance obligations, the Company estimates the amount of the transaction price to allocate to individual performance obligations based on their stand-alone selling price, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions. The satisfaction of performance obligations requires management to make judgments as to when control of the underlying good or service transfers to the customer. Determining when a performance obligation is satisfied affects the timing of revenue recognition. Management considers both customer acceptance of the good or service and the impact of laws and regulations such as certification requirements, in determining when this transfer occurs. When contracts are modified, management must exercise judgment to determine, depending upon the facts and circumstances of the changes to the contract, whether the modification is accounted for as a new contract or as part of the existing contract. If it is required to be accounted for as part of the existing contract the transaction price can be affected and adjustments to previously recognized revenue can occur, or the impacts can be reflected prospectively from the modification date. Management also applies judgment in determining whether the invoice practical expedient permits recognition of revenue at the invoiced amount if that invoiced amount corresponds directly with the entity's performance to date. XI. Classification of Joint Arrangements Upon entering into a joint arrangement, the Company must classify it as either a joint operation or joint venture, and this classification affects the accounting for the joint arrangement. In making this classification, the Company exercises judgment in evaluating the terms and conditions of the arrangement to determine whether the parties have rights to the assets and obligations or rights to the net assets. Factors such as the legal structure, contractual arrangements and other facts and circumstances, such as where the purpose of the arrangement is primarily for the provision of the output to the parties and when the parties are substantially the only source of cash flows for the arrangement, must be evaluated to understand the rights of the parties to the arrangement. XII. Significant Influence Upon entering into an investment, the Company must classify it as either an investment in an associate or an investment under IFRS 9. In making this classification, the Company exercises judgment in evaluating whether the Company has significant influence over the investee. Significant influence is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control over those policies. If the Company holds 20 per cent or more of the voting rights in the investee, it is presumed that the entity has significant influence, unless it can be clearly demonstrated that this is not the case. Other factors such as representation on the Board, participation in policy-making processes, material transactions between the Company and investee, interchange of managerial personnel or providing essential technical information are considered when assessing if the Company has significant influence over an investee. XIII. Change in Estimates During the year ended Dec. 31, 2022, there were changes in estimates relating to asset useful lives and depreciation (Note 19), decommissioning and other provisions (Note 24) and defined benefit obligation (Note 27). During the year ended Dec. 31, 2021, there were changes in estimates relating to decommissioning and other provisions (Note 24) and defined benefit obligation (Note 27).

Material Accounting Policies (T

Material Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Disclosure of detailed information about property, plant and equipment	Estimated remaining useful lives of the components of depreciable assets, categorized by asset class, are as follows: Hydro generation 2-50 years Wind and Solar generation 2-30 years Gas generation 2-35 years Energy Transition 1-10 years Capital spares and other 2-50 years The Company recognized the following asset impairment charges (reversals): For year ended Dec. 31 2022 2021 2020 Segments: Hydro 21 5 2 Wind and Solar 43 12 — Gas — 5 — Energy Transition — 540 82 Corporate (2) 27 — Changes in decommissioning and restoration provisions on retired assets (1) (53) 32 — Intangible asset impairment charges - coal rights (2) — 17 — Project development costs (3) — 10 — Asset impairment charges 9 648 84 (1) Changes relate to changes in discount rates and cash flow revisions on retired assets in 2022 and cash flow revisions on retired assets in 2021. Refer to Note 24 for further details. (2) Impaired to nil in 2021, as no future coal will be extracted from this area of the mine. (3) During 2021, the Company recorded an impairment charge of $9 million in the Hydro segment for the balance of project development costs at one of our hydro facilities as there is uncertainty on timing of when the project will proceed and $1 million related to projects that are no longer proceeding. A reconciliation of the changes in the carrying amount of PP&E is as follows: Assets under Land Hydro (1) Wind and Solar (1) Gas generation Energy Transition Capital spares and other (2) Total Cost As at Dec. 31, 2020 495 96 846 2,746 3,935 4,901 379 13,398 Additions (3) 477 — — — — — 2 479 Additions from development projects 1 — — — — — — 1 Acquisitions (Note 4) — — — 146 — — — 146 Disposals (2) (1) — — (2) (74) — (79) Impairment charges (Note 7) (4) (91) — (3) (12) (2) (468) (13) (589) Revisions/additions to decommissioning and restoration costs (Note 24) — — 1 128 6 — — 135 Retirement of assets — — (4) (11) (57) (49) — (121) Change in foreign exchange rates — — — 3 (25) 2 (7) (27) Transfers (to) from assets held for sale (Note 18) (25) — — — — 31 — 6 Transfers in (out) of PP&E (5) 5 — — (4) (5) 46 — 42 Transfer of assets upon commissioning (676) 1 27 280 237 124 5 (2) As at Dec. 31, 2021 184 96 867 3,276 4,087 4,513 366 13,389 Additions (3) 891 — — — — — 6 897 Additions from development projects 17 — — — — — 12 29 Disposals — (3) — — (1) (216) — (220) Impairment (charges) reversals (Note 7) (4) 2 — (21) (43) — — — (62) Revisions/additions to decommissioning and restoration costs (Note 24) — — (15) (59) (12) 10 2 (74) Retirement of assets — — (9) (9) (12) (7) (2) (39) Change in foreign exchange rates 13 — — 45 (4) 97 2 153 Transfers to assets held for sale (Note 18) (22) — (9) — — — — (31) Transfers in (out) of PPE (5) 16 — — (22) 437 (442) (13) (24) Transfer of assets upon commissioning (138) — 27 45 35 19 6 (6) As at Dec. 31, 2022 963 93 840 3,233 4,530 3,974 379 14,012 Accumulated depreciation As at Dec. 31, 2020 — — 447 969 2,058 3,933 169 7,576 Depreciation — — 24 130 184 264 12 614 Retirement of assets — — (3) (6) (55) (48) — (112) Disposals — — — — (1) (72) — (73) Change in foreign exchange rates — — — — (8) 2 (1) (7) Transfers to assets held for sale (Note 18) — — — — — 31 — 31 Transfers from right-of-use assets — — — — — 40 — 40 As at Dec. 31, 2021 — — 468 1,093 2,178 4,150 180 8,069 Depreciation — — 21 130 308 63 16 538 Retirement of assets — — (8) (6) (10) (7) (2) (33) Disposals — — — — (1) (211) — (212) Change in foreign exchange rates — — — 11 2 89 — 102 Transfers to assets held for sale (Note 18) — — (3) — — — — (3) Transfers in (out) of PP&E (5) — — — — 335 (340) — (5) As at Dec. 31, 2022 — — 478 1,228 2,812 3,744 194 8,456 Carrying amount As at Dec. 31, 2020 495 96 399 1,777 1,877 968 210 5,822 As at Dec. 31, 2021 184 96 399 2,183 1,909 363 186 5,320 As at Dec. 31, 2022 963 93 362 2,005 1,718 230 185 5,556 (1) The renewable generation that was previously disclosed has been separated by segment. (2) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance. (3) In 2022, the Company capitalized $16 million (2021 – $14 million) of interest to PP&E in at a weighted average rate of 6.0 per cent (2021 – 6.0 per cent). (4) The 2021 impairment charges, net of reversals exclude the changes in decommissioning and restoration provisions on assets. (5) Includes transfers between PP&E classifications, net of accumulated depreciation.
Disclosure of detailed information about intangible assets	Estimated remaining useful lives of intangible assets are as follows: Software 1-7 years Power sale contracts 1-18 years

Business Acquisitions (Tables)

Business Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combinations [Abstract]
Disclosure of details of business combinations	The fair values of the identifiable assets and liabilities of the acquired entity in the business combinations as at the date of acquisition were: North Carolina Solar Assets Cash and cash equivalents 4 Accounts receivable 4 Property, plant and equipment 146 Right-of-use assets 13 Liabilities Accounts payable and accrued liabilities (4) Lease liabilities (13) Tax equity liability (20) Deferred taxes (3) Decommissioning provisions (4) Net assets acquired 123 Cash consideration 120 Working capital consideration 3 Total purchase consideration transferred 123

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of revenue from contracts with customers [Abstract]
Disclosure of disaggregation of revenue	The majority of the Company's revenues are derived from the sale of power, capacity and environmental attributes, leasing of power facilities and from asset optimization activities, which the Company disaggregates into the following groups for the purpose of determining how economic factors affect the recognition of revenue. Year ended Dec. 31, 2022 Hydro Wind and Gas Energy Transition Energy Corporate Total Revenues from contracts with customers Power and other 33 220 462 10 — — 725 Environmental attributes (1) 1 50 — — — — 51 Revenue from contracts with customers 34 270 462 10 — — 776 Revenue from leases (2) — — 32 — — — 32 Revenue from derivatives and other trading activities (3) — (87) (821) 243 160 (2) (507) Revenue from merchant sales 564 86 1,529 461 — — 2,640 Other 8 20 7 — — — 35 Total revenue 606 289 1,209 714 160 (2) 2,976 Revenues from contracts with customers Timing of revenue recognition At a point in time 1 50 — 12 — — 63 Over time 33 220 462 (2) — — 713 Total revenue from contracts with customers 34 270 462 10 — — 776 (1) The environmental attributes represent environmental attribute sales not bundled with power and other sales. (2) Total lease income from long-term contracts that meet the criteria of operating leases. (3) Represents realized and unrealized gains or losses from hedging and derivative positions. Year ended Dec. 31, 2021 Hydro Wind and Gas Energy Transition Energy Corporate Total Revenues from contracts with customers Power and other 28 207 395 24 — — 654 Environmental attributes (1) — 28 — — — — 28 Revenue from contracts with customers 28 235 395 24 — — 682 Revenue from leases (2) — — 19 — — — 19 Revenue from derivatives and other trading activities (3) — (14) (118) 138 211 4 221 Revenue from merchant sales 345 68 808 546 — — 1,767 Other 10 16 5 1 — — 32 Total revenue 383 305 1,109 709 211 4 2,721 Revenues from contracts with customers Timing of revenue recognition At a point in time — 28 2 23 — — 53 Over time 28 207 393 1 — — 629 Total revenue from contracts with customers 28 235 395 24 — — 682 (1) The environmental attributes represent environmental attribute sales not bundled with power and other sales. (2) Total lease income from long-term contracts that meet the criteria of operating leases. (3) Represents realized and unrealized gains or losses from hedging and derivative positions. Wind and Solar has been revised to present revenue classifications consistent with current period. Year ended Dec. 31, 2020 Hydro Wind and Gas Energy Transition Energy Corporate Total Revenues from contracts with customers Power and other 141 238 465 156 — — 1,000 Environmental attributes (1) — 23 — — — — 23 Revenue from contracts with customers 141 261 465 156 — — 1,023 Revenue from leases (2) — — 123 — — — 123 Revenue from derivatives and other trading activities (3) — 8 (8) 283 122 12 417 Revenue from merchant sales 3 49 200 264 — — 516 Other (4) 8 11 7 1 — (5) 22 Total revenue 152 329 787 704 122 7 2,101 Revenues from contracts with customers Timing of revenue recognition At a point in time — 25 7 26 — — 58 Over time 141 236 458 130 — — 965 Total revenue from contracts with customers 141 261 465 156 — — 1,023 (1) The environmental attributes represent environmental attribute sales not bundled with power and other sales. (2) Total lease income from certain PPAs and long-term contracts that meet the criteria of operating leases. (3) Represents realized and unrealized gains or losses from hedging and derivative positions. Wind and Solar has been revised to present revenue classifications consistent with current period. (4) Includes government incentives and other miscellaneous.

Expenses by Nature (Tables)

Expenses by Nature (Tables)	12 Months Ended
	Dec. 31, 2022
Analysis of income and expense [abstract]
Disclosure of expenses classified by nature	Fuel and purchased power and OM&A expenses classified by nature are as follows: Year ended Dec. 31 2022 2021 2020 Fuel and OM&A Fuel and OM&A Fuel and OM&A Gas fuel costs 578 — 306 — 159 — Coal fuel costs (1) 141 — 164 — 269 — Royalty, land lease, other direct costs 25 — 19 — 20 — Purchased power 514 — 339 — 163 — Mine depreciation (2) — — 190 — 144 — Salaries and benefits 5 263 36 234 50 235 Other operating expenses (3) — 258 — 277 — 237 Total 1,263 521 1,054 511 805 472 (1) Included in coal fuel costs for 2021 and 2020 was $17 million and $15 million, respectively, related to the impairment of coal inventory. (2) Included in mine depreciation for 2021 and 2020 was $48 million and $22 million, respectively, related to mine depreciation that was initially recorded in the standard cost of coal inventory and then subsequently written down during 2021.

Asset Impairment Charges (Table

Asset Impairment Charges (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of impairment of assets [Abstract]
Disclosure of detailed information about property, plant and equipment	Estimated remaining useful lives of the components of depreciable assets, categorized by asset class, are as follows: Hydro generation 2-50 years Wind and Solar generation 2-30 years Gas generation 2-35 years Energy Transition 1-10 years Capital spares and other 2-50 years The Company recognized the following asset impairment charges (reversals): For year ended Dec. 31 2022 2021 2020 Segments: Hydro 21 5 2 Wind and Solar 43 12 — Gas — 5 — Energy Transition — 540 82 Corporate (2) 27 — Changes in decommissioning and restoration provisions on retired assets (1) (53) 32 — Intangible asset impairment charges - coal rights (2) — 17 — Project development costs (3) — 10 — Asset impairment charges 9 648 84 (1) Changes relate to changes in discount rates and cash flow revisions on retired assets in 2022 and cash flow revisions on retired assets in 2021. Refer to Note 24 for further details. (2) Impaired to nil in 2021, as no future coal will be extracted from this area of the mine. (3) During 2021, the Company recorded an impairment charge of $9 million in the Hydro segment for the balance of project development costs at one of our hydro facilities as there is uncertainty on timing of when the project will proceed and $1 million related to projects that are no longer proceeding. A reconciliation of the changes in the carrying amount of PP&E is as follows: Assets under Land Hydro (1) Wind and Solar (1) Gas generation Energy Transition Capital spares and other (2) Total Cost As at Dec. 31, 2020 495 96 846 2,746 3,935 4,901 379 13,398 Additions (3) 477 — — — — — 2 479 Additions from development projects 1 — — — — — — 1 Acquisitions (Note 4) — — — 146 — — — 146 Disposals (2) (1) — — (2) (74) — (79) Impairment charges (Note 7) (4) (91) — (3) (12) (2) (468) (13) (589) Revisions/additions to decommissioning and restoration costs (Note 24) — — 1 128 6 — — 135 Retirement of assets — — (4) (11) (57) (49) — (121) Change in foreign exchange rates — — — 3 (25) 2 (7) (27) Transfers (to) from assets held for sale (Note 18) (25) — — — — 31 — 6 Transfers in (out) of PP&E (5) 5 — — (4) (5) 46 — 42 Transfer of assets upon commissioning (676) 1 27 280 237 124 5 (2) As at Dec. 31, 2021 184 96 867 3,276 4,087 4,513 366 13,389 Additions (3) 891 — — — — — 6 897 Additions from development projects 17 — — — — — 12 29 Disposals — (3) — — (1) (216) — (220) Impairment (charges) reversals (Note 7) (4) 2 — (21) (43) — — — (62) Revisions/additions to decommissioning and restoration costs (Note 24) — — (15) (59) (12) 10 2 (74) Retirement of assets — — (9) (9) (12) (7) (2) (39) Change in foreign exchange rates 13 — — 45 (4) 97 2 153 Transfers to assets held for sale (Note 18) (22) — (9) — — — — (31) Transfers in (out) of PPE (5) 16 — — (22) 437 (442) (13) (24) Transfer of assets upon commissioning (138) — 27 45 35 19 6 (6) As at Dec. 31, 2022 963 93 840 3,233 4,530 3,974 379 14,012 Accumulated depreciation As at Dec. 31, 2020 — — 447 969 2,058 3,933 169 7,576 Depreciation — — 24 130 184 264 12 614 Retirement of assets — — (3) (6) (55) (48) — (112) Disposals — — — — (1) (72) — (73) Change in foreign exchange rates — — — — (8) 2 (1) (7) Transfers to assets held for sale (Note 18) — — — — — 31 — 31 Transfers from right-of-use assets — — — — — 40 — 40 As at Dec. 31, 2021 — — 468 1,093 2,178 4,150 180 8,069 Depreciation — — 21 130 308 63 16 538 Retirement of assets — — (8) (6) (10) (7) (2) (33) Disposals — — — — (1) (211) — (212) Change in foreign exchange rates — — — 11 2 89 — 102 Transfers to assets held for sale (Note 18) — — (3) — — — — (3) Transfers in (out) of PP&E (5) — — — — 335 (340) — (5) As at Dec. 31, 2022 — — 478 1,228 2,812 3,744 194 8,456 Carrying amount As at Dec. 31, 2020 495 96 399 1,777 1,877 968 210 5,822 As at Dec. 31, 2021 184 96 399 2,183 1,909 363 186 5,320 As at Dec. 31, 2022 963 93 362 2,005 1,718 230 185 5,556 (1) The renewable generation that was previously disclosed has been separated by segment. (2) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance. (3) In 2022, the Company capitalized $16 million (2021 – $14 million) of interest to PP&E in at a weighted average rate of 6.0 per cent (2021 – 6.0 per cent). (4) The 2021 impairment charges, net of reversals exclude the changes in decommissioning and restoration provisions on assets. (5) Includes transfers between PP&E classifications, net of accumulated depreciation.
Disclosure of fair value less cost of disposal	The calculation of fair value less costs of disposal for all of the above facilities is most sensitive to the following assumptions: Location of assets Current year contract and merchant discount rates (1) Prior year contract and merchant discount rates (1) Wind and Solar Canada 6.4 and 7.1 per cent 5.0 and 5.0 per cent US 6.5 and 7.7 per cent 5.1 and 5.0 per cent Hydro Canada 5.9 and 6.4 per cent 3.6 and 4.9 per cent (1) Discount rates were related to the valuations performed for the Wind and Solar and Hydro segments in 2022. The prior year discount rates were related to the previous detailed valuation performed for the Wind and Solar segment in 2021 and for the Hydro segment in 2019.

Net Other Operating (Income) _2

Net Other Operating (Income) Loss (Tables)	12 Months Ended
	Dec. 31, 2022
Analysis of income and expense [abstract]
Disclosure of components of net other operating (income) Loss	Net other operating (income) loss includes the following: Year ended Dec. 31 2022 2021 2020 Alberta Off-Coal Agreement (40) (40) (40) Liquidated damages recoverable (12) — — Insurance recoveries (7) — — Supplier and other contract settlements 5 34 — Onerous contract provisions — 14 29 Retail power contract amortization (Note 27) (4) — — Net other operating (income) loss (58) 8 (11)

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2022
Interests In Other Entities [Abstract]
Disclosure of investments in joint ventures and associates	The change in investments is as follows: Skookumchuck EMG EIP Ekona Total Classification Equity-accounted Equity-accounted FVTPL FVTOCI Balance, Dec. 31, 2020 85 15 — — 100 Equity income (loss) 12 (3) — — 9 Distributions received (4) — — — (4) Balance, Dec. 31, 2021 93 12 — — 105 Investment — — 10 2 12 Equity income (loss) 10 (1) — — 9 Distributions received (5) — — — (5) Changes in foreign exchange rates 7 1 1 — 9 Net change in fair value recognized in OCI — — — (1) (1) Balance, Dec. 31, 2022 105 12 11 1 129 Summarized financial information on the results of operations relating to the Company’s pro-rata interests in Skookumchuck and EMG, is as follows: Year ended Dec. 31 2022 2021 2020 Results of operations Revenues and other operating income 24 19 3 Expenses (15) (10) (2) Proportionate share of net earnings 9 9 1

Net Interest Expense (Tables)

Net Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2022
Analysis of income and expense [abstract]
Disclosure of components of net interest expense	Year ended Dec. 31 2022 2021 2020 Interest on debt 164 163 158 Interest on exchangeable debentures (Note 26) 29 29 29 Interest on exchangeable preferred shares (Note 26) 28 28 5 Interest income (24) (11) (10) Capitalized interest (Note 19) (16) (14) (8) Interest on lease liabilities 7 7 8 Credit facility fees, bank charges and other interest 27 20 25 Tax shield on tax equity financing (Note 25) (1) (2) (9) 1 Accretion of provisions (Note 24) 49 32 30 Net interest expense 262 245 238 (1) The credit balance in 2021 primarily relates to the tax benefit associated with investment tax credits claimed in 2021 on the North Carolina Solar facility that was assigned to the tax equity investor. The tax equity investments are treated as debt under IFRS and the monetization of the tax attributes is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Taxes [Abstract]
Disclosure of rate reconciliations	Rate Reconciliation Year ended Dec. 31 2022 2021 2020 Earnings (loss) before income taxes 353 (380) (303) Net (earnings) loss attributable to non-controlling interests not subject to tax (94) (33) 2 Adjusted earnings (loss) before income taxes 259 (413) (301) Statutory Canadian federal and provincial income tax rate (%) 23.4 % 23.6 % 24.5 % Expected income tax expense (recovery) 61 (98) (74) Increase (decrease) in income taxes resulting from: Differences in effective foreign tax rates (1) 4 3 Non-deductible expense (1) 130 — — Taxable capital gain 18 — — Deferred income tax expense (recovery) related to temporary difference on investment in subsidiaries (2) — 9 Write-down (reversal of write-down) of unrecognized deferred income tax (24) 134 8 Statutory and other rate differences (3) 4 (7) Adjustments in respect of deferred income tax of previous years (2) 6 (4) (3) Other (2) 7 5 14 Income tax expense (recovery) 192 45 (50) Effective tax rate (%) 74 % (11 %) 17 % (1) This amount is related to current and prior period tax adjustments in the US to mitigate cash tax relating to the Base Erosion and Anti-Abuse Tax ("BEAT").
Disclosure of components of income tax expense	The components of income tax expense are as follows: Year ended Dec. 31 2022 2021 2020 Current income tax expense 65 56 35 Deferred income tax expense (recovery) related to the origination and reversal of temporary differences 153 (145) (95) Deferred income tax expense (recovery) related to temporary difference on investment in subsidiary (2) — 9 Deferred income tax recovery resulting from changes in tax rates or laws — — (7) Deferred income tax expense (recovery) arising from the unrecognized deferred income tax assets (1) (24) 134 8 Income tax expense (recovery) 192 45 (50) Year ended Dec. 31 2022 2021 2020 Current income tax expense 65 56 35 Deferred income tax expense (recovery) 127 (11) (85) Income tax expense (recovery) 192 45 (50) (1) During the year ended Dec. 31, 2022, the Company recognized deferred tax assets of $24 million (2021 – $134 million write-down, 2020 – $8 million write-down). The deferred income tax assets mainly relate to the tax benefits associated with tax losses related to the Company's directly owned US operations and other deductible differences. The Company has not recognized $361 million of deferred tax assets on the basis that it is not probable that sufficient future taxable income would be available to utilize these tax assets. The Company undertakes an analysis of the recoverability of its tax assets on an annual basis.
Disclosure of aggregate current and deferred income tax related to items charged or credited to equity	The aggregate current and deferred income tax related to items charged or credited to equity are as follows: Year ended Dec. 31 2022 2021 2020 Income tax expense (recovery) related to: Net impact related to cash flow hedges (112) (57) (23) Net impact related to hedges of foreign operations (3) — — Net impact to net actuarial gains (losses) 12 11 (3) Income tax recovery reported in equity (103) (46) (26)
Disclosure of significant components of deferred income tax assets (liabilities)	Significant components of the Company’s deferred income tax assets (liabilities) are as follows: As at Dec. 31 2022 2021 Non-capital losses (1) 244 530 Future decommissioning and restoration costs 119 183 Property, plant and equipment (553) (651) Risk management assets and liabilities, net 193 (53) Employee future benefits and compensation plans 48 53 Interest deductible in future periods — 17 Foreign exchange differences on US-denominated debt 13 16 Other deductible temporary differences (5) (5) Net deferred income tax asset, before write-down of deferred income tax assets 59 90 Unrecognized deferred income tax assets (361) (380) Net deferred income tax liability, after write-down of deferred income tax assets (302) (290) (1) Non-capital losses expire between 2033 and 2042. Net operating losses from US operations have no expiration. The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows: As at Dec. 31 2022 2021 Deferred income tax assets (1) 50 64 Deferred income tax liabilities (352) (354) Net deferred income tax liability (302) (290) (1) The deferred income tax assets presented on the Consolidated Statements of Financial Position are recoverable based on estimated future earnings and tax planning strategies. The assumptions used in the estimate of future earnings are based on the Company’s long-range forecasts.

Non-Controlling Interests (Tabl

Non-Controlling Interests (Tables)	12 Months Ended
	Dec. 31, 2022
Interests In Other Entities [Abstract]
Disclosure of share of ownership and equity participation in TransAlta Renewables	The Company’s subsidiaries and operations that have non-controlling interests are as follows: Subsidiary/Operation Non-controlling interest as at Dec. 31, 2022 TransAlta Cogeneration LP 49.99% — Canadian Power Holdings Inc. TransAlta Renewables 39.9% — Public shareholders Kent Hills Wind LP (1) 17% — Natural Forces Technologies Inc. (1) Owned by TransAlta Renewables.
Disclosure of interests in subsidiaries	The net earnings, distributions and equity attributable to non-controlling interests include the 17 per cent non-controlling interest in Kent Hills Wind LP. Year ended Dec. 31 2022 2021 2020 Revenues 560 470 436 Net earnings 74 139 97 Total comprehensive income (loss) (67) 66 223 Amounts attributable to the non-controlling interests: Net earnings 20 50 40 Total comprehensive income (loss) (36) 21 90 Distributions paid to non-controlling interests 100 100 80 As at Dec. 31 2022 2021 Current assets 240 430 Long-term assets 2,989 3,319 Current liabilities (306) (593) Long-term liabilities (1,118) (1,033) Total equity (1,805) (2,123) Equity attributable to non-controlling interests (732) (869) Non-controlling interests’ share (per cent) 39.9 39.9 B. TA Cogen Year ended Dec. 31 2022 2021 2020 Revenues 347 265 146 Net earnings (loss) 143 103 (13) Total comprehensive income (loss) 143 103 (13) Amounts attributable to the non-controlling interest: Net earnings (loss) 91 62 (6) Total comprehensive income (loss) 91 62 (6) Distributions paid to Canadian Power Holdings Inc. 87 56 17 As at Dec. 31 2022 2021 Current assets 127 66 Long-term assets 253 312 Current liabilities (62) (52) Long-term liabilities (27) (36) Total equity (291) (290) Equity attributable to Canadian Power Holdings Inc. (147) (142) Non-controlling interest share (per cent) 49.99 49.99 Details of the Company’s principal operating subsidiaries at Dec. 31, 2022, are as follows: Subsidiary Country Ownership Principal activity TransAlta Generation Partnership Canada 100 Generation and sale of electricity TransAlta Cogeneration, L.P. Canada 50.01 Generation and sale of electricity TransAlta Centralia Generation, LLC US 100 Generation and sale of electricity TransAlta Energy Marketing Corp. Canada 100 Energy marketing TransAlta Energy Marketing (U.S.), Inc. US 100 Energy marketing TransAlta Energy (Australia), Pty Ltd. Australia 100 Generation and sale of electricity TransAlta Renewables Inc. Canada 60.1 Generation and sale of electricity Associate or joint venture Country Ownership Principal activity SP Skookumchuck Investment, LLC US 49 Generation and sale of electricity EMG International, LLC US 30 Wastewater treatment and biogas fuel to generate electricity

Trade and Other Receivables (Ta

Trade and Other Receivables (Tables)	12 Months Ended
	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of trade and Other Receivables	As at Dec. 31 2022 2021 Trade accounts receivable 1,165 499 Collateral provided (Note 15) 304 55 Current portion of finance lease receivables (Note 17) 52 40 Loan receivable (Note 23) 4 55 Income taxes receivable 64 2 Trade and other receivables 1,589 651
Components of Accounts Payable	As at Dec. 31 2022 2021 Accounts payable and accrued liabilities 1,069 654 Interest payable 17 17 Collateral held (Note 15) 260 18 Accounts payable and accrued liabilities 1,346 689

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of detailed information about financial instruments [abstract]
Disclosure of financial assets	The following table outlines the carrying amounts and classifications of the financial assets and liabilities: Carrying value as at Dec. 31, 2022 Derivatives Derivatives Amortized cost Other financial assets (FVTPL) Other financial assets (FVTOCI) Total Financial assets Cash and cash equivalents (1) — — 1,134 — — 1,134 Restricted cash — — 70 — — 70 Trade and other receivables — — 1,589 — — 1,589 Long-term portion of finance lease receivables — — 129 — — 129 Long-term portion of loan receivable (2) — — 33 — — 33 Other investments — — — 11 1 12 Risk management assets Current — 709 — — — 709 Long-term — 161 — — — 161 Financial liabilities Bank overdraft — — 16 — — 16 Accounts payable and accrued liabilities — — 1,346 — — 1,346 Dividends payable — — 68 — — 68 Risk management liabilities Current 271 858 — — — 1,129 Long-term 76 257 — — — 333 Credit facilities, long-term debt and lease liabilities (3) — — 3,653 — — 3,653 Exchangeable securities — — 739 — — 739 (1) Includes cash equivalents of nil. (2) Included in other assets. Refer to Note 23. (3) Includes current portion. Carrying value as at Dec. 31, 2021 Derivatives Derivatives Amortized cost Total Financial assets Cash and cash equivalents (1) — — 947 947 Restricted cash — — 70 70 Trade and other receivables — — 651 651 Long-term portion of finance lease receivables — — 185 185 Risk management assets Current 36 272 — 308 Long-term 252 147 — 399 Financial liabilities Accounts payable and accrued liabilities — — 689 689 Dividends payable — — 62 62 Risk management liabilities Current — 261 — 261 Long-term — 145 — 145 Credit facilities, long-term debt and lease liabilities (2) — — 3,267 3,267 Exchangeable securities — — 735 735 (1) Includes cash equivalents of nil. (2) Includes current portion.
Disclosure of financial liabilities	The following table outlines the carrying amounts and classifications of the financial assets and liabilities: Carrying value as at Dec. 31, 2022 Derivatives Derivatives Amortized cost Other financial assets (FVTPL) Other financial assets (FVTOCI) Total Financial assets Cash and cash equivalents (1) — — 1,134 — — 1,134 Restricted cash — — 70 — — 70 Trade and other receivables — — 1,589 — — 1,589 Long-term portion of finance lease receivables — — 129 — — 129 Long-term portion of loan receivable (2) — — 33 — — 33 Other investments — — — 11 1 12 Risk management assets Current — 709 — — — 709 Long-term — 161 — — — 161 Financial liabilities Bank overdraft — — 16 — — 16 Accounts payable and accrued liabilities — — 1,346 — — 1,346 Dividends payable — — 68 — — 68 Risk management liabilities Current 271 858 — — — 1,129 Long-term 76 257 — — — 333 Credit facilities, long-term debt and lease liabilities (3) — — 3,653 — — 3,653 Exchangeable securities — — 739 — — 739 (1) Includes cash equivalents of nil. (2) Included in other assets. Refer to Note 23. (3) Includes current portion. Carrying value as at Dec. 31, 2021 Derivatives Derivatives Amortized cost Total Financial assets Cash and cash equivalents (1) — — 947 947 Restricted cash — — 70 70 Trade and other receivables — — 651 651 Long-term portion of finance lease receivables — — 185 185 Risk management assets Current 36 272 — 308 Long-term 252 147 — 399 Financial liabilities Accounts payable and accrued liabilities — — 689 689 Dividends payable — — 62 62 Risk management liabilities Current — 261 — 261 Long-term — 145 — 145 Credit facilities, long-term debt and lease liabilities (2) — — 3,267 3,267 Exchangeable securities — — 735 735 (1) Includes cash equivalents of nil. (2) Includes current portion.
Disclosure of reconciliation of changes in loss allowance and explanation of changes in gross carrying amount for financial instruments	The following table summarizes the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification during the years ended Dec. 31, 2022 and 2021, respectively: Year ended Dec. 31, 2022 Year ended Dec. 31, 2021 Hedge Non-hedge Total Hedge Non-hedge Total Opening balance 285 (126) 159 573 9 582 Changes attributable to: Market price changes on existing contracts (611) (298) (909) (181) 4 (177) Market price changes on new contracts — (124) (124) — (134) (134) Contracts settled (38) 118 80 (107) (5) (112) Change in foreign exchange rates 17 (5) 12 — — — Net risk management assets (liabilities) at end of year (347) (435) (782) 285 (126) 159 Additional Level III information: Losses recognized in other comprehensive loss (594) — (594) (181) — (181) Total gains (losses) included in earnings (loss) before income taxes 38 (427) (389) 107 (130) (23) Unrealized gains (losses) included in earnings (loss) before income taxes relating to net assets held at year end — (309) (309) — (135) (135)
Disclosure for sensitivity ranges for the base fair value	As at Dec. 31, 2022 Description Sensitivity Valuation technique Unobservable input Reasonably possible change Long-term power sale – US +15 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$5 or price increase of US$55 -163 Coal +14 Numerical derivative valuation Illiquid future power prices (per MWh) Price decrease of US$5 or price increase of US$55 Volatility 80% to 120% -13 Rail rate escalation zero to 10% Full requirements +3 Scenario analysis (1) Volume 96% to 104% -21 Cost of supply Decrease of $0.50 per MWh or increase of $3.30 per MWh Long-term wind +22 Long-term price forecast Illiquid future power prices (per MWh) Price decrease or increase of US$6 -18 Illiquid future REC prices (per unit) Price decrease or increase of US$2 Wind discounts 0% decrease or 5% increase Long-term wind +47 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of C$85 or increase of C$5 -25 Wind discounts 28% decrease or 5% increase Long-term wind +74 Long-term price forecast Illiquid future power prices (per MWh) Price decrease or increase of US$2 -28 Wind discounts 2% decrease or 5% increase Others +18 -19 (1) The valuation technique for Full requirements - Eastern US was updated to scenario analysis to provide a more representative description and did not result in changes to the value. As at Dec. 31, 2021 Description Sensitivity Valuation technique Unobservable input Reasonably possible change Long-term power +22 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$3 or a price increase of US$20 -145 Coal +3 Numerical derivative valuation Illiquid future power prices (per MWh) Price decrease of US$3 or a price increase of US$20 Volatility 80% to 120% -18 Rail rate escalation zero to 4% Full requirements – Eastern US +9 Historical Bootstrap Volume 95% to 105% -9 Cost of supply (+/-) US$1 per MWh Long-term wind +17 Long-term price forecast Illiquid future power prices (per MWh) Price increase or decrease of US$6 -16 Illiquid future REC prices (per unit) Price decrease US$3 or increase of US$2 Long-term wind +21 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of C$24 or increase of C$5 -11 Wind discounts 5% decrease or 5% increase Long-term wind +27 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$2 or increase of US$3 -15 Wind discounts 3% decrease or 3% increase Others +6 -6
Disclosure of fair value measurement of liabilities	The fair value of financial assets and liabilities measured at other than fair value is as follows: Fair value (1) Total carrying value (1) Level I Level II Level III Total Exchangeable securities — Dec. 31, 2022 — 685 — 685 739 Long-term debt — Dec. 31, 2022 — 3,200 — 3,200 3,518 Loan receivable — Dec. 31, 2022 — 37 — 37 37 Exchangeable securities — Dec. 31, 2021 — 770 — 770 735 Long-term debt — Dec. 31, 2021 — 3,272 — 3,272 3,167 Loan receivable — Dec. 31, 2021 — 55 — 55 55 (1) Includes current portion.
Disclosure of difference between transaction price and the fair value determined using valuation model	The difference between the transaction price and the fair value determined using a valuation model, yet to be recognized in net earnings (loss) and a reconciliation of changes is as follows: As at Dec. 31 2022 2021 2020 Unamortized net gain (loss) at beginning of year (1) (131) (33) 9 New inception loss (2) (37) (79) (13) Change in foreign exchange rates (10) — — Amortization recorded in net earnings during the year (35) (19) (29) Unamortized net loss at end of year (213) (131) (33) (1) In 2022, the day one valuation of certain PPAs in 2021 was revised for consistency with other fair value calculations. The reconciliation for the 2021 comparative period was restated. This did not impact the prior year financial statements as the inception completely offset the fair value at Dec. 31, 2021. (2) During 2022, the Company entered into a PPA for the Horizon Hill wind project (2021 – PPAs for the White Rock wind project) that resulted in a new inception loss due to the difference between the fixed PPA price and future estimated market prices. There are other key factors, such as project economics and incentives, that influence the long-term power price for renewable projects outside of the power price curve, which is not liquid for the majority of the duration of the PPA. During 2020, the Company entered into a coal rail transportation agreement that includes an upside sharing mechanism. Option pricing techniques have been utilized to value the obligation associated with this component of the deal.

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2022
Financial Instruments [Abstract]
Disclosure of derivative Financial Instruments	Net Risk Management Assets and Liabilities Aggregate net risk management assets (liabilities) are as follows: As at Dec. 31, 2022 Cash flow Not Total Commodity risk management Current (271) (143) (414) Long-term (76) (96) (172) Net commodity risk management liabilities (347) (239) (586) Other Current — (6) (6) Long-term — — — Net other risk management liabilities — (6) (6) Total net risk management liabilities (347) (245) (592) As at Dec. 31, 2021 Cash flow Not Total Commodity risk management Current 33 12 45 Long-term 252 (4) 248 Net commodity risk management assets 285 8 293 Other Current 3 (1) 2 Long-term — 6 6 Net other risk management assets 3 5 8 Total net risk management assets 288 13 301 The Comp any’s outstanding commodity derivative instruments not designated as hedging instruments are as follows: As at Dec. 31 2022 2021 Type Notional Notional Notional Notional Electricity (MWh) 55,821 13,934 46,139 14,951 Natural gas (GJ) 23,464 162,384 7,501 173,898 Transmission (MWh) — 1,643 37 1,097 Emissions (MWh) 274 2,297 445 2,030 Emissions (tonnes) 300 300 350 350 Coal (tonnes) — 7,746 — 9,352 As at Dec. 31 2022 2021 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign exchange forward contracts – foreign-denominated receipts/expenditures AU183 CAD168 (1) 2023-2026 AU28 CAD26 (5) 2022-2025 US573 CAD761 (12) 2023-2025 US271 CAD357 8 2022-2025 US66 AU102 4 2023 — — — — Foreign exchange forward contracts – foreign-denominated debt CAD159 US120 3 2023 CAD191 US150 1 2022
Disclosure of net Arrangements	Information about the Company’s financial assets and liabilities that are subject to enforceable master netting arrangements or similar agreements is as follows: As at Dec. 31, 2022 Gross amounts of recognized financial assets (liabilities) Amounts set off Net amounts presented on the statement of financial position Master netting arrangements (1) Net amount Current risk management assets $ 1,602 $ (883) $ 688 $ (62) $ 626 Long-term risk management assets $ 204 $ (43) $ 157 $ (7) $ 150 Current risk management liabilities $ (1,953) $ 883 $ (1,033) $ 62 $ (971) Long-term risk management liabilities $ (449) $ 43 $ (402) $ 7 $ (395) Trade and other receivables (2) $ 1,330 $ (934) $ 396 $ (176) $ 220 Accounts payable and accrued liabilities (2) $ (1,344) $ 934 $ (411) $ 176 $ (235) As at Dec. 31, 2021 Gross amounts of recognized financial assets (liabilities) Amounts set off Net amounts presented on the statement of financial position Master netting arrangements (1) Net amount Current risk management assets $ 636 $ (307) $ 316 $ (92) $ 224 Long-term risk management assets $ 285 $ (16) $ 260 $ (23) $ 237 Current risk management liabilities $ (529) $ 307 $ (211) $ 92 $ (119) Long-term risk management liabilities $ (89) $ 16 $ (70) $ 23 $ (47) Trade and other receivables (2) $ 699 $ (571) $ 128 $ (35) $ 93 Accounts payable and accrued liabilities (2) $ (689) $ 571 $ (118) $ 35 $ (83) (1) Amounts not set off in the Consolidated Statements of Financial Position. (2) The trade and other receivables and accounts payable and accrued liabilities include amounts related to collateral provided and held. Refer to Note 15(F) below for further details.
Disclosure of currency Rate Risk	The possible effect on net earnings and OCI, due to changes in foreign exchange rates associated with financial instruments denominated in currencies other than the Company’s functional currency, is outlined below. The sensitivity analysis has been prepared using management’s assessment that an average three cents (2021 – three cents, 2020 – three cents) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter. Year ended Dec. 31 2022 2021 2020 Currency Net earnings decrease (1) OCI gain (1)(2) Net earnings increase (decrease) (1) OCI gain (1)(2) Net earnings decrease (1) OCI gain (1)(2) USD (12) — (13) 1 (8) 1 AUD (2) — 1 — (4) — Total (14) — (12) 1 (12) 1 (1) These calculations assume an increase in the value of these currencies relative to the Canadian dollar. A decrease would have the opposite effect. (2) The foreign exchange impact related to financial instruments designated as hedging instruments in net investment hedges has been excluded.
Disclosure of credit Risk	The following table outlines the Company’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at Dec. 31, 2022: Investment grade (Per cent) Non-investment grade (Per cent) Total (Per cent) Total Trade and other receivables (1)(2) 87 13 100 1,585 Long-term finance lease receivable 100 — 100 129 Risk management assets (1) 92 8 100 870 Loan receivable (2) — 100 100 37 Total 2,621 (1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts. (2) Includes $37 million loan receivable included within other assets with a counterparty that has no external credit rating. The current portion of $4 million was excluded from trade and other receivables as it is included in loan receivable in the table above. Refer to Note 23 for further details.
Disclosure of maturity Analysis of Financial Liabilities	A maturity analysis of the Company's financial liabilities as well as financial assets that are expected to generate cash inflows to meet cash outflows on financial liabilities, is as follows: 2023 2024 2025 2026 2027 2028 and thereafter Total Bank overdraft 16 — — — — — 16 Accounts payable and accrued liabilities 1,346 — — — — — 1,346 Long-term debt (1) Credit facilities (1) — 400 — 33 — — 433 Debentures — — — — — 251 251 Senior notes — — — — — 949 949 Non-recourse — Hydro 45 — — — — — 45 Non-recourse — Wind & Solar 63 66 69 67 70 363 698 Non-recourse — Gas 45 46 58 61 65 782 1,057 Tax equity financing 16 15 15 16 19 48 129 Other 1 — — — — — 1 Exchangeable securities (2) — — 750 — — — 750 Commodity risk management (assets) 415 182 (42) 15 8 8 586 Other risk management (assets) liabilities 7 (1) 1 — — (1) 6 Lease liabilities (3) (7) 4 4 3 4 127 135 Interest on long-term debt and lease liabilities (4) 205 192 166 158 150 836 1,707 Interest on exchangeable securities (2)(4) 52 62 — — — — 114 Dividends payable 68 — — — — — 68 Total 2,272 966 1,021 353 316 3,363 8,291 (1) Excludes impact of hedge accounting and derivatives. (2) The exchangeable securities can be exchanged, at the earliest, on Jan. 1, 2025. Refer to Note 26 for further details. (3) Lease liabilities include a lease incentive of $12 million expected to be received in 2023. The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount, timing and uncertainty of future cash flows: Maturity 2023 2024 2025 2026 2027 2028 Cash flow hedges Commodity derivative instruments Electricity Notional amount (thousands of MWh) 3,329 3,338 2,628 — — — Average price ($ per MWh) 78.27 80.22 82.22 — — —
Disclosure of hedging Instruments	The impact of the hedging instruments on the statement of financial position is as follows: As at Dec. 31, 2022 Notional amount Carrying amount Line item in the statement of financial position Change in fair value used for measuring ineffectiveness Commodity price risk Cash flow hedges Physical power sales (1) 9,295 (347) Risk management liabilities (594) Foreign currency risk Net investment hedges Foreign-denominated debt US370 CAD502 Credit facilities, long-term debt and lease liabilities — (1) In thousands of MWh. As at Dec. 31, 2021 Notional amount Carrying amount Line item in the statement of financial position Change in fair value used for measuring ineffectiveness Commodity price risk Cash flow hedges Physical power sales (1) 12,624 285 Risk management assets (181) Interest rate risk Cash flow hedges Interest rate swap US300 3 Risk management assets 3 Foreign currency risk Cash flow hedges Foreign-denominated expenditures US8 — Risk management assets — Foreign-denominated expenditures US14 — Risk management assets — Net investment hedges Foreign-denominated debt US370 CAD473 Credit facilities, long-term debt and lease liabilities — (1) In thousands of MWh. The impact of the hedged items on the statement of financial position is as follows: As at Dec. 31 2022 2021 Change in fair value used for measuring ineffectiveness Cash flow hedge reserve (1) Change in fair value used for measuring ineffectiveness Cash flow hedge reserve (1) Commodity price risk Cash flow hedges Power forecast sales – (594) (279) (181) 226 Interest rate risk Cash flow hedges Interest expense on long- — — 3 2 Change in fair value used for measuring ineffectiveness Foreign currency translation reserve (1) Change in fair value used for measuring ineffectiveness Foreign currency translation reserve (1) Foreign currency risk Net investment hedges Net investment in foreign — (39) — (35) (1 Net of tax. Included in AOCI.
Disclosure of effect of Hedges	The impact of designated cash flow hedges on OCI and net earnings is: Year ended Dec. 31, 2022 Effective portion Ineffective portion Derivatives in cash flow Pre-tax Location of (gain)loss reclassified Pre-tax Location of (gain) loss Pre-tax Commodity contracts (747) Revenue 124 Revenue — Forward starting interest rate 53 Interest expense 2 Interest expense — OCI impact (694) OCI impact 126 Net earnings impact — Year ended Dec. 31, 2021 Effective portion Ineffective portion Derivatives in cash flow Pre-tax Location of (gain) loss reclassified Pre-tax Location of (gain) loss Pre-tax Commodity contracts (268) Revenue (13) Revenue — Foreign exchange forwards — Property, plant 1 Foreign exchange — Forward starting interest rate 13 Interest expense 4 Interest expense — OCI impact (255) OCI impact (8) Net earnings impact — Year ended Dec. 31, 2020 Effective portion Ineffective portion Derivatives in cash flow Pre-tax Location of (gain) Pre-tax Location of (gain) loss reclassified Pre-tax Commodity contracts 41 Revenue (137) Revenue — Foreign exchange forwards (1) Property, plant and equipment — Foreign exchange — Forward starting interest rate (12) Interest expense (4) Interest expense — OCI impact 28 OCI impact (141) Net earnings impact —

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of inventories [Abstract]
Disclosure Of The Components Of Inventories	The components of inventory are as follows: As at Dec. 31 2022 2021 Parts, materials and supplies 83 82 Coal 43 27 Emission credits 27 55 Natural gas 4 3 Total 157 167

Finance Lease Receivables (Tabl

Finance Lease Receivables (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of maturity analysis of finance lease payments receivable [abstract]
Disclosure of maturity analysis of finance lease payments receivable	Amounts receivable under the Company’s finance leases associated with the Poplar Creek cogeneration facility and the Southern Cross Energy facilities are as follows: As at Dec. 31 2022 2021 Minimum Present value of Minimum Present value of Within one year 62 55 58 54 Second to fifth years inclusive 81 75 127 105 More than five years 60 51 80 66 203 181 265 225 Less: unearned finance lease income 22 — 40 — Total finance lease receivables 181 181 225 225 Included in the Consolidated Statements of Financial Position as: Current portion of finance lease receivables (Note 13) 52 40 Long-term portion of finance lease receivables 129 185 Total finance lease receivables 181 225

Assets Held for Sale (Tables)

Assets Held for Sale (Tables)	12 Months Ended
	Dec. 31, 2022
Assets Held for Sale [Abstract]
Disclosure of change in assets held for sale	The change in assets held for sale is as follows: 2022 2021 Balance, Jan 1 25 105 Transfers from property, plant and equipment 28 25 Disposals (31) (105) Balance, Dec. 31 22 25

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of detailed information about property, plant and equipment [abstract]
Disclosure of detailed information about property, plant and equipment	Estimated remaining useful lives of the components of depreciable assets, categorized by asset class, are as follows: Hydro generation 2-50 years Wind and Solar generation 2-30 years Gas generation 2-35 years Energy Transition 1-10 years Capital spares and other 2-50 years The Company recognized the following asset impairment charges (reversals): For year ended Dec. 31 2022 2021 2020 Segments: Hydro 21 5 2 Wind and Solar 43 12 — Gas — 5 — Energy Transition — 540 82 Corporate (2) 27 — Changes in decommissioning and restoration provisions on retired assets (1) (53) 32 — Intangible asset impairment charges - coal rights (2) — 17 — Project development costs (3) — 10 — Asset impairment charges 9 648 84 (1) Changes relate to changes in discount rates and cash flow revisions on retired assets in 2022 and cash flow revisions on retired assets in 2021. Refer to Note 24 for further details. (2) Impaired to nil in 2021, as no future coal will be extracted from this area of the mine. (3) During 2021, the Company recorded an impairment charge of $9 million in the Hydro segment for the balance of project development costs at one of our hydro facilities as there is uncertainty on timing of when the project will proceed and $1 million related to projects that are no longer proceeding. A reconciliation of the changes in the carrying amount of PP&E is as follows: Assets under Land Hydro (1) Wind and Solar (1) Gas generation Energy Transition Capital spares and other (2) Total Cost As at Dec. 31, 2020 495 96 846 2,746 3,935 4,901 379 13,398 Additions (3) 477 — — — — — 2 479 Additions from development projects 1 — — — — — — 1 Acquisitions (Note 4) — — — 146 — — — 146 Disposals (2) (1) — — (2) (74) — (79) Impairment charges (Note 7) (4) (91) — (3) (12) (2) (468) (13) (589) Revisions/additions to decommissioning and restoration costs (Note 24) — — 1 128 6 — — 135 Retirement of assets — — (4) (11) (57) (49) — (121) Change in foreign exchange rates — — — 3 (25) 2 (7) (27) Transfers (to) from assets held for sale (Note 18) (25) — — — — 31 — 6 Transfers in (out) of PP&E (5) 5 — — (4) (5) 46 — 42 Transfer of assets upon commissioning (676) 1 27 280 237 124 5 (2) As at Dec. 31, 2021 184 96 867 3,276 4,087 4,513 366 13,389 Additions (3) 891 — — — — — 6 897 Additions from development projects 17 — — — — — 12 29 Disposals — (3) — — (1) (216) — (220) Impairment (charges) reversals (Note 7) (4) 2 — (21) (43) — — — (62) Revisions/additions to decommissioning and restoration costs (Note 24) — — (15) (59) (12) 10 2 (74) Retirement of assets — — (9) (9) (12) (7) (2) (39) Change in foreign exchange rates 13 — — 45 (4) 97 2 153 Transfers to assets held for sale (Note 18) (22) — (9) — — — — (31) Transfers in (out) of PPE (5) 16 — — (22) 437 (442) (13) (24) Transfer of assets upon commissioning (138) — 27 45 35 19 6 (6) As at Dec. 31, 2022 963 93 840 3,233 4,530 3,974 379 14,012 Accumulated depreciation As at Dec. 31, 2020 — — 447 969 2,058 3,933 169 7,576 Depreciation — — 24 130 184 264 12 614 Retirement of assets — — (3) (6) (55) (48) — (112) Disposals — — — — (1) (72) — (73) Change in foreign exchange rates — — — — (8) 2 (1) (7) Transfers to assets held for sale (Note 18) — — — — — 31 — 31 Transfers from right-of-use assets — — — — — 40 — 40 As at Dec. 31, 2021 — — 468 1,093 2,178 4,150 180 8,069 Depreciation — — 21 130 308 63 16 538 Retirement of assets — — (8) (6) (10) (7) (2) (33) Disposals — — — — (1) (211) — (212) Change in foreign exchange rates — — — 11 2 89 — 102 Transfers to assets held for sale (Note 18) — — (3) — — — — (3) Transfers in (out) of PP&E (5) — — — — 335 (340) — (5) As at Dec. 31, 2022 — — 478 1,228 2,812 3,744 194 8,456 Carrying amount As at Dec. 31, 2020 495 96 399 1,777 1,877 968 210 5,822 As at Dec. 31, 2021 184 96 399 2,183 1,909 363 186 5,320 As at Dec. 31, 2022 963 93 362 2,005 1,718 230 185 5,556 (1) The renewable generation that was previously disclosed has been separated by segment. (2) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance. (3) In 2022, the Company capitalized $16 million (2021 – $14 million) of interest to PP&E in at a weighted average rate of 6.0 per cent (2021 – 6.0 per cent). (4) The 2021 impairment charges, net of reversals exclude the changes in decommissioning and restoration provisions on assets. (5) Includes transfers between PP&E classifications, net of accumulated depreciation.

Right of Use Assets (Tables)

Right of Use Assets (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of leases [Abstract]
Disclosure of quantitative information about right-of-use assets	A reconciliation of the changes in the carrying amount of the right-of-use assets is as follows: Land Buildings Vehicles Equipment Pipeline Total As at Dec. 31, 2020 58 24 1 16 42 141 Additions — 1 — — — 1 Acquisitions (Note 4) 13 — — — — 13 Depreciation (3) (5) — (2) (1) (11) Disposal of assets — — — — (41) (41) Transfers — — — (8) — (8) As at Dec. 31, 2021 68 20 1 6 — 95 Additions 36 — 1 3 — 40 Depreciation (4) (5) — (2) — (11) Change in foreign exchange 2 — — — — 2 As at Dec. 31, 2022 102 15 2 7 — 126

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of detailed information about intangible assets [abstract]
Disclosure of reconciliation of changes in intangible assets	A reconciliation of the changes in the carrying amount of intangible assets is as follows: Power Software Intangibles Coal rights Total Cost As at Dec. 31, 2020 269 412 3 149 833 Additions — — 9 — 9 Impairment charges (Note 7) — — — (17) (17) Change in foreign exchange rates — (2) — — (2) Transfers — 12 (8) — 4 As at Dec. 31, 2021 269 422 4 132 827 Additions (1) — — 31 — 31 Change in foreign exchange rates 3 3 1 — 7 Transfers — 12 (9) — 3 As at Dec. 31, 2022 272 437 27 132 868 Accumulated amortization As at Dec. 31, 2020 123 272 — 125 520 Amortization 17 27 — 7 51 As at Dec. 31, 2021 140 299 — 132 571 Amortization 17 26 — — 43 Change in foreign exchange rates 1 1 — — 2 As at Dec. 31, 2022 158 326 — 132 616 Carrying amount As at Dec. 31, 2020 146 140 3 24 313 As at Dec. 31, 2021 129 123 4 — 256 As at Dec. 31, 2022 114 111 27 — 252 Goodwill acquired through business combinations has been allocated to groups of CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments is as follows: As at Dec. 31 2022 2021 Hydro 258 258 Wind and Solar 176 175 Energy Marketing 30 30 Total goodwill 464 463

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of detailed information about goodwill [Abstract]
Disclosure of detailed information about goodwill	A reconciliation of the changes in the carrying amount of intangible assets is as follows: Power Software Intangibles Coal rights Total Cost As at Dec. 31, 2020 269 412 3 149 833 Additions — — 9 — 9 Impairment charges (Note 7) — — — (17) (17) Change in foreign exchange rates — (2) — — (2) Transfers — 12 (8) — 4 As at Dec. 31, 2021 269 422 4 132 827 Additions (1) — — 31 — 31 Change in foreign exchange rates 3 3 1 — 7 Transfers — 12 (9) — 3 As at Dec. 31, 2022 272 437 27 132 868 Accumulated amortization As at Dec. 31, 2020 123 272 — 125 520 Amortization 17 27 — 7 51 As at Dec. 31, 2021 140 299 — 132 571 Amortization 17 26 — — 43 Change in foreign exchange rates 1 1 — — 2 As at Dec. 31, 2022 158 326 — 132 616 Carrying amount As at Dec. 31, 2020 146 140 3 24 313 As at Dec. 31, 2021 129 123 4 — 256 As at Dec. 31, 2022 114 111 27 — 252 Goodwill acquired through business combinations has been allocated to groups of CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments is as follows: As at Dec. 31 2022 2021 Hydro 258 258 Wind and Solar 176 175 Energy Marketing 30 30 Total goodwill 464 463

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of financial assets [abstract]
Disclosure of components in other assets	The components of other assets are as follows: As at Dec. 31 2022 2021 Loan receivable 37 55 South Hedland prepaid transmission access and distribution costs 61 65 Long-term prepaids and other assets 56 48 Project development costs 10 29 Total Other assets 164 197 Included in the Consolidated Statements of Financial Position as: Total current other assets (Note 13) 4 55 Total long-term other assets 160 142 Total Other assets 164 197
Disclosure of change in project development costs	The change in project development costs is as follows: As at Dec. 31 2022 2021 Balance, Jan 1 29 25 Additions 29 15 Transfers to PP&E (Note 19) (29) (1) Transfers to intangible assets (Note 21) (19) — Impairment charges (Note 7) — (10) Balance, Dec. 31 10 29

Decommissioning and Other Pro_2

Decommissioning and Other Provisions (Tables)	12 Months Ended
	Dec. 31, 2022
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Disclosure of change in decommissioning and other provision balances	The change in decommissioning and other provision balances is as follows: Decommissioning and Other provisions Total Balance, Dec. 31, 2020 608 65 673 Liabilities incurred 8 22 30 Liabilities settled (18) (62) (80) Accretion 32 — 32 Acquisition of liabilities 2 — 2 Revisions in estimated cash flows 167 12 179 Revisions in discount rates (6) — (6) Reversals — (3) (3) Balance, Dec. 31, 2021 793 34 827 Liabilities incurred 1 23 24 Liabilities settled (35) (12) (47) Accretion (Note 10) 49 — 49 Disposals (5) — (5) Revisions in estimated cash flows 95 5 100 Revisions in discount rates (225) — (225) Reversals — (9) (9) Change in foreign exchange rates 15 — 15 Balance, Dec. 31, 2022 688 41 729 Included in the Consolidated Statements of Financial Position as: As at Dec. 31, 2022 2021 Current portion 70 48 Non-current portion 659 779 Total Decommissioning and other provisions 729 827

Credit Facilities, Long-Term _2

Credit Facilities, Long-Term Debt and Lease Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of borrowings outstanding	The amounts outstanding are as follows: As at Dec. 31 2022 2021 Segment Maturity Currency Carrying Face Interest (1) Carrying Face Interest Credit facilities Committed syndicated bank facility (2) Corporate 2026 CAD 32 33 4.7 % — — — % Term Facility Corporate 2024 CAD 396 400 6.5 % — — — % Debentures 7.3% Medium term notes Corporate 2029 CAD 110 110 7.3 % 110 110 7.3 % 6.9% Medium term notes Corporate 2030 CAD 141 141 6.9 % 141 141 6.9 % Senior notes (3) 7.8% Senior notes (4) Corporate 2029 USD 533 542 7.8 % — — — % 6.5% Senior notes Corporate 2040 USD 401 407 6.5 % 378 383 6.5 % 4.5% Senior notes Corporate 2022 USD — — 4.5 % 510 511 4.5 % Non-recourse Melancthon Wolfe Wind LP bond Wind & Solar 2028 CAD 202 203 3.8 % 235 237 3.8 % New Richmond Wind LP Wind & Solar 2032 CAD 112 113 4.0 % 120 121 4.0 % Kent Hills Wind LP bond Wind & Solar 2033 CAD 206 209 4.5 % 221 221 4.5 % Windrise Wind LP bond Wind & Solar 2041 CAD 170 173 3.4 % 171 173 3.4 % Pingston bond Hydro 2023 CAD 45 45 3.0 % 45 45 3.0 % TAPC Holdings LP bond (Poplar Creek) Gas 2030 CAD 94 95 8.9 % 102 104 4.4 % TEC Hedland PTY Ltd bond (5) Gas 2042 AUD 711 720 4.1 % 732 742 4.1 % TransAlta OCP LP bond Gas 2030 CAD 241 242 4.5 % 263 265 4.5 % Tax equity financing Big Level & Antrim (6) Wind & Solar 2029 USD 102 108 6.6 % 106 112 6.6 % Lakeswind (7) Wind & Solar 2024 USD 15 15 10.5 % 18 18 10.5 % North Carolina Solar (8) Wind & Solar 2028 USD 6 6 7.3 % 11 11 7.3 % Other Corporate 2023 CAD 1 1 5.9 % 4 4 5.9 % Total long-term debt 3,518 3,563 3,167 3,198 Lease liabilities 135 100 Total long-term debt and lease liabilities 3,653 3,267 Less: current portion of long-term debt (170) (837) Less: current portion of lease liabilities (8) (7) Total current long-term debt and lease liabilities (178) (844) Total non-current credit facilities, long-term debt and lease 3,475 2,423 (1) Interest rate reflects the stipulated rate or the average rate weighted by principal amounts outstanding and is before the effect of hedging. (2) Composed of bankers’ acceptances and other commercial borrowings under long-term committed credit facilities. (3) US face value at Dec. 31, 2022 — US$700 million (2021 – US$700 million). (4) The effective interest rate for the senior notes is 5.98 per cent after the effects of gains realized on settled interest rate hedging instruments. (5) AU face value at Dec. 31, 2022 — AU$786 million (2021 – AU$800 million). (6) US face value at Dec. 31, 2022 — US$79 million (2021 – US$88 million). (7) US face value at Dec. 31, 2022 — US$11 million (2021 – US$14 million). (8) US face value at Dec. 31, 2022 — US$5 million (2021 – US$9 million). The Company's credit facilities are summarized in the table below: As at Dec. 31, 2022 Facility Utilized Available Maturity Credit Facilities Outstanding letters of credit (1) Cash drawings Committed TransAlta Corporation syndicated credit facility 1,250 738 — 512 Q2 2026 TransAlta Renewables syndicated credit facility 700 — 33 667 Q2 2026 TransAlta Corporation bilateral credit facilities 240 219 — 21 Q2 2024 TransAlta Corporation Term Facility 400 — 400 — Q3 2024 Total Committed 2,590 957 433 1,200 Non-Committed TransAlta Corporation demand facilities 250 120 — 130 n/a TransAlta Renewables demand facility 150 98 — 52 n/a Total Non-Committed 400 218 — 182 (1) TransAlta has obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase obligations. Letters of credit drawn against the non-committed facilities reduce the available capacity under the committed syndicated credit facilities. At Dec. 31, 2022, TransAlta provided cash collateral of $304 million.
Disclosure of principal repayments	2023 2024 2025 2026 2027 2028 and thereafter Total Principal repayments (1) 170 527 142 177 154 2,393 3,563 Lease liabilities (2) (7) 4 4 3 4 127 135 (1) Excludes impact of hedge accounting and derivatives. (2) Lease liabilities include a lease incentive of $12 million, expected to be received in 2023.

Exchangeable Securities (Tables

Exchangeable Securities (Tables)	12 Months Ended
	Dec. 31, 2022
Exchangeable Securities [Abstract]
Disclosure of borrowing costs	Exchangeable Securities As at Dec. 31, 2022 Dec. 31, 2021 Carrying value Face value Interest Carrying value Face value Interest Exchangeable debentures – due May 1, 2039 (1) 339 350 7 % 335 350 7 % Exchangeable preferred shares (2) 400 400 7 % 400 400 7 % Total exchangeable securities 739 750 735 750 (1) On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for seven per cent unsecured subordinated debentures due May 1, 2039. (2) On Oct. 30, 2020, Brookfield invested the second tranche of $400 million in exchange for redeemable, retractable first preferred shares (Series 1). Exchangeable preferred share dividends are reported as interest expense.
Disclosure of sensitivity analysis of fair value measurement to changes in unobservable inputs, liabilities	As at Dec. 31, 2022 Dec. 31, 2021 Description Base fair value Sensitivity Base fair value Sensitivity Option to exchange – embedded derivative — +nil -25 — +nil -32

Defined Benefit Obligation an_2

Defined Benefit Obligation and Other Long-Term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of components of defined benefit obligations and other long-term liabilities	The components of defined benefit obligation and other long-term liabilities are as follows: As at Dec. 31 2022 2021 Defined benefit obligation (Note 32) 150 228 Long-term incentive accruals (Note 31) 8 4 Retail power contract liability 126 — Other 10 21 Total 294 253

Common Shares (Tables)

Common Shares (Tables)	12 Months Ended
	Dec. 31, 2022
Share Capital, Reserves And Other Equity Interest [Abstract]
Disclosure of issued and outstanding	TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value. As at Dec. 31 2022 2021 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 271.0 2,901 269.8 2,896 Purchased and cancelled under the NCIB (4.3) (46) — — Effects of share-based payment plans 0.9 5 — (3) Stock options exercised 0.5 3 1.2 8 Issued and outstanding, end of year 268.1 2,863 271.0 2,901 The following are the effects of the Company's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2022 2021 Total shares purchased (1) 4,342,300 — Average purchase price per share 12.48 — Total cost (millions) 54 — Weighted average book value of shares cancelled 46 — Amount recorded in deficit (8) — (1) As at Dec. 31, 2022, includes 164,300 (2021 – nil) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. The Company paid $52 million in 2022 and the remaining amount was paid subsequent to the year end. All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares. As at Dec. 31 2022 2021 Series (1) Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 9.6 235 Series B 2.4 58 2.4 58 Series C 10.0 243 11.0 269 Series D 1.0 26 — — Series E 9.0 219 9.0 219 Series G 6.6 161 6.6 161 Issued and outstanding, end of year 38.6 942 38.6 942 (1) Series 1 Preferred Shares are accounted for as long-term debt. Refer to Note 26.
Disclosure of earnings per share	Year ended Dec. 31 2022 2021 2020 Net earnings (loss) attributable to common shareholders 4 (576) (336) Basic and diluted weighted average number of common shares outstanding 271 271 275 Net earnings (loss) per share attributable to common shareholders, basic and diluted 0.01 (2.13) (1.22)

Preferred Shares (Tables)

Preferred Shares (Tables)	12 Months Ended
	Dec. 31, 2022
Share Capital, Reserves And Other Equity Interest [Abstract]
Disclosure of issued and outstanding	TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value. As at Dec. 31 2022 2021 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 271.0 2,901 269.8 2,896 Purchased and cancelled under the NCIB (4.3) (46) — — Effects of share-based payment plans 0.9 5 — (3) Stock options exercised 0.5 3 1.2 8 Issued and outstanding, end of year 268.1 2,863 271.0 2,901 The following are the effects of the Company's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2022 2021 Total shares purchased (1) 4,342,300 — Average purchase price per share 12.48 — Total cost (millions) 54 — Weighted average book value of shares cancelled 46 — Amount recorded in deficit (8) — (1) As at Dec. 31, 2022, includes 164,300 (2021 – nil) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. The Company paid $52 million in 2022 and the remaining amount was paid subsequent to the year end. All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares. As at Dec. 31 2022 2021 Series (1) Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 9.6 235 Series B 2.4 58 2.4 58 Series C 10.0 243 11.0 269 Series D 1.0 26 — — Series E 9.0 219 9.0 219 Series G 6.6 161 6.6 161 Issued and outstanding, end of year 38.6 942 38.6 942 (1) Series 1 Preferred Shares are accounted for as long-term debt. Refer to Note 26.
Disclosure of characteristics specific to preferred share series	Characteristics specific to each first preferred share series as at Dec. 31, 2022, are as follows: Series Rate during term Annual dividend rate per share ($) (1) Next Rate spread over benchmark (per cent) Convertible to A Fixed 0.71924 March 31, 2026 2.03 B B Floating 1.10295 March 31, 2026 2.03 A C Fixed 1.34933 Jun. 30, 2027 3.10 D D Floating 1.40030 Jun. 30, 2027 3.10 C E Fixed 1.51102 Sept. 30, 2027 3.65 F F Floating — — 3.65 E G Fixed 1.24700 Sept. 30, 2024 3.80 H H Floating — — 3.80 G (1) The annual dividend rate per share represents dividends declared in 2022.
Disclosure of dividends declared on preference shares	The following table summarizes the value of the preferred share dividends declared in 2022 and 2021: Total dividends declared Series 2022 (1) 2021 (1) A 7 7 B (2) 3 1 C 14 11 D (3) 1 — E 13 12 G 8 8 Total for the year 46 39 (1) No dividends were declared in the first quarter of the year as the quarterly dividend related to the period covering the first quarter was declared in December of the prior year. (2) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.0 per cent. (3) Series D Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 3.1 per cent.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of analysis of other comprehensive income by item [abstract]
Disclosure of changes in accumulated other comprehensive income (loss)	The components of and changes in, accumulated other comprehensive income (loss) are as follows: 2022 2021 Currency translation adjustment Opening balance, Jan. 1 (35) (21) Losses (gains) on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax 21 (14) Gains (losses) on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax (1) (25) — Balance, Dec. 31 (39) (35) Cash flow hedges Opening balance, Jan. 1 228 436 Losses on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax (2) (456) (208) Balance, Dec. 31 (228) 228 Employee future benefits Opening balance, Jan. 1 (29) (66) Net actuarial gains on defined benefit plans, net of tax (3) 37 37 Balance, Dec. 31 8 (29) Other Opening balance, Jan. 1 (18) (47) Intercompany and third-party investments at FVTOCI 55 29 Balance, Dec. 31 37 (18) Accumulated other comprehensive income (loss) (222) 146 (1) Net of income tax recovery of $3 million for the year ended Dec. 31, 2022 (2021 – nil). (2) Net of income tax recovery of $112 million for the year ended Dec. 31, 2022 (2021 – $57 million). (3) Net of income tax expense of $12 million for the year ended Dec. 31, 2022 (2021 – $11 million).

Share-Based Payment Plans (Tabl

Share-Based Payment Plans (Tables)	12 Months Ended
	Dec. 31, 2022
Share-based payment arrangements [Abstract]
Disclosure of range of exercise prices of outstanding share options	The total options outstanding and exercisable under the Stock Option Plan at Dec. 31, 2022, are outlined below: Options outstanding Range of exercise prices (1) ($ per share) Number of options (millions) Weighted average remaining contractual life (years) Weighted average exercise price ($ per share) 5.00-12.00 3.0 3.89 8.41
Disclosure of number and weighted average remaining contractual life of outstanding share options	The total options outstanding and exercisable under the Stock Option Plan at Dec. 31, 2022, are outlined below: Options outstanding Range of exercise prices (1) ($ per share) Number of options (millions) Weighted average remaining contractual life (years) Weighted average exercise price ($ per share) 5.00-12.00 3.0 3.89 8.41 (1) Options currently exercisable as at Dec. 31, 2022.

Employee Future Benefits (Table

Employee Future Benefits (Tables)	12 Months Ended
	Dec. 31, 2022
Employee Benefits [Abstract]
Disclosure of costs recognized	The costs recognized in net earnings during the year on the defined benefit, defined contribution and other post-employment benefits plans are as follows: Year ended Dec. 31, 2022 Registered Supplemental Other Total Current service cost 1 1 — 2 Administration expenses 1 — — 1 Interest cost on defined benefit obligation 13 3 — 16 Interest on plan assets (9) — — (9) Defined benefit expense 6 4 — 10 Defined contribution expense 11 — — 11 Net expense 17 4 — 21 Year ended Dec. 31, 2021 Registered Supplemental Other Total Current service cost 3 2 1 6 Administration expenses 1 — — 1 Interest cost on defined benefit obligation 12 2 — 14 Interest on plan assets (8) — — (8) Curtailment and amendment gain (7) — — (7) Defined benefit expense 1 4 1 6 Defined contribution expense 8 — — 8 Net expense 9 4 1 14 Year ended Dec. 31, 2020 Registered Supplemental Other Total Current service cost 5 2 1 8 Administration expenses 1 — — 1 Interest cost on defined benefit obligation 16 3 1 20 Interest on plan assets (11) (1) — (12) Curtailment and amendment gain (2) — — (2) Defined benefit expense 9 4 2 15 Defined contribution expense 9 — — 9 Net expense 18 4 2 24 The expected employer contributions for 2023 for the defined benefit pension and other post-employment benefit plans are as follows: Registered Supplemental Other Total Expected employer contributions 1 6 2 9
Disclosure of defined benefit obligation	The status of the defined benefit pension and other post-employment benefit plans is as follows: Year ended Dec. 31, 2022 Registered Supplemental Other Total Fair value of plan assets 274 15 — 289 Present value of defined benefit obligation (345) (85) (17) (447) Funded status – plan deficit (71) (70) (17) (158) Amount recognized in the consolidated financial statements: Accrued current liabilities (1) (6) (1) (8) Other long-term liabilities (70) (64) (16) (150) Total amount recognized (71) (70) (17) (158) Year ended Dec. 31, 2021 Registered Supplemental Other Total Fair value of plan assets 339 14 — 353 Present value of defined benefit obligation (469) (101) (23) (593) Funded status – plan deficit (130) (87) (23) (240) Amount recognized in the consolidated financial statements: Accrued current liabilities (4) (6) (2) (12) Other long-term liabilities (126) (81) (21) (228) Total amount recognized (130) (87) (23) (240) The present value of the obligation for the defined benefit pension and other post-employment benefit plans is as follows: Registered Supplemental Other Total Present value of defined benefit obligation as at Dec. 31, 2020 542 109 24 675 Current service cost 3 2 1 6 Interest cost 12 2 — 14 Benefits paid (54) (5) (1) (60) Curtailment (7) — — (7) Actuarial gain arising from financial assumptions (26) (7) (1) (34) Actuarial gain arising from experience adjustments (1) — — (1) Present value of defined benefit obligation as at Dec. 31, 2021 469 101 23 593 Current service cost 1 1 — 2 Interest cost 13 3 — 16 Benefits paid (57) (5) 1 (61) Actuarial gain arising from financial assumptions (83) (22) (5) (110) Actuarial loss (gain) arising from experience adjustments 1 7 (2) 6 Change in foreign exchange rates 1 — — 1 Present value of defined benefit obligation as at Dec. 31, 2022 345 85 17 447
Disclosure of plan assets	The fair value of the plan assets of the defined benefit pension and other post-employment benefit plans is as follows: Registered Supplemental Other Total As at Dec. 31, 2020 367 14 — 381 Interest on plan assets 8 — — 8 Net return (loss) on plan assets 14 (1) — 13 Contributions 5 6 1 12 Benefits paid (54) (5) (1) (60) Administration expenses (1) — — (1) As at Dec. 31, 2021 339 14 — 353 Interest on plan assets 9 — — 9 Net loss on plan assets (55) — — (55) Contributions (1) 38 6 — 44 Benefits paid (57) (5) — (62) Administration expenses (1) — — (1) Change in foreign exchange rates 1 — — 1 As at Dec. 31, 2022 274 15 — 289 (1) The Company made a voluntary contribution of $35 million to further improve the funded status of the Sunhills Mining Ltd. Pension Plan for the Highvale mine. The contribution reduces the amount of the Company's future funding obligations, including amounts secured by the letters of credit. The fair value of the Company’s defined benefit plan assets by major category is as follows: As at Dec. 31, 2022 Level I Level II Level III Total Equity securities Canadian — 18 — 18 US 12 5 — 17 International 38 41 — 79 Private — — 1 1 Bonds AAA — 24 — 24 AA — 38 — 38 A — 26 — 26 BBB 1 18 — 19 Below BBB — 6 — 6 Loans A — 1 — 1 BBB — 1 — 1 Alternative funds (1) — — 39 39 Money market and cash and cash equivalents — 20 — 20 Total 51 198 40 289 (1) Alternative funds include investments in infrastructure and real estate funds. As at Dec. 31, 2021 Level I Level II Level III Total Equity securities Canadian — 29 4 33 US — 20 — 20 International 47 79 — 126 Private — — 1 1 Bonds AAA — 28 — 28 AA — 54 — 54 A — 36 — 36 BBB 1 24 — 25 Below BBB — 10 — 10 Money market and cash and cash equivalents — 20 — 20 Total 48 300 5 353
Disclosure of assumptions	Assumptions The significant actuarial assumptions used in measuring the Company’s defined benefit obligation for the defined benefit pension and other post-employment benefit plans are as follows: 2022 2021 As at Dec. 31 (per cent) Registered Supplemental Other Registered Supplemental Other Accrued benefit obligation Discount rate 4.7 5.0 5.0 2.8 2.8 2.7 Rate of compensation increase 2.6 3.0 — 2.9 3.0 — Assumed health-care cost trend rate Health-care cost escalation (1)(3) — — 7.1 — — 6.8 Dental-care cost escalation — — 4.2 — — 4.0 Benefit cost for the year Discount rate 2.8 2.8 2.7 2.4 2.3 2.3 Rate of compensation increase 2.9 3.0 — 2.9 3.0 — Assumed health-care cost trend rate Health-care cost escalation (2)(4) — — 6.8 — — 7.1 Dental-care cost escalation — — 4.7 — — 4.0 (1) 2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2032 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada. (2) 2022 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2031 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada. (3) 2021 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada. (4) 2021 Post- and pre-65 rates: decreasing gradually to 4.5 per cent by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3 per cent per year to 4.5 per cent in 2030 for Canada.
Disclosure of estimated increase in the net defined benefit obligation assuming certain changes in key assumptions	The following table outlines the estimated increase in the net defined benefit obligation assuming certain changes in key assumptions: Canadian plans US plans Year ended Dec. 31, 2022 Registered Supplemental Other Pension 1% decrease in the discount rate 31 10 2 2 1% increase in the salary scale 1 — — — 1% increase in the health-care cost trend rate — — 1 — 10% improvement in mortality rates 12 2 — 1

Joint Arrangements (Tables)

Joint Arrangements (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of interests in other entities [Abstract]
Disclosure of interests in joint arrangements	Joint arrangements at Dec. 31, 2022, included the following: Joint operations Segment Ownership (per cent) Description Sheerness Gas 50 Dual-fuel facility in Alberta, of which TA Cogen has a 50 per cent interest, operated by Heartland Generation Ltd., an affiliate of Energy Capital Partners Goldfields Power Gas 50 Gas-fired facility in Australia operated by TransAlta Fort Saskatchewan Gas 60 Cogeneration facility in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta Fortescue River Gas Pipeline Gas 43 Natural gas pipeline in Western Australia, operated by DBP Development Group McBride Lake Wind and Solar 50 Wind generation facility in Alberta operated by TransAlta Soderglen Wind and Solar 50 Wind generation facility in Alberta operated by TransAlta Pingston Hydro 50 Hydro facility in British Columbia operated by TransAlta Joint venture Segment Ownership (per cent) Description Skookumchuck Wind and Solar 49 Wind generation facility in Washington operated by Southern Power

Cash Flow Information (Tables)

Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of cash flow statement [Abstract]
Disclosure of non-cash operating working capital	Year ended Dec. 31 2022 2021 2020 (Use) source: Accounts receivable (869) (28) (79) Prepaid expenses — 9 2 Income taxes receivable (61) — (4) Inventory 6 42 6 Accounts payable, accrued liabilities and provisions 548 153 160 Income taxes payable 60 (2) 4 Change in non-cash operating working capital (316) 174 89
Disclosure of cash flows from (used in) operating activities	Balance Dec. 31, 2021 Cash issuances (1) Repayments and dividends paid (2) New leases Dividends declared Foreign exchange impact Other Balance Dec. 31, 2022 Long-term debt and lease liabilities 3,267 981 (630) 40 — 39 (28) 3,669 Exchangeable securities 735 — — — — — 4 739 Dividends payable (common and preferred) 62 — (97) — 103 — — 68 Total liabilities from 4,064 981 (727) 40 103 39 (24) 4,476 (1) Includes $449 million net increase in borrowings under credit facilities and an increase in issuance of long-term debt of $532 million. (2) Includes a decrease of $621 million related to the repayment of long-term debt and a decrease in finance lease obligations of $9 million. Balance Dec. 31, 2020 Cash issuances (1) Repayments and dividends paid (2) New leases Dividends declared Foreign exchange impact Other Balance Dec. 31, 2021 Long-term debt and lease liabilities 3,361 173 (214) 1 — (39) (15) 3,267 Exchangeable securities 730 — — — — — 5 735 Dividends payable (common and preferred) 59 — (87) — 90 — — 62 Total liabilities from financing activities 4,150 173 (301) 1 90 (39) (10) 4,064 (1) Includes an increase in issuance of long-term debt of $173 million. (2) Includes a net decrease of $114 million in borrowings under credit facilities, a decrease of $92 million related to the repayment of long-term debt and a decrease in finance lease obligations of $8 million.

Capital (Tables)

Capital (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of notes and other explanatory information [Abstract]
Disclosure of share capital, reserves and other equity interest	Common Shares A. Issued and Outstanding TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value. As at Dec. 31 2022 2021 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 271.0 2,901 269.8 2,896 Purchased and cancelled under the NCIB (4.3) (46) — — Effects of share-based payment plans 0.9 5 — (3) Stock options exercised 0.5 3 1.2 8 Issued and outstanding, end of year 268.1 2,863 271.0 2,901 B. Normal Course Issuer Bid ("NCIB") Program Shares purchased by the Company under the NCIB are recognized as a reduction to share capital equal to the average carrying value of the common shares. Any difference between the aggregate purchase price and the average carrying value of the common shares is recorded in deficit. The following are the effects of the Company's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2022 2021 Total shares purchased (1) 4,342,300 — Average purchase price per share 12.48 — Total cost (millions) 54 — Weighted average book value of shares cancelled 46 — Amount recorded in deficit (8) — (1) As at Dec. 31, 2022, includes 164,300 (2021 – nil) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. The Company paid $52 million in 2022 and the remaining amount was paid subsequent to the year end. 2022 On May 24, 2022, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to renew its normal course issuer bid for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 17, 2022. Any common shares purchased under the NCIB are cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2022, and ends on May 30, 2023. 2021 On May 25, 2021, the Company announced that the TSX accepted the notice filed by the Company to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14 million common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. No common shares were repurchased in 2021 under the current and previous NCIB. C. Shareholder Rights Plan The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 28, 2022. As required, the Shareholder Rights Plan must be put before the Company’s shareholders every three years for approval. It was last approved on April 28, 2022, and will need to be approved at the annual meeting of shareholders in 2025. The primary objective of the Shareholder Rights Plan is to encourage a potential acquirer to meet certain minimum standards designed to promote the fair and equal treatment of all common shareholders. When an acquiring shareho lder acquires 20 per cent or more of the Company’s common shares, except in limited circumstances including by way of a “permitted bid” or a "competing permitted bid" (as defined in the Shareholder Rights Plan), the rights granted under the Shareholder Rights Plan become exercisable by all shareholders except those held by the acquiring shareholder. Each right will entitle a shareholder, other than the acquiring shareholder, to purchase additional common shares at a significant discount to market, thus exposing the person acquiring 20 per cent or more of the shares to substantial dilution of their holdings. D. Earnings per Share Year ended Dec. 31 2022 2021 2020 Net earnings (loss) attributable to common shareholders 4 (576) (336) Basic and diluted weighted average number of common shares outstanding 271 271 275 Net earnings (loss) per share attributable to common shareholders, basic and diluted 0.01 (2.13) (1.22) E. Dividends On Dec. 12, 2022, the Company declared a quarterly dividend of $0.055 per common share, payable on April 1, 2023. There have been no other transactions involving common shares between the reporting date and the date of completion of these consolidated financial statements. A. Issued and Outstanding All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares. As at Dec. 31 2022 2021 Series (1) Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 9.6 235 Series B 2.4 58 2.4 58 Series C 10.0 243 11.0 269 Series D 1.0 26 — — Series E 9.0 219 9.0 219 Series G 6.6 161 6.6 161 Issued and outstanding, end of year 38.6 942 38.6 942 (1) Series 1 Preferred Shares are accounted for as long-term debt. Refer to Note 26. I. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On March 31, 2021, the Company converted 1,417,338 of its 10.2 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") and 871,871 of its 1.8 million Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares"), on a one-for-one basis, into Series B Shares and Series A Shares. II. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion On June 30, 2022, the Company converted 1,044,299 of its 11.0 million Cumulative Redeemable Rate Reset First Preferred Shares, Series C (“Series C Shares”), on a one-for-one basis, into Cumulative Redeemable Floating Rate First Preferred Shares, Series D (“Series D Shares”). The Series C Shares will pay fixed cumulative preferential cash dividends on a quarterly basis, for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The annual fixed dividend rate of 5.854 per cent, being equal to the five-year Government of Canada bond yield of 2.754 per cent determined as of May 31, 2022, plus 3.10 per cent, in accordance with the terms of the Series C Shares. The Series D Shares will pay quarterly floating rate cumulative preferential cash dividends for the five-year period from and including June 30, 2022, to but excluding June 30, 2027, if, as and when declared by the Board. The quarterly dividend rate for the Series D Shares will be established each quarter, being equal to the annual rate for the auction of 90-day Government of Canada Treasury Bills, plus 3.10 per cent, in accordance with the terms of the Series D Shares. III. Series E Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On Sept. 21, 2022, the Company announced that, after taking into account all election notices received for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series E (the "Series E shares") into Cumulative Redeemable Floating Rate Preferred Shares Series F (the "Series F Shares"), there were 89,945 Series E Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series F Shares. Therefore, none of the Series E Shares were converted into Series F Shares. As a result, the Series E Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series E Shares for the five-year period from and including Sept. 30, 2022, to but excluding Sept. 30, 2027, will be 6.894 per cent, which is equal to the five-year Government of Canada bond yield of 3.244 per cent, determined as of Aug. 31, 2022, plus 3.65 per cent, in accordance with the terms of the Series E Shares. Preferred Share Series Information The holders are entitled to receive cumulative fixed quarterly cash dividends at specified rates, as approved by the Board. After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed rate resets to the sum of the then five-year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified spread. Upon each Rate Reset Date, the shares are also: • Redeemable at the option of the Company, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. • Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Company and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2022, are as follows: Series Rate during term Annual dividend rate per share ($) (1) Next Rate spread over benchmark (per cent) Convertible to A Fixed 0.71924 March 31, 2026 2.03 B B Floating 1.10295 March 31, 2026 2.03 A C Fixed 1.34933 Jun. 30, 2027 3.10 D D Floating 1.40030 Jun. 30, 2027 3.10 C E Fixed 1.51102 Sept. 30, 2027 3.65 F F Floating — — 3.65 E G Fixed 1.24700 Sept. 30, 2024 3.80 H H Floating — — 3.80 G (1) The annual dividend rate per share represents dividends declared in 2022. B. Dividends The following table summarizes the value of the preferred share dividends declared in 2022 and 2021: Total dividends declared Series 2022 (1) 2021 (1) A 7 7 B (2) 3 1 C 14 11 D (3) 1 — E 13 12 G 8 8 Total for the year 46 39 (1) No dividends were declared in the first quarter of the year as the quarterly dividend related to the period covering the first quarter was declared in December of the prior year. (2) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.0 per cent. (3) Series D Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 3.1 per cent. TransAlta’s capital is comprised of the following: As at Dec. 31 2022 2021 Increase/ Long-term debt (1) 3,653 3,267 386 Exchangeable securities 739 735 4 Bank overdraft 16 — 16 Equity Common shares 2,863 2,901 (38) Preferred shares 942 942 — Contributed surplus 41 46 (5) Deficit (2,514) (2,453) (61) Accumulated other comprehensive income (loss) (222) 146 (368) Non-controlling interests 879 1,011 (132) Less: available cash and cash equivalents (1,134) (947) (187) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (17) (17) — Less: fair value asset of hedging instruments on long-term debt (4) (3) (2) (1) Total capital 5,243 5,629 (386) (1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt. (2) The Company includes available cash and cash equivalents, as a reduction in the calculation of capital, as capital is managed internally and evaluated by management using a net debt position. In this regard, these funds may be available and used to facilitate repayment of debt. (3) The Company includes the principal portion of restricted cash on TransAlta OCP bonds as this cash is restricted specifically to repay outstanding debt. (4) The Company includes the fair value of economic and designated hedging instruments on debt in an asset, or liability, position as a reduction, or increase, in the calculation of capital, as the carrying value of the related debt has either increased, or decreased, due to changes in foreign exchange rates.
Disclosure of cash flow statement	For the years ended Dec. 31, 2022 and 2021, cash inflows and outflows are summarized below. The Company manages variations in working capital using existing liquidity under credit facilities to ensure sufficient cash and credit are available to fund operations, pay dividends, distribute payments to subsidiaries' non-controlling interests and invest in PP&E. Year ended Dec. 31 2022 2021 Increase Cash flow from operating activities 877 1,001 (124) Change in non-cash working capital 316 (174) 490 Cash flow from operations before changes in working capital 1,193 827 366 Dividends paid on common shares (54) (48) (6) Dividends paid on preferred shares (43) (39) (4) Distributions paid to subsidiaries’ non-controlling interests (187) (156) (31) Property, plant and equipment expenditures (918) (480) (438) Inflow (outflow) (9) 104 (113)

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2022
Related Party [Abstract]
Disclosure of interests in subsidiaries	The net earnings, distributions and equity attributable to non-controlling interests include the 17 per cent non-controlling interest in Kent Hills Wind LP. Year ended Dec. 31 2022 2021 2020 Revenues 560 470 436 Net earnings 74 139 97 Total comprehensive income (loss) (67) 66 223 Amounts attributable to the non-controlling interests: Net earnings 20 50 40 Total comprehensive income (loss) (36) 21 90 Distributions paid to non-controlling interests 100 100 80 As at Dec. 31 2022 2021 Current assets 240 430 Long-term assets 2,989 3,319 Current liabilities (306) (593) Long-term liabilities (1,118) (1,033) Total equity (1,805) (2,123) Equity attributable to non-controlling interests (732) (869) Non-controlling interests’ share (per cent) 39.9 39.9 B. TA Cogen Year ended Dec. 31 2022 2021 2020 Revenues 347 265 146 Net earnings (loss) 143 103 (13) Total comprehensive income (loss) 143 103 (13) Amounts attributable to the non-controlling interest: Net earnings (loss) 91 62 (6) Total comprehensive income (loss) 91 62 (6) Distributions paid to Canadian Power Holdings Inc. 87 56 17 As at Dec. 31 2022 2021 Current assets 127 66 Long-term assets 253 312 Current liabilities (62) (52) Long-term liabilities (27) (36) Total equity (291) (290) Equity attributable to Canadian Power Holdings Inc. (147) (142) Non-controlling interest share (per cent) 49.99 49.99 Details of the Company’s principal operating subsidiaries at Dec. 31, 2022, are as follows: Subsidiary Country Ownership Principal activity TransAlta Generation Partnership Canada 100 Generation and sale of electricity TransAlta Cogeneration, L.P. Canada 50.01 Generation and sale of electricity TransAlta Centralia Generation, LLC US 100 Generation and sale of electricity TransAlta Energy Marketing Corp. Canada 100 Energy marketing TransAlta Energy Marketing (U.S.), Inc. US 100 Energy marketing TransAlta Energy (Australia), Pty Ltd. Australia 100 Generation and sale of electricity TransAlta Renewables Inc. Canada 60.1 Generation and sale of electricity Associate or joint venture Country Ownership Principal activity SP Skookumchuck Investment, LLC US 49 Generation and sale of electricity EMG International, LLC US 30 Wastewater treatment and biogas fuel to generate electricity
Disclosure of information about key management personnel and transactions with associates	TransAlta’s key management personnel include the President and Chief Executive Officer ("CEO") and members of the senior management team that report directly to the President and CEO and the members of the Board. Key management personnel compensation is as follows: Year ended Dec. 31 2022 2021 2020 Total compensation 23 30 27 Comprised of: Short-term employee benefits 11 14 12 Post-employment benefits 1 1 2 Share-based payments 11 15 13 Transactions with Brookfield include the following: Year ended Dec. 31 2022 2021 2020 Power sales 127 27 10 Purchased power 12 3 3 Asset management fees paid 2 2 1

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of other provisions, contingent liabilities and contingent assets [Abstract]
Disclosure of commitments and future payments	In addition to commitments disclosed elsewhere in the financial statements, the Company has incurred the following additional contractual commitments, either directly or through its interests in joint operations. Approximate future payments under these agreements are as follows: 2023 2024 2025 2026 2027 2028 and thereafter Total Natural gas, transportation and other contracts 56 47 45 45 46 457 696 Transmission 10 7 7 3 1 39 67 Coal supply agreements 83 87 71 — — — 241 Long-term service agreements 51 49 35 32 21 140 328 Operating leases 3 3 3 2 2 29 42 Growth 446 — — — — — 446 TransAlta Energy Transition Bill 6 — — — — — 6 Total 655 193 161 82 70 665 1,826

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2022
Disclosure of operating segments [abstract]
Disclosure of operating segments	Year ended Dec. 31, 2022 Hydro Wind & Solar (1) Gas Energy Transition Energy Corporate Total Equity accounted investments (1) Reclass adjustments IFRS financials Revenues 606 303 1,209 714 160 (2) 2,990 (14) — 2,976 Reclassifications and adjustments: Unrealized mark-to-market 1 104 251 10 12 — 378 — (378) — Realized (gain) loss on — — (4) — 47 — 43 — (43) — Decrease in finance lease — — 46 — — — 46 — (46) — Finance lease income — — 19 — — — 19 — (19) — Unrealized foreign exchange — — — — (1) — (1) — 1 — Adjusted revenues 607 407 1,521 724 218 (2) 3,475 (14) (485) 2,976 Fuel and purchased power 22 31 641 566 — 3 1,263 — — 1,263 Reclassifications and adjustments: Australian interest income — — (4) — — — (4) — 4 — Adjusted fuel and purchased 22 31 637 566 — 3 1,259 — 4 1,263 Carbon compliance — 1 83 (1) — (5) 78 — — 78 Gross margin 585 375 801 159 218 — 2,138 (14) (489) 1,635 OM&A 55 68 195 69 35 101 523 (2) — 521 Taxes, other than income 3 12 15 4 — 1 35 (2) — 33 Net other operating (income) — (23) (38) — — — (61) 3 — (58) Insurance recovery — 7 — — — — 7 — (7) — Adjusted net other operating — (16) (38) — — — (54) 3 (7) (58) Adjusted EBITDA (2) 527 311 629 86 183 (102) 1,634 Equity income 9 Finance lease income 19 Depreciation and amortization (599) Asset impairment charges (9) Net interest expense (262) Foreign exchange gain 4 Gain on sale of assets and other 52 Earnings before income taxes 353 (1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment. (2) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Year ended Dec. 31, 2021 Hydro Wind & Solar (1) Gas Energy Transition Energy Corporate Total Equity accounted investments (1) Reclass adjustments IFRS financials Revenues 383 323 1,109 709 211 4 2,739 (18) — 2,721 Reclassifications and adjustments: Unrealized mark-to-market — 25 (40) 19 (38) — (34) — 34 — Realized (gain) loss on closed exchange positions (2) — — (6) — 29 — 23 — (23) — Decrease in finance lease — — 41 — — — 41 — (41) — Finance lease income — — 25 — — — 25 — (25) — Unrealized foreign exchange — — (3) — — — (3) — 3 — Adjusted revenues 383 348 1,126 728 202 4 2,791 (18) (52) 2,721 Fuel and purchased power 16 17 457 560 — 4 1,054 — — 1,054 Reclassifications and adjustments: Australian interest income — — (4) — — — (4) — 4 — Mine depreciation — — (79) (111) — — (190) — 190 — Coal inventory write-down — — — (17) — — (17) — 17 — Adjusted fuel and purchased 16 17 374 432 — 4 843 — 211 1,054 Carbon compliance — — 118 60 — — 178 — — 178 Gross margin 367 331 634 236 202 — 1,770 (18) (263) 1,489 OM&A 42 59 175 117 36 84 513 (2) — 511 Reclassifications and adjustments: Parts and materials — — (2) (26) — — (28) — 28 — Curtailment gain — — — 6 — — 6 — (6) — Adjusted OM&A 42 59 173 97 36 84 491 (2) 22 511 Taxes, other than income 3 10 13 6 — 1 33 (1) — 32 Net other operating loss — — (40) 48 — — 8 — — 8 Reclassifications and adjustments: Royalty onerous contract and — — — (48) — — (48) — 48 — Adjusted net other operating — — (40) — — — (40) — 48 8 Adjusted EBITDA (3) 322 262 488 133 166 (85) 1,286 Equity income 9 Finance lease income 25 Depreciation and amortization (529) Asset impairment charges (648) Net interest expense (245) Foreign exchange gain 16 Gain on sale of assets and 54 Loss before income taxes (380) (1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment. (2) In 2022, our adjusted EBITDA composition was adjusted to include the impact of closed positions that are effectively settled by offsetting positions with the same counterparty to reflect the performance of the assets and the Energy Marketing segment in the period in which the transactions occur. (3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Year ended Dec. 31, 2020 Hydro Wind & Solar (1) Gas Energy Transition Energy Corporate Total Equity accounted investments (1) Reclass adjustments IFRS financials Revenues 152 332 787 704 122 7 2,104 (3) — 2,101 Reclassifications and adjustments: Unrealized mark-to-market — 2 33 (14) 21 — 42 — (42) — Realized gain on closed exchange positions (2) — — — — (10) — (10) — 10 — Decrease in finance lease — — 17 — — — 17 — (17) — Finance lease income — — 7 — — — 7 — (7) — Unrealized foreign — — 4 — — — 4 — (4) — Adjusted revenues 152 334 848 690 133 7 2,164 (3) (60) 2,101 Fuel and purchased power 8 25 325 435 — 12 805 — — 805 Reclassifications and adjustments: Australian interest income — — (4) — — — (4) — 4 — Mine depreciation — — (100) (46) — — (146) — 146 — Coal inventory write-down — — — (37) — — (37) — 37 — Adjusted fuel and purchased power 8 25 221 352 — 12 618 — 187 805 Carbon compliance — — 120 48 — (5) 163 — — 163 Gross margin 144 309 507 290 133 — 1,383 (3) (247) 1,133 OM&A 37 53 166 106 30 80 472 — — 472 Taxes, other than income 2 8 13 9 — 1 33 — — 33 Net other operating income — — (11) — — — (11) — — (11) Reclassifications and adjustments: Impact of Sheerness going — — (28) — — — (28) — 28 — Adjusted net other operating — — (39) — — — (39) — 28 (11) Adjusted EBITDA (3) 105 248 367 175 103 (81) 917 Equity income 1 Finance lease income 7 Depreciation and (654) Asset impairment charges (84) Net interest expense (238) Foreign exchange gain 17 Gain on sale of assets and 9 Loss before income taxes (303) (1) The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment. (2) In 2022, our adjusted EBITDA composition was adjusted to include the impact of closed positions that are effectively settled by offsetting positions with the same counterparty to reflect the performance of the assets and the Energy Marketing segment in the period in which the transactions occur. (3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.
Disclosure of selected consolidated statements of financial position information	Selected Consolidated Statements of Financial Position Information As at Dec. 31, 2022 Hydro Wind Gas Energy Transition Energy Corporate Total PP&E 437 2,837 1,858 313 — 111 5,556 Right-of-use assets 6 98 6 2 — 14 126 Intangible assets 2 157 49 5 8 31 252 Goodwill 258 176 — — 30 — 464 As at Dec. 31, 2021 Hydro Wind Gas Energy Transition Energy Corporate Total PP&E 466 2,304 2,036 481 — 33 5,320 Right-of-use assets 5 64 7 1 — 18 95 Intangible assets 3 147 56 9 5 36 256 Goodwill 258 175 — — 30 — 463
Disclosure of components in other non-current assets	Additions to non-current assets are as follows: Year ended Dec. 31, 2022 Hydro Wind Gas Energy Transition Energy Corporate Total Additions to non-current assets: PP&E 36 745 43 19 — 75 918 Intangible assets — 19 — — 3 9 31 Year ended Dec. 31, 2021 Hydro Wind Gas Energy Transition Energy Corporate Total Additions to non-current assets: PP&E 29 166 167 90 — 28 480 Intangible assets — — — 1 — 8 9 Year ended Dec. 31, 2020 Hydro Wind Gas Energy Transition Energy Corporate Total Additions to non-current assets: PP&E 22 174 199 78 — 13 486 Intangible assets — — — 1 — 13 14
Disclosure of reconciliation between depreciation and amortization	The reconciliation between depreciation and amortization reported on the Consolidated Statements of Earnings (Loss) and the Consolidated Statements of Cash Flows is presented below: Year ended Dec. 31 2022 2021 2020 Depreciation and amortization expense on the Consolidated Statements of 599 529 654 Depreciation included in fuel and purchased power (Note 6) — 190 144 Depreciation and amortization on the Consolidated Statements of Cash Flows 599 719 798
Disclosure of geographical areas	Revenues Year ended Dec. 31 2022 2021 2020 Canada 1,905 1,854 1,227 US 940 731 716 Australia 131 136 158 Total revenue 2,976 2,721 2,101 II. Non-Current Assets Property, plant and Right-of-use assets Intangible assets Other assets As at Dec. 31 2022 2021 2022 2021 2022 2021 2022 2021 Canada 3,817 4,051 49 52 123 141 62 15 US 1,307 860 74 39 101 85 34 61 Australia 432 409 3 4 28 30 64 66 Total 5,556 5,320 126 95 252 256 160 142

Corporate Information (Details)

Corporate Information (Details)	Dec. 31, 2022 segment
Disclosure of operating segments [line items]
Number of segments	6
Generation Segments
Disclosure of operating segments [line items]
Number of segments	4

Material Accounting Policies (D

Material Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2022
Hydro generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	2 years
Hydro generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	50 years
Wind and Solar generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	2 years
Wind and Solar generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	30 years
Gas generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	2 years
Gas generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	35 years
Energy Transition | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	1 year
Energy Transition | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	10 years
Capital spares and other | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	2 years
Capital spares and other | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	50 years
Facilities | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	3 years
Facilities | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	50 years
Software | Minimum
Disclosure of detailed information about intangible assets [line items]
Useful life measured as period of time, intangible assets other than goodwill	1 year
Software | Maximum
Disclosure of detailed information about intangible assets [line items]
Useful life measured as period of time, intangible assets other than goodwill	7 years
Power sale contracts | Minimum
Disclosure of detailed information about intangible assets [line items]
Useful life measured as period of time, intangible assets other than goodwill	1 year
Power sale contracts | Maximum
Disclosure of detailed information about intangible assets [line items]
Useful life measured as period of time, intangible assets other than goodwill	18 years

Business Acquisitions - Narrati

Business Acquisitions - Narrative (Details) $ in Millions, $ in Millions	Nov. 05, 2021 USD ($) MW	Nov. 05, 2021 CAD ($)	Feb. 26, 2021 CAD ($)
TransAlta Renewables Inc.
Investment [Line Items]
Aggregate consideration			$ 213
North Carolina Solar | TransAlta Renewables Inc.
Investment [Line Items]
Membership interest	100%
North Carolina Solar
Investment [Line Items]
Membership interest	100%
Capacity of facility (in megawatts) | MW	122,000,000
Cash consideration	$ 99
Aggregate consideration		$ 123
North Carolina Solar | Entities with joint control or significant influence over entity
Investment [Line Items]
Aggregate consideration	$ 102

Business Acquisitions - Fair Va

Business Acquisitions - Fair Values of the Identifiable Assets and Liabilities of the Acquired Entity in the Business Combination (Details) - CAD ($) $ in Millions	Nov. 05, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about business combination [line items]
Right-of-use assets		$ 126	$ 95	$ 141
North Carolina Solar
Disclosure of detailed information about business combination [line items]
Cash and cash equivalents	$ 4
Accounts receivable	4
Property, plant and equipment	146
Right-of-use assets	13
Accounts payable and accrued liabilities	(4)
Lease liabilities	(13)
Tax equity liability	(20)
Deferred taxes	(3)
Decommissioning provisions	(4)
Net assets acquired	123
Cash consideration	120
Working capital consideration	3
Total purchase consideration transferred	$ 123

Revenue - Disaggregation of Rev

Revenue - Disaggregation of Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	$ 2,976	$ 2,721	$ 2,101
At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	63	53	58
Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	713	629	965
Revenues from contracts with customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	776	682	1,023
Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	725	654	1,000
Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	51	28	23
Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	32	19	123
Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	(507)	221	417
Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	2,640	1,767	516
Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	35	32	22
Hydro | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	606	383	152
Hydro | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	1	0	0
Hydro | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	33	28	141
Hydro | Operating segments | Revenues from contracts with customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	34	28	141
Hydro | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	33	28	141
Hydro | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	1	0	0
Hydro | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Hydro | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Hydro | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	564	345	3
Hydro | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	8	10	8
Wind and Solar | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	289	305	329
Wind and Solar | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	50	28	25
Wind and Solar | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	220	207	236
Wind and Solar | Operating segments | Revenues from contracts with customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	270	235	261
Wind and Solar | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	220	207	238
Wind and Solar | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	50	28	23
Wind and Solar | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Wind and Solar | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	(87)	(14)	8
Wind and Solar | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	86	68	49
Wind and Solar | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	20	16	11
Gas | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	1,209	1,109	787
Gas | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	2	7
Gas | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	462	393	458
Gas | Operating segments | Revenues from contracts with customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	462	395	465
Gas | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	462	395	465
Gas | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Gas | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	32	19	123
Gas | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	(821)	(118)	(8)
Gas | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	1,529	808	200
Gas | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	7	5	7
Energy Transition | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	714	709	704
Energy Transition | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	12	23	26
Energy Transition | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	(2)	1	130
Energy Transition | Operating segments | Revenues from contracts with customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	10	24	156
Energy Transition | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	10	24	156
Energy Transition | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Transition | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Transition | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	243	138	283
Energy Transition | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	461	546	264
Energy Transition | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	1	1
Energy Marketing | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	160	211	122
Energy Marketing | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Revenues from contracts with customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	160	211	122
Energy Marketing | Operating segments | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Energy Marketing | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	(2)	4	7
Corporate | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Revenues from contracts with customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Power and other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Environmental attributes
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Revenue from leases
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Revenue from derivatives and other trading activities
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	(2)	4	12
Corporate | Revenue from merchant sales
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	0	0	0
Corporate | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Total revenue from contracts with customers	$ 0	$ 0	$ (5)

Revenue - Narrative (Details)

Revenue - Narrative (Details) $ in Millions	Dec. 31, 2022 CAD ($)
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	$ 2,790
2023 to 2025
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	465
2026 to 2028
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	490
2029 to 2033
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	750
2034 and Thereafter
Disclosure of disaggregation of revenue from contracts with customers [line items]
Remaining performance obligations	$ 1,085

Expenses by Nature - Expenses C

Expenses by Nature - Expenses Classified by Nature (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of products and services [line items]
Mine depreciation	$ 0	$ 190	$ 144
Total		511	472
Adjustments for impairment loss (reversal of impairment loss) recognised in profit or loss, inventories		17	15
Fuel and purchased power
Disclosure of products and services [line items]
Gas fuel costs	578	306	159
Coal fuel costs	141	164	269
Royalty, land lease, other direct costs	25	19	20
Purchased power	514	339	163
Mine depreciation	0	190	144
Salaries and benefits	5	36	50
Other operating expenses	0	0	0
Total	1,263	1,054	805
Fuel and purchased power | Coal (tonnes)
Disclosure of products and services [line items]
Mine depreciation		48	22
OM&A
Disclosure of products and services [line items]
Gas fuel costs	0	0	0
Coal fuel costs	0	0	0
Royalty, land lease, other direct costs	0	0	0
Purchased power	0	0	0
Mine depreciation	0	0	0
Salaries and benefits	263	234	235
Other operating expenses	258	277	237
Total	$ 521	511	$ 472
Write-downs		$ 28

Asset Impairment Charges - Deta

Asset Impairment Charges - Detailed Information About Property, Plant, and Equipment (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges		$ 9	$ 648	$ 84
Impairment charges		0	10
Hydro generation
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges			1
Kaybob Cogeneration Project | Corporate
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges		(2)	27	0
Impairment charges	$ 27
Hydro
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges		21	5	2
Wind and Solar
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges		43	12	0
Gas
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges		0	5	0
Energy Transition
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges		0	540	82
Changes in decommissioning and restoration provisions on retired assets
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges		(53)	32	0
Intangible asset impairment charges - Coal Rights
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges		0	17	0
Project development costs
Disclosure of detailed information about property, plant and equipment [line items]
Asset impairment charges		$ 0	10	$ 0
Project development costs | Hydro generation
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges			$ 9

Asset Impairment Charges - Narr

Asset Impairment Charges - Narrative (Details) $ in Millions, $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2022 CAD ($) MW	Mar. 31, 2021 CAD ($)	Dec. 31, 2022 CAD ($) asset numberOfAssets facility MW	Dec. 31, 2021 CAD ($) MW	Dec. 31, 2020 CAD ($)	Dec. 31, 2020 USD ($)
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges			$ 0	$ 10
Recoverable amounts	$ 10,741		10,741	9,226
Asset impairment charges			9	648	$ 84
Estimated salvage value				33
Reversal of impairment loss			$ 102	0
Energy Transition
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges				$ 191
Discount rate, measurement input
Disclosure of impairment loss recognised or reversed [line items]
Discount rates				5
Wind Facilities
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges				$ 10
Wind Facilities | Level III | Non-recurring fair value measurement | Investment property
Disclosure of impairment loss recognised or reversed [line items]
Recoverable amounts				65
Kent Hills Wind L.P.
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges				$ 2
Capacity of facility (in megawatts) | MW	167		167	167
Keephills Unit 1 | Energy Transition
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges				$ 94
Sundance Unit 4 | Energy Transition
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges				56
Kaybob Cogeneration Project | Corporate
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges		$ 27
Asset impairment charges			$ (2)	27	0
Reversal of impairment loss	$ 2
Hydro
Disclosure of impairment loss recognised or reversed [line items]
Number of facilities | facility			4
Number of assets | asset			2
Asset impairment charges			$ 21	5	2
Hydro | Hydro Facilities
Disclosure of impairment loss recognised or reversed [line items]
Number of assets | numberOfAssets			4
Carrying value	88		$ 88
Hydro | Hydro Facilities | Level III | Non-recurring fair value measurement
Disclosure of impairment loss recognised or reversed [line items]
Recoverable amounts	89		$ 89
Wind
Disclosure of impairment loss recognised or reversed [line items]
Number of facilities | facility			5
Solar
Disclosure of impairment loss recognised or reversed [line items]
Number of facilities | facility			1
Wind and Solar
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charges			$ 43	12	0
Wind and Solar | Wind and Solar Facilities
Disclosure of impairment loss recognised or reversed [line items]
Number of assets | asset			6
Carrying value	748		$ 748
Wind and Solar | Wind and Solar Facilities | Level III | Non-recurring fair value measurement
Disclosure of impairment loss recognised or reversed [line items]
Recoverable amounts	$ 754		$ 754
Mining assets | Highvale Mine
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges				$ 195
Property, plant and equipment | Sundance Unit 4
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges					70
Land
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss					$ 9	$ 7

Asset Impairment Charges - Disc

Asset Impairment Charges - Disclosure of Fair Value Less Cost of Disposal (Details)	Dec. 31, 2022	Dec. 31, 2021
Canada | Wind and Solar | Contract Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year Contract and Merchant discount rates	6.40%
Prior period Contract and Merchant discount rates		500%
Canada | Wind and Solar | Merchant Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year Contract and Merchant discount rates	7.10%
Prior period Contract and Merchant discount rates		500%
Canada | Hydro | Contract Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year Contract and Merchant discount rates	5.90%
Prior period Contract and Merchant discount rates		360%
Canada | Hydro | Merchant Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year Contract and Merchant discount rates	6.40%
Prior period Contract and Merchant discount rates		490%
US | Wind and Solar | Contract Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year Contract and Merchant discount rates	6.50%
Prior period Contract and Merchant discount rates		510%
US | Wind and Solar | Merchant Discount Rate
Disclosure of detailed information about property, plant and equipment [line items]
Current year Contract and Merchant discount rates	7.70%
Prior period Contract and Merchant discount rates		500%

Net Other Operating (Income) _3

Net Other Operating (Income) Loss - Disclosure of Components of Net Other Operating (Income) Expense (Details) - CAD ($) $ in Millions		12 Months Ended
	Jul. 20, 2018	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Analysis of income and expense [abstract]
Alberta Off-Coal Agreement	$ (40)	$ (40)	$ (40)	$ (40)
Liquidated damages recoverable		(12)	0	0
Insurance recoveries		(7)	0	0
Supplier and other contract settlements		5	34	0
Onerous contract provisions		0	14	29
Retail power contract amortization		(4)	0	0
Net other operating (income) loss		$ (58)	$ 8	$ (11)

Net Other Operating (Income) _4

Net Other Operating (Income) Loss - Narrative (Details) $ in Millions, $ in Millions		3 Months Ended	12 Months Ended
	Jul. 20, 2018 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2021 USD ($)
Analysis of income and expenses [Line Items]
Alberta Off-Coal Agreement	$ (40)		$ (40)	$ (40)	$ (40)
Annual cash payments, net		$ 37
Liquidated damages recoverable			(12)	0	0
Insurance recoveries			(7)	0	0
Supplier and other contract settlements			(5)	(34)	0
Onerous contract provisions			$ 0	14	$ 29
Sundance Unit 5
Analysis of income and expenses [Line Items]
Net deferred tax assets		$ 10		$ 10		$ 8

Investments - Change in Investm

Investments - Change in Investments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Change In Investments [Roll Forward]
Equity income (loss)	$ 9	$ 9	$ 1
Changes in foreign exchange rates	10	0	0
SP Skookumchuck Investment, LLC | Equity-accounted
Change In Investments [Roll Forward]
Beginning balance	93	85
Equity income (loss)	10	12
Investment	0
Distributions received	(5)	(4)
Changes in foreign exchange rates	(7)
Net change in fair value recognized in OCI	0
Ending balance	105	93	85
EMG | Equity-accounted
Change In Investments [Roll Forward]
Beginning balance	12	15
Equity income (loss)	(1)	(3)
Investment	0
Distributions received	0	0
Changes in foreign exchange rates	(1)
Net change in fair value recognized in OCI	0
Ending balance	12	12	15
EIP | FVTPL
Change In Investments [Roll Forward]
Beginning balance	0	0
Equity income (loss)	0	0
Investment	10
Distributions received	0	0
Changes in foreign exchange rates	(1)
Net change in fair value recognized in OCI	0
Ending balance	11	0	0
Ekona | FVTOCI
Change In Investments [Roll Forward]
Beginning balance	0	0
Equity income (loss)	0	0
Investment	2
Distributions received	0	0
Changes in foreign exchange rates	0
Net change in fair value recognized in OCI	(1)
Ending balance	1	0	0
Consolidated structured entities
Change In Investments [Roll Forward]
Beginning balance	105	100
Equity income (loss)	9	9	1
Investment	12
Distributions received	(5)	(4)
Changes in foreign exchange rates	(9)
Net change in fair value recognized in OCI	(1)
Ending balance	$ 129	$ 105	$ 100

Investments - Narrative (Detail

Investments - Narrative (Details) $ in Millions, $ in Millions			12 Months Ended
	May 06, 2022 USD ($)	Nov. 30, 2020	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($) MW	Dec. 31, 2022 USD ($) MW	Feb. 01, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Investment [Line Items]
Equity investment				$ 129			$ 105
Skookumchuck
Investment [Line Items]
Ownership interest (as a percent)			49%
Capacity of facility (in megawatts) | MW				136.8	136.8
PPA, period			20 years
EMG
Investment [Line Items]
Ownership interest (as a percent)		30%
Contingent amount paid			$ 3.5
Energy Impact Partners
Investment [Line Items]
Committed investment	$ 25
Committed investment, period	4 years
Initial investment				$ 10	$ 8
Ekona | Class B Preferred Shares
Investment [Line Items]
Equity investment						$ 2

Investments - Results of Operat

Investments - Results of Operations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of subsidiaries [line items]
Revenues and other operating income	$ 2,976	$ 2,721	$ 2,101
Proportionate share of net earnings	9	9	1
Consolidated structured entities
Disclosure of subsidiaries [line items]
Revenues and other operating income	24	19	3
Expenses	(15)	(10)	(2)
Proportionate share of net earnings	$ 9	$ 9	$ 1

Net Interest Expense - Disclosu

Net Interest Expense - Disclosure of Components of Net Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Analysis of income and expense [abstract]
Interest on debt	$ 164	$ 163	$ 158
Interest on exchangeable debentures	29	29	29
Interest on exchangeable preferred shares	28	28	5
Interest income	(24)	(11)	(10)
Capitalized interest	(16)	(14)	(8)
Interest on lease liabilities	7	7	8
Credit facility fees, bank charges and other interest	27	20	25
Tax shield on tax equity financing	(2)	(9)	1
Accretion of provisions	49	32	30
Net interest expense	$ 262	$ 245	$ 238

Income Taxes - Rate Reconciliat

Income Taxes - Rate Reconciliations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Abstract]
Earnings (loss) before income taxes	$ 353	$ (380)	$ (303)
Net (earnings) loss attributable to non-controlling interests not subject to tax	(94)	(33)	2
Adjusted earnings (loss) before income taxes	$ 259	$ (413)	$ (301)
Statutory Canadian federal and provincial income tax rate (%)	23.40%	23.60%	24.50%
Expected income tax expense (recovery)	$ 61	$ (98)	$ (74)
Increase (decrease) in income taxes resulting from:
Differences in effective foreign tax rates	(1)	4	3
Non-deductible expense	130	0	0
Taxable capital gain	18	0	0
Deferred income tax expense (recovery) related to temporary difference on investment in subsidiaries	(2)	0	9
Write-down (reversal of write-down) of unrecognized deferred income tax assets	(24)	134	8
Statutory and other rate differences	(3)	4	(7)
Adjustments in respect of deferred income tax of previous years	6	(4)	(3)
Other	7	5	14
Income tax expense (recovery)	$ 192	$ 45	$ (50)
Effective tax rate (%)	74%	(11.00%)	17%

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Abstract]
Current income tax expense	$ 65	$ 56	$ 35
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences	153	(145)	(95)
Deferred income tax expense (recovery) related to temporary difference on investment in subsidiary	(2)	0	9
Deferred income tax recovery resulting from changes in tax rates or laws	0	0	(7)
Deferred income tax expense (recovery) arising from the unrecognized deferred income tax assets	(24)	134	8
Current income tax expense	65	56	35
Deferred income tax expense (recovery)	127	(11)	(85)
Income tax expense (recovery)	192	$ 45	$ (50)
Deferred tax assets yet to be recognized	$ (361)

Income Taxes - Aggregate Curren

Income Taxes - Aggregate Current and Deferred Income Tax Charged to Equity (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Abstract]
Net impact related to cash flow hedges	$ (112)	$ (57)	$ (23)
Net impact related to hedges of foreign operations	(3)	0	0
Net impact to net actuarial gains (losses)	12	11	(3)
Income tax recovery reported in equity	$ (103)	$ (46)	$ (26)

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Income Tax Assets (Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Unrecognized deferred income tax assets	$ (50)	$ (64)
Net deferred income tax liability, after write-down of deferred income tax assets	(302)	(290)
Cost | Non-capital losses
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset, before write-down of deferred income tax assets	244	530
Cost | Future decommissioning and restoration costs
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset, before write-down of deferred income tax assets	119	183
Cost | Property, plant and equipment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset, before write-down of deferred income tax assets	(553)	(651)
Cost | Risk management assets and liabilities, net
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset, before write-down of deferred income tax assets	193	(53)
Cost | Employee future benefits and compensation plans
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset, before write-down of deferred income tax assets	48	53
Cost | Interest deductible in future periods
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset, before write-down of deferred income tax assets	0	17
Cost | Foreign exchange differences on US-denominated debt
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset, before write-down of deferred income tax assets	13	16
Cost | Other deductible temporary differences
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset, before write-down of deferred income tax assets	(5)	(5)
Accumulated impairment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset, before write-down of deferred income tax assets	59	90
Unrecognized deferred income tax assets	$ (361)	$ (380)

Income Taxes - Deferred Income

Income Taxes - Deferred Income Tax Liability Presentation (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Abstract]
Deferred income tax assets	$ 50	$ 64
Deferred income tax liabilities	(352)	(354)
Net deferred income tax liability, after write-down of deferred income tax assets	$ (302)	$ (290)

Income Taxes - Contingencies (D

Income Taxes - Contingencies (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Uncertain tax positions
Disclosure of contingent liabilities [line items]
Provision for uncertain tax positions	$ 0	$ 0

Non-Controlling Interests - Sub

Non-Controlling Interests - Subsidiaries and Operations with Non-Controlling Interests (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Ownership interests	49.99%	49.99%
TransAlta Cogeneration, L.P. | TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Ownership interests	49.99%
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Ownership interests	39.90%	39.90%
Kent Hills wind farm | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Ownership interests	17%

Non-Controlling Interests - Nar

Non-Controlling Interests - Narrative (Details) - MW	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Kent Hills Wind L.P.
Disclosure of subsidiaries [line items]
Capacity of facility (in megawatts)	167	167
Coal facility | TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Ownership interests	50%
Kent Hills wind farm | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Ownership interests	17%

Non-Controlling Interests - Ear

Non-Controlling Interests - Earnings of Subsidiaries with Non-Controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of subsidiaries [line items]
Revenues	$ 2,976	$ 2,721	$ 2,101
Net earnings (loss)	161	(425)	(253)
Total comprehensive income (loss)	(263)	(610)	(355)
Amounts attributable to the non-controlling interests:
Net earnings (loss)	111	112	34
Total comprehensive income (loss)	55	83	84
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Revenues	560	470	436
Net earnings (loss)	74	139	97
Total comprehensive income (loss)	(67)	66	223
Amounts attributable to the non-controlling interests:
Net earnings (loss)	20	50	40
Total comprehensive income (loss)	(36)	21	90
Dividends paid to non-controlling interests	100	100	80
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Revenues	347	265	146
Net earnings (loss)	143	103	(13)
Total comprehensive income (loss)	143	103	(13)
Amounts attributable to the non-controlling interests:
Net earnings (loss)	91	62	(6)
Total comprehensive income (loss)	91	62	(6)
Dividends paid to non-controlling interests	$ 87	$ 56	$ 17

Non-Controlling Interests - Fin

Non-Controlling Interests - Financial Position of Non-Controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of subsidiaries [line items]
Current assets	$ 3,714	$ 2,197
Current liabilities	(2,888)	(1,931)
Total equity	1,989	2,593	$ 3,436
Non-controlling interests	879	1,011
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Current assets	240	430
Long-term assets	2,989	3,319
Current liabilities	(306)	(593)
Long-term liabilities	(1,118)	(1,033)
Total equity	(1,805)	(2,123)
Non-controlling interests	$ (732)	$ (869)
Non-controlling interests’ share (per cent)	39.90%	39.90%
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Current assets	$ 127	$ 66
Long-term assets	253	312
Current liabilities	(62)	(52)
Long-term liabilities	(27)	(36)
Total equity	(291)	(290)
Non-controlling interests	$ (147)	$ (142)
Non-controlling interests’ share (per cent)	49.99%	49.99%

Trade and Other Receivables (De

Trade and Other Receivables (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Subclassifications of assets, liabilities and equities [abstract]
Trade accounts receivable	$ 1,165	$ 499
Collateral provided	304	55
Current portion of finance lease receivables	52	40
Loan receivable	4	55
Income taxes receivable	64	2
Trade and other receivables	1,589	651
Accounts payable and accrued liabilities	1,069	654
Interest payable	17	17
Collateral held	260	18
Accounts payable and accrued liabilities	$ 1,346	$ 689

Financial Instruments - Carryin

Financial Instruments - Carrying Amounts and Classifications of Financial Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	$ 3,653	$ 3,267
Cash equivalents	0	0
Bank overdraft
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	16
Bank overdraft | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	16
Accounts payable and accrued liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	1,346	689
Accounts payable and accrued liabilities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	1,346	689
Dividends payable
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	68	62
Dividends payable | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	68	62
Credit facilities, long-term debt and lease liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,653	3,267
Credit facilities, long-term debt and lease liabilities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,653	3,267
Exchangeable securities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	739	735
Exchangeable securities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	739	735
Within one year | Risk management liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	1,129	261
Within one year | Derivatives | Risk management liabilities | Derivatives used for hedging
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	271	0
Within one year | Derivatives | Risk management liabilities | Derivatives held for trading (FVTPL)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	858	261
Later than one year | Risk management liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	333	145
Later than one year | Derivatives | Risk management liabilities | Derivatives used for hedging
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	76	0
Later than one year | Derivatives | Risk management liabilities | Derivatives held for trading (FVTPL)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	257	145
Cash and cash equivalents
Disclosure of detailed information about financial instruments [line items]
Financial assets	1,134	947
Cash and cash equivalents | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	1,134	947
Restricted cash
Disclosure of detailed information about financial instruments [line items]
Financial assets	70	70
Restricted cash | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	70	70
Trade and other receivables
Disclosure of detailed information about financial instruments [line items]
Financial assets	1,589	651
Trade and other receivables | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	1,589	651
Long-term portion of finance lease receivables
Disclosure of detailed information about financial instruments [line items]
Financial assets	129	185
Long-term portion of finance lease receivables | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	129	185
Long-term portion of loan receivable
Disclosure of detailed information about financial instruments [line items]
Financial assets	33
Long-term portion of loan receivable | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	33
Other investments
Disclosure of detailed information about financial instruments [line items]
Financial assets	12
Other investments | Other financial assets (FVTPL)
Disclosure of detailed information about financial instruments [line items]
Financial assets	11
Other investments | Other financial assets (FVTOCI)
Disclosure of detailed information about financial instruments [line items]
Financial assets	1
Risk management assets | Within one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	709	308
Risk management assets | Later than one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	161	399
Risk management assets | Derivatives used for hedging | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	0	36
Risk management assets | Derivatives used for hedging | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	0	252
Risk management assets | Derivatives held for trading (FVTPL) | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	709	272
Risk management assets | Derivatives held for trading (FVTPL) | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	$ 161	$ 147

Financial Instruments - Narrati

Financial Instruments - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) MW	Apr. 05, 2022 MW	Dec. 31, 2021 CAD ($) MW	Dec. 31, 2020 CAD ($)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	$ 3,653		$ 3,267
Decrease in base fair value	(21)
Increase in sensitivity values	$ 9
Other
Disclosure of detailed information about financial instruments [line items]
Commodity risk management assets and liabilities			$ 8
Garden Plain Wind Project
Disclosure of detailed information about financial instruments [line items]
Capacity of facility (in megawatts) | MW	130
Weighted average extension period (in years)	17 years
Long-term wind energy sale – Eastern US
Disclosure of detailed information about financial instruments [line items]
Membership interest	100%
Capacity of facility (in megawatts) | MW	90
Long-term wind energy sale – Canada
Disclosure of detailed information about financial instruments [line items]
Membership interest	100%
Long-term wind energy sale - Central US
Disclosure of detailed information about financial instruments [line items]
Membership interest	100%	100%
White Rock East And White Rock West Wind Power Projects
Disclosure of detailed information about financial instruments [line items]
Capacity of facility (in megawatts) | MW			300
Horizon Hill Wind Project
Disclosure of detailed information about financial instruments [line items]
Capacity of facility (in megawatts) | MW		200
Pembina | Long-term wind energy sale – Canada
Disclosure of detailed information about financial instruments [line items]
Membership interest			37.70%
Maximum | Fixed-price contracts
Disclosure of detailed information about financial instruments [line items]
Capacity long-term fixed price power sale | MW	380
Minimum | Fixed-price contracts
Disclosure of detailed information about financial instruments [line items]
Capacity long-term fixed price power sale | MW	300
Level I | Recurring fair value measurement
Disclosure of detailed information about financial instruments [line items]
Commodity risk management assets and liabilities	$ 23		$ 12
Level II | Recurring fair value measurement
Disclosure of detailed information about financial instruments [line items]
Commodity risk management assets and liabilities	173		122
Level III | Recurring fair value measurement
Disclosure of detailed information about financial instruments [line items]
Commodity risk management assets and liabilities	(782)		159	$ 582
Level III | Recurring fair value measurement | Other
Disclosure of detailed information about financial instruments [line items]
Commodity risk management assets and liabilities	(6)		8
Level III | Recurring fair value measurement | Financial liabilities at fair value through profit or loss, category
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	813		146
Level III | Recurring fair value measurement | FVTPL
Disclosure of detailed information about financial instruments [line items]
Financial assets	$ 31		$ 305

Financial Instruments - Fair Va

Financial Instruments - Fair Value of the Commodity Risk Management Assets and Liabilities by Classification Level (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of risk management strategy related to hedge accounting [line items]
Change in foreign exchange rates	$ 4	$ 16	$ 17
Losses recognized in other comprehensive loss	126	(8)	(141)
Total gains (losses) included in earnings (loss) before income taxes	(694)	(255)	28
Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Commodity risk management assets and liabilities	(782)	159	582
Market price changes	80	(112)
Change in foreign exchange rates	12	0
Non-recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Losses recognized in other comprehensive loss	(594)	(181)
Total gains (losses) included in earnings (loss) before income taxes	(389)	(23)
Unrealized gains (losses) included in earnings (loss) before income taxes relating to net assets held at year end	(309)	(135)
Hedge | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Commodity risk management assets and liabilities	(347)	285	573
Market price changes	(38)	(107)
Change in foreign exchange rates	17	0
Hedge | Non-recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Losses recognized in other comprehensive loss	(594)	(181)
Total gains (losses) included in earnings (loss) before income taxes	38	107
Unrealized gains (losses) included in earnings (loss) before income taxes relating to net assets held at year end	0	0
Non-hedge | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Commodity risk management assets and liabilities	(435)	(126)	$ 9
Market price changes	118	(5)
Change in foreign exchange rates	(5)	0
Non-hedge | Non-recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Losses recognized in other comprehensive loss	0	0
Total gains (losses) included in earnings (loss) before income taxes	(427)	(130)
Unrealized gains (losses) included in earnings (loss) before income taxes relating to net assets held at year end	(309)	(135)
Market price changes on existing contracts | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(909)	(177)
Market price changes on existing contracts | Hedge | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(611)	(181)
Market price changes on existing contracts | Non-hedge | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(298)	4
Market price changes on new contracts | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(124)	(134)
Market price changes on new contracts | Hedge | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	0	0
Market price changes on new contracts | Non-hedge | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	$ (124)	$ (134)

Financial Instruments - Sensiti

Financial Instruments - Sensitivity Ranges for the Base Fair Values (Details)	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)
Full requirements – Eastern US | Cost of supply
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible				$ 1
Forward contract | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ (6)		6
Fixed-price contracts | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		(2)
Minimum | Long-term power sale – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 163,000,000		$ 145,000,000
Increase (decrease) in derivative future power prices, reasonable possible		(5)		$ (3)
Minimum | Coal transportation – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 13,000,000		$ 18,000,000
Minimum | Coal transportation – US | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in rail rate escalation expressed as a percentage			0	0
Minimum | Coal transportation – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ (5)
Minimum | Coal transportation – US | Long-term contracts | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in rail rate escalation expressed as a percentage	0	0
Minimum | Coal transportation – US | Long-term contracts | US | Volatility
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	0.80	0.80	0.80	0.80
Minimum | Full requirements – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 21,000,000		$ (9,000,000)
Minimum | Full requirements – Eastern US | Cost of supply
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ (0.50)
Minimum | Full requirements – Eastern US | US | Volume
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	0.96	0.96	0.95	0.95
Minimum | Long-term wind energy sale – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 18,000,000		$ 16,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	0%	0%
Minimum | Long-term wind energy sale – Canada
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 25,000,000		$ 11,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	28%	28%	(5.00%)	(5.00%)
Minimum | Long-term wind energy sale – Canada | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible	$ 85		$ (24)
Minimum | Long-term wind energy sale - Central US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 28,000,000		$ 15,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	2%	2%	(3.00%)	(3.00%)
Minimum | Long-term wind energy sale - Central US | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible				$ (2)
Minimum | Others
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 19,000,000		$ 6,000,000
Minimum | Fixed-price contracts | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible				(3)
Maximum | Long-term power sale – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	15,000,000		22,000,000
Increase (decrease) in derivative future power prices, reasonable possible		$ 55		$ 20
Maximum | Coal transportation – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 14,000,000		$ 3,000,000
Maximum | Coal transportation – US | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in rail rate escalation expressed as a percentage			0.04	0.04
Maximum | Coal transportation – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ 55
Maximum | Coal transportation – US | Long-term contracts | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in rail rate escalation expressed as a percentage	0.10	0.10
Maximum | Coal transportation – US | Long-term contracts | US | Volatility
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	1.20	1.20	1.20	1.20
Maximum | Full requirements – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 3,000,000		$ 9,000,000
Maximum | Full requirements – Eastern US | Cost of supply
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ 3.30
Maximum | Full requirements – Eastern US | US | Volume
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	1.04	1.04	1.05	1.05
Maximum | Long-term wind energy sale – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 22,000,000		$ 17,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	5%	5%
Maximum | Long-term wind energy sale – Canada
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 47,000,000		$ 21,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	5%	5%	5%	5%
Maximum | Long-term wind energy sale – Canada | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible	$ (5)		$ (5)
Maximum | Long-term wind energy sale - Central US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 74,000,000		$ 27,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	5%	5%	3%	3%
Maximum | Long-term wind energy sale - Central US | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible		$ (2)		$ (3)
Maximum | Others
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity	$ 18,000,000		$ 6,000,000
Maximum | Fixed-price contracts | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in derivative future power prices, reasonable possible				$ 2

Financial Instruments - Fair _2

Financial Instruments - Fair Value of Financial Assets and Liabilities Measured at Other than Fair Value (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	$ 3,653	$ 3,267
FVTPL | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	37	55
Long-term debt
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,518	3,167
Exchangeable securities
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	739	735
Recurring fair value measurement | FVTPL | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	37	55
Recurring fair value measurement | Long-term debt | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,200	3,272
Recurring fair value measurement | Exchangeable securities | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	685	770
Recurring fair value measurement | Level I | FVTPL | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	0	0
Recurring fair value measurement | Level I | Long-term debt | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	0	0
Recurring fair value measurement | Level I | Exchangeable securities | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	0	0
Recurring fair value measurement | Level II | FVTPL | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	37	55
Recurring fair value measurement | Level II | Long-term debt | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,200	3,272
Recurring fair value measurement | Level II | Exchangeable securities | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	685	770
Recurring fair value measurement | Level III | FVTPL
Disclosure of fair value measurement of liabilities [line items]
Financial assets	31	305
Recurring fair value measurement | Level III | FVTPL | Amortized cost
Disclosure of fair value measurement of liabilities [line items]
Financial assets	0	0
Recurring fair value measurement | Level III | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	813	146
Recurring fair value measurement | Level III | Long-term debt | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	0	0
Recurring fair value measurement | Level III | Exchangeable securities | Financial liabilities at fair value through profit or loss, category
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	$ 0	$ 0

Financial Instruments - Incepti

Financial Instruments - Inception Gains And Losses (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Changes in aggregate difference between fair value at initial recognition and transaction price yet to be recognised in profit or loss [abstract]
Unamortized net gain (loss) at beginning of year	$ (131)	$ (33)	$ 9
New inception loss	(37)	(79)	(13)
Changes in foreign exchange rates	(10)	0	0
Amortization recorded in net earnings during the year	(35)	(19)	(29)
Unamortized net loss at end of year	$ (213)	$ (131)	$ (33)

Risk Management Activities - Ne

Risk Management Activities - Net Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	$ (592)
Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		$ 293
Commodity risk management | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(586)
Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		8
Other | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(6)
Current | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(414)	45
Current | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(6)	2
Long-term | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(172)	248
Long-term | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	0	6
Financial Assets
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		301
Cash flow hedges | Cash flow hedges | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(347)
Cash flow hedges | Cash flow hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		285
Cash flow hedges | Cash flow hedges | Commodity risk management | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(347)
Cash flow hedges | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		3
Cash flow hedges | Cash flow hedges | Other | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	0
Cash flow hedges | Current | Cash flow hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(271)	33
Cash flow hedges | Current | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	0	3
Cash flow hedges | Long-term | Cash flow hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(76)	252
Cash flow hedges | Long-term | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	0	0
Cash flow hedges | Financial Assets | Cash flow hedges
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		288
Not designated as a hedge | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(245)
Not designated as a hedge | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		8
Not designated as a hedge | Commodity risk management | Long-term risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(96)	(4)
Not designated as a hedge | Commodity risk management | Current risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(143)
Not designated as a hedge | Commodity risk management | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(239)
Not designated as a hedge | Other | Long-term risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		6
Not designated as a hedge | Other | Current risk management liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		(1)
Not designated as a hedge | Other | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(6)	5
Not designated as a hedge | Current | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		12
Not designated as a hedge | Current | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	(6)
Not designated as a hedge | Long-term | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities	$ 0
Not designated as a hedge | Financial Assets
Disclosure of nature and extent of risks arising from financial instruments [line items]
Commodity risk management assets and liabilities		$ 13

Risk Management Activities - _2

Risk Management Activities - Netting Arrangements (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current risk management liabilities
Disclosure of financial liabilities [abstract]
Gross amounts of recognized financial liabilities	$ (1,953)	$ (529)
Amounts set off	883	307
Net amounts presented on the statement of financial position	(1,033)	(211)
Master netting arrangements	62	92
Net amount	(971)	(119)
Long-term risk management liabilities
Disclosure of financial liabilities [abstract]
Gross amounts of recognized financial liabilities	(449)	(89)
Amounts set off	43	16
Net amounts presented on the statement of financial position	(402)	(70)
Master netting arrangements	7	23
Net amount	(395)	(47)
Accounts payable and accrued liabilities
Disclosure of financial liabilities [abstract]
Gross amounts of recognized financial liabilities	(1,344)	(689)
Amounts set off	934	571
Net amounts presented on the statement of financial position	(411)	(118)
Master netting arrangements	176	35
Net amount	(235)	(83)
Current risk management assets
Disclosure of financial assets [abstract]
Gross amounts of recognized financial assets	1,602	636
Amounts set off	(883)	(307)
Net amounts presented on the statement of financial position	688	316
Master netting arrangements	(62)	(92)
Net amount	626	224
Long-term risk management assets
Disclosure of financial assets [abstract]
Gross amounts of recognized financial assets	204	285
Amounts set off	(43)	(16)
Net amounts presented on the statement of financial position	157	260
Master netting arrangements	(7)	(23)
Net amount	150	237
Trade and other receivables
Disclosure of financial assets [abstract]
Gross amounts of recognized financial assets	1,330	699
Amounts set off	(934)	(571)
Net amounts presented on the statement of financial position	396	128
Master netting arrangements	(176)	(35)
Net amount	$ 220	$ 93

Risk Management Activities - Ad

Risk Management Activities - Additional Information (Details) $ in Millions			12 Months Ended
	Oct. 26, 2022 USD ($)	Oct. 25, 2022 USD ($)	Dec. 31, 2022 CAD ($) agency agreement	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2022 USD ($) agency	Dec. 31, 2021 USD ($)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Floating interest rates			15%	3%		15%	3%
Outstanding credit facilities			$ 449,000,000	$ (114,000,000)	$ (106,000,000)
Target percentage, four year period			60%
Target percentage, current period			90%
Target percentage, next year			70%
Target percentage, third year			50%
Target percentage, fourth year			30%
Sensitivity analysis average			$ 0.03	0.03	0.03
Maximum credit exposure			$ 64,000,000	37,000,000
Number of credit rating agency | agency			1			1
Debt maturing			$ 839,000,000
After-tax gain reclassified from AOCI to net earnings			(460,000,000)	(222,000,000)	(90,000,000)
Net unrealized gain			384,000,000	97,000,000	43,000,000
Gains on foreign exchange and other derivatives			20,000,000	6,000,000	11,000,000
Unrealised Gains On Change In Fair Value Of Derivatives			11,000,000	4,000,000
Unrealised loss on foreign exchange and other derivatives					(2,000,000)
Net realized gains on foreign exchange and other derivatives			31,000,000	2,000,000	13,000,000
Collateral provided			304,000,000	55,000,000
Cash collateral			260,000,000	18,000,000
Additional collateral requirement			$ 656,000,000	120,000,000
Number Of Below Investment Grade Ratings From Credit Rating Agencies | agency			2			2
Recourse Debt
Disclosure of nature and extent of risks arising from financial instruments [line items]
Debt maturing			$ 400,000,000
Letter of credit
Disclosure of nature and extent of risks arising from financial instruments [line items]
Collateral posted on derivative liabilities			820,000,000	356,000,000
Within one year
Disclosure of nature and extent of risks arising from financial instruments [line items]
After-tax gain reclassified from AOCI to net earnings			$ (208,000,000)
Long-term debt | Net investment hedges
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount						$ 370	$ 370
Interest rate swap
Disclosure of nature and extent of risks arising from financial instruments [line items]
Number of agreements | agreement			2
Outstanding credit facilities			$ 433,000,000	0
Bond Lock Agreement
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount							$ 150
Commodity Price Risk - Proprietary Trading
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk			4,000,000	2,000,000	1,000,000
Commodity Price Risk - Generation
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk			97,000,000	33,000,000	12,000,000
Commodity Price Risk - Generation - Mark To Market Value
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk			54,000,000	51,000,000	15,000,000
Commodity Price Risk - Generation - virtual PPAs
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk			26,000,000	14,000,000	$ 3,000,000
Interest rate risk | Interest rate swap
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount	$ 100	$ 100				$ 150
Interest rate risk | Interest rate swap | Fixed Blended Rate
Disclosure of nature and extent of risks arising from financial instruments [line items]
Fixed interest rate	470%	470%
Interest rate risk | TAPC Holdings LP bond (Poplar Creek)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount			95,000,000	$ 104,000,000
Commodity risk management | Cash flow hedges
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk			$ 0

Risk Management Activities - Co

Risk Management Activities - Commodity Derivative Instruments Not Designated as Hedging Instruments (Details) - Non-hedge - Commodity risk management	Dec. 31, 2022 MWh J t	Dec. 31, 2021 MWh J t
Electricity
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	55,821,000	46,139,000
Notional amount purchased	13,934,000	14,951,000
Natural gas (GJ)
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold | J	23,464,000	7,501,000
Notional amount purchased | J	162,384,000	173,898,000
Transmission (MWh)
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	0	37,000
Notional amount purchased	1,643,000	1,097,000
Emissions
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	274,000	445,000
Notional amount purchased	2,297,000	2,030,000
Notional amount sold | t	300,000	350,000
Notional amount purchased | t	300,000	350,000
Coal (tonnes)
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold | t	0	0
Notional amount purchased | t	7,746,000	9,352,000

Risk Management Activities - No

Risk Management Activities - Non-Hedges (Details) $ in Millions, $ in Millions, $ in Millions	Dec. 31, 2022 AUD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 AUD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)
Disclosure of detailed information about hedges [line items]
Fair value asset		$ 3			$ 2
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2026, Contract One
Disclosure of detailed information about hedges [line items]
Fair value liability		(1)
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2025, Contract Two
Disclosure of detailed information about hedges [line items]
Fair value asset		(12)
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023
Disclosure of detailed information about hedges [line items]
Fair value asset		4
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022-2025, Contract One
Disclosure of detailed information about hedges [line items]
Fair value liability					(5)
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022-2025, Contract Two
Disclosure of detailed information about hedges [line items]
Fair value asset					8
Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2022
Disclosure of detailed information about hedges [line items]
Fair value asset		3			1
AUD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2026, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount sold	$ 183
AUD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023
Disclosure of detailed information about hedges [line items]
Notional amount purchased		102
AUD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022-2025, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount sold				$ 28
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2026, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount purchased		168
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2025, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount purchased		761
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022-2025, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount purchased					26
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022-2025, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount purchased					357
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2022
Disclosure of detailed information about hedges [line items]
Notional amount sold		$ 159			$ 191
USD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023-2025, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount sold			$ 573
USD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2023
Disclosure of detailed information about hedges [line items]
Notional amount sold			66
USD | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022-2025, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount sold						$ 271
USD | Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2022
Disclosure of detailed information about hedges [line items]
Notional amount purchased			$ 120			$ 150

Risk Management Activities - Im

Risk Management Activities - Impacts of currency rate risk (Details) - Currency risk - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of credit risk exposure [line items]
Net earnings increase (decrease)	$ (14)	$ (12)	$ (12)
OCI gain	0	1	1
USD
Disclosure of credit risk exposure [line items]
Net earnings increase (decrease)	(12)	(13)	(8)
OCI gain	0	1	1
AUD
Disclosure of credit risk exposure [line items]
Net earnings increase (decrease)	(2)	1	(4)
OCI gain	$ 0	$ 0	$ 0

Risk Management Activities - Ma

Risk Management Activities - Maximum Exposure to Credit Risk (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of credit risk exposure [line items]
Maximum credit exposure	$ 64	$ 37
Credit risk
Disclosure of credit risk exposure [line items]
Maximum credit exposure	2,621
Credit risk | Trade and other receivables
Disclosure of credit risk exposure [line items]
Maximum credit exposure	$ 1,585
Trade and other receivables | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100%
Maximum credit exposure	$ 4
Trade and other receivables | Investment grade (Per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	87%
Trade and other receivables | Non-investment grade (Per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	13%
Long-term portion of finance lease receivables | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100%
Maximum credit exposure	$ 129
Long-term portion of finance lease receivables | Investment grade (Per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100%
Long-term portion of finance lease receivables | Non-investment grade (Per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	0%
Risk management assets | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100%
Maximum credit exposure	$ 870
Risk management assets | Investment grade (Per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	92%
Risk management assets | Non-investment grade (Per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	8%
Loan receivable | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100%
Maximum credit exposure	$ 37
Loan receivable | Investment grade (Per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	0%
Loan receivable | Non-investment grade (Per cent) | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100%

Risk Management Activities - _3

Risk Management Activities - Maturity Analysis of Financial Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	$ 16	$ 0
Accounts payable and accrued liabilities	1,346	689
Principal repayments	3,653	3,267
Exchangeable securities	739	735
Dividends payable	68	62
Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	1	$ 4
2023
Disclosure of maturity analysis for derivative financial liabilities [line items]
Lease incentive	12
Cost
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	16
Accounts payable and accrued liabilities	1,346
Principal repayments	3,563
Exchangeable securities	750
Other risk management (assets) liabilities	(6)
Lease liabilities	135
Interest expense on borrowings	1,707
Dividends payable	68
Total	8,291
Cost | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	433
Cost | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	251
Cost | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	949
Cost | Non-recourse — Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	45
Cost | Non-recourse — Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	698
Cost | Non-recourse — Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	1,057
Cost | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	129
Cost | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	1
Cost | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	114
Cost | Commodity risk management (assets) liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management (assets) liabilities	586
Cost | 2023
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	16
Accounts payable and accrued liabilities	1,346
Principal repayments	170
Exchangeable securities	0
Other risk management (assets) liabilities	(7)
Lease liabilities	(7)
Interest expense on borrowings	205
Dividends payable	68
Total	2,272
Cost | 2023 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2023 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2023 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2023 | Non-recourse — Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	45
Cost | 2023 | Non-recourse — Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	63
Cost | 2023 | Non-recourse — Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	45
Cost | 2023 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	16
Cost | 2023 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	1
Cost | 2023 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	52
Cost | 2023 | Commodity risk management (assets) liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management (assets) liabilities	415
Cost | 2024
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	527
Exchangeable securities	0
Other risk management (assets) liabilities	1
Lease liabilities	4
Interest expense on borrowings	192
Dividends payable	0
Total	966
Cost | 2024 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	400
Cost | 2024 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2024 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2024 | Non-recourse — Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2024 | Non-recourse — Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	66
Cost | 2024 | Non-recourse — Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	46
Cost | 2024 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	15
Cost | 2024 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2024 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	62
Cost | 2024 | Commodity risk management (assets) liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management (assets) liabilities	182
Cost | 2025
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	142
Exchangeable securities	750
Other risk management (assets) liabilities	(1)
Lease liabilities	4
Interest expense on borrowings	166
Dividends payable	0
Total	1,021
Cost | 2025 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2025 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2025 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2025 | Non-recourse — Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2025 | Non-recourse — Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	69
Cost | 2025 | Non-recourse — Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	58
Cost | 2025 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	15
Cost | 2025 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2025 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	0
Cost | 2025 | Commodity risk management (assets) liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management (assets) liabilities	(42)
Cost | 2026
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	177
Exchangeable securities	0
Other risk management (assets) liabilities	0
Lease liabilities	3
Interest expense on borrowings	158
Dividends payable	0
Total	353
Cost | 2026 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	33
Cost | 2026 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2026 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2026 | Non-recourse — Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2026 | Non-recourse — Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	67
Cost | 2026 | Non-recourse — Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	61
Cost | 2026 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	16
Cost | 2026 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2026 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	0
Cost | 2026 | Commodity risk management (assets) liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management (assets) liabilities	15
Cost | 2027
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	154
Exchangeable securities	0
Other risk management (assets) liabilities	0
Lease liabilities	4
Interest expense on borrowings	150
Dividends payable	0
Total	316
Cost | 2027 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2027 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2027 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2027 | Non-recourse — Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2027 | Non-recourse — Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	70
Cost | 2027 | Non-recourse — Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	65
Cost | 2027 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	19
Cost | 2027 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2027 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	0
Cost | 2027 | Commodity risk management (assets) liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management (assets) liabilities	8
Cost | 2028
Disclosure of maturity analysis for derivative financial liabilities [line items]
Bank overdraft	0
Accounts payable and accrued liabilities	0
Principal repayments	2,393
Exchangeable securities	0
Other risk management (assets) liabilities	1
Lease liabilities	127
Interest expense on borrowings	836
Dividends payable	0
Total	3,363
Cost | 2028 | Credit Facilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2028 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	251
Cost | 2028 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	949
Cost | 2028 | Non-recourse — Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2028 | Non-recourse — Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	363
Cost | 2028 | Non-recourse — Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	782
Cost | 2028 | Tax equity financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	48
Cost | 2028 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Principal repayments	0
Cost | 2028 | Interest on exchangeable securities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	0
Cost | 2028 | Commodity risk management (assets) liabilities
Disclosure of maturity analysis for derivative financial liabilities [line items]
Commodity risk management (assets) liabilities	$ 8

Risk Management Activities - _4

Risk Management Activities - Maturity of Non-Hedges (Details) - Dec. 31, 2022 - Electricity - Non-hedge - Commodity risk management	CAD ($)	cADPerMegawattHour
2023
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 3,329
Average prices | cADPerMegawattHour		cADPerMegawattHour 78.27
2024
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	3,338
Average prices | cADPerMegawattHour		80.22
2025
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	2,628
Average prices | cADPerMegawattHour		82.22
2026
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	0
Average prices | cADPerMegawattHour		0
2027
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	0
Average prices | cADPerMegawattHour		0
2028 and thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 0
Average prices | cADPerMegawattHour		cADPerMegawattHour 0

Risk Management Activities - Ef

Risk Management Activities - Effect of Hedges (Details) MWh in Thousands, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 USD ($) MWh	Dec. 31, 2022 CAD ($) MWh	Dec. 31, 2021 USD ($) MWh	Dec. 31, 2021 CAD ($) MWh
Disclosure of detailed information about hedging instruments [line items]
Fair value asset				$ 3		$ 2
Physical power sales | Cash flow hedges | Commodity risk management
Disclosure of detailed information about hedging instruments [line items]
Notional amount (MMWH) | MWh			9,295	9,295	12,624	12,624
Fair value asset						$ 285
Fair value liability				$ (347)
Change in fair value used for measuring ineffectiveness	$ (594)	$ (181)
Interest rate swap | Cash flow hedges | Interest rate risk | USD
Disclosure of detailed information about hedging instruments [line items]
Notional amount					$ 300
Fair value asset						3
Change in fair value used for measuring ineffectiveness		3
Foreign-Denominated Expenditures | Cash flow hedges | Interest rate risk | USD | Minimum
Disclosure of detailed information about hedging instruments [line items]
Notional amount					8
Fair value asset						0
Change in fair value used for measuring ineffectiveness		0
Foreign-Denominated Expenditures | Cash flow hedges | Interest rate risk | USD | Maximum
Disclosure of detailed information about hedging instruments [line items]
Notional amount					14
Fair value asset						0
Change in fair value used for measuring ineffectiveness		0
Foreign-denominated debt | Net Investment Hedge | Currency risk
Disclosure of detailed information about hedging instruments [line items]
Fair value asset				$ 502		$ 473
Change in fair value used for measuring ineffectiveness	$ 0	$ 0
Foreign-denominated debt | Net Investment Hedge | Currency risk | USD
Disclosure of detailed information about hedging instruments [line items]
Notional amount			$ 370		$ 370

Risk Management Activities - He

Risk Management Activities - Hedged Items on the Statement of Financial Position (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about hedging instruments [line items]
Carrying amount	$ 3	$ 2
Physical power sales | Cash flow hedges | Commodity risk management
Disclosure of detailed information about hedging instruments [line items]
Carrying amount		285
Hedging instrument, liabilities	(347)
Change in fair value used for measuring ineffectiveness	(594)	(181)
Reserve of cash flow hedges	(279)	226
Interest Expense On Long-Term Debt | Cash flow hedges | Interest rate risk
Disclosure of detailed information about hedging instruments [line items]
Change in fair value used for measuring ineffectiveness	0	3
Reserve of cash flow hedges	0	2
Foreign-denominated debt | Net Investment Hedge | Currency risk
Disclosure of detailed information about hedging instruments [line items]
Carrying amount	502	473
Change in fair value used for measuring ineffectiveness	0	0
Reserve of cash flow hedges	$ (39)	$ (35)

Risk Management Activities - _5

Risk Management Activities - Impact of Hedged Items Designated in Hedging Relationships on OCI and Net Earnings (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about hedging instruments [line items]
Derivatives in cash flow  hedging relationships	$ (694)	$ (255)	$ 28
Location of (gain)loss reclassified from OCI	126	(8)	(141)
Location of (gain) loss reclassified from OCI	0	0	0
Commodity contracts
Disclosure of detailed information about hedging instruments [line items]
Derivatives in cash flow  hedging relationships	(747)	(268)	41
Commodity contracts | Revenue
Disclosure of detailed information about hedging instruments [line items]
Location of (gain)loss reclassified from OCI	124	(13)	(137)
Location of (gain) loss reclassified from OCI	0	0	0
Foreign exchange forwards on project hedges
Disclosure of detailed information about hedging instruments [line items]
Derivatives in cash flow  hedging relationships		0	(1)
Foreign exchange forwards on project hedges | Property, plant and equipment
Disclosure of detailed information about hedging instruments [line items]
Location of (gain)loss reclassified from OCI		1	0
Location of (gain) loss reclassified from OCI		0
Forward starting interest rate swaps
Disclosure of detailed information about hedging instruments [line items]
Derivatives in cash flow  hedging relationships	53	13	(12)
Forward starting interest rate swaps | Interest expense
Disclosure of detailed information about hedging instruments [line items]
Location of (gain)loss reclassified from OCI	2	4	(4)
Location of (gain) loss reclassified from OCI	$ 0	$ 0	$ 0

Inventory Components of Invento

Inventory Components of Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of inventories [Abstract]
Parts, materials and supplies	$ 83	$ 82
Coal	43	27
Emission credits	27	55
Natural gas	4	3
Total	$ 157	$ 167

Inventory - Narrative (Details)

Inventory - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) emissionCredit	Dec. 31, 2021 CAD ($) emissionCredit
Analysis of income and expenses [Line Items]
Emission credits | emissionCredit	963,068	2,033,752
Purchased emission credits | $	$ 27	$ 55
Emission credits in inventory | emissionCredit	1,869,450	1,922,973
Emission credits utilized | emissionCredit	1,169,333
Carrying value | $	$ 35
Carbon compliance obligation settlement | $	47
Carbon compliance costs | $	$ 12
Hydro Power Purchase Arrangement
Analysis of income and expenses [Line Items]
Emission credits | emissionCredit	1,750,000

Finance Lease Receivables (Deta

Finance Lease Receivables (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	$ 203	$ 265
Present value of minimum lease receipts	181	225
Less: unearned finance lease income	22	40
Less: unearned finance lease income	0	0
Total finance lease receivables	181	225
Current portion of finance lease receivables	52	40
Long-term portion of finance lease receivables	129	185
Within one year
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	62	58
Present value of minimum lease receipts	55	54
Second to fifth years inclusive
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	81	127
Present value of minimum lease receipts	75	105
More than five years
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	60	80
Present value of minimum lease receipts	$ 51	$ 66

Assets Held for Sale - Disclosu

Assets Held for Sale - Disclosure of Change in Assets Held for Sale (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Change in Assets Held for Sale [Roll Forward]
Beginning of the period	$ 25	$ 105
Transfers from property, plant and equipment	28	25
Disposals	(31)	(105)
End of the period	$ 22	$ 25

Assets Held for Sale - Narrativ

Assets Held for Sale - Narrative (Details) $ in Millions					12 Months Ended
	Dec. 02, 2022 CAD ($)	Nov. 07, 2022 CAD ($)	Jun. 30, 2021 CAD ($)	Oct. 01, 2020	Dec. 31, 2022 CAD ($) asset	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)
Investment [Line Items]
Proceeds on sale of Pioneer Pipeline					$ 0	$ 128	$ 0
Gain on sale of assets and other					52	54	$ 9
Transfers from property, plant and equipment					$ (29)	(1)
Pipeline
Investment [Line Items]
Aggregate consideration			$ 255
Membership interest			50%
Proceeds on sale of Pioneer Pipeline			$ 128
Gain on sale of assets and other			31
Gains on lease liability			$ 2
Gas
Investment [Line Items]
Transfers from property, plant and equipment						$ 25
Creeks
Investment [Line Items]
Proceeds on sale of Pioneer Pipeline		$ 45
Gain on sale of assets and other		$ 20
Hydro
Investment [Line Items]
Gain on sale of assets and other	$ 2
Proceeds from sale of assets held for sale	$ 6
Number of assets | asset					2
Kaybob Cogeneration Project
Investment [Line Items]
Transfers from property, plant and equipment					$ 22
Tidewater | Pioneer Pipeline
Investment [Line Items]
Proportion of ownership interest in joint operation				50%

Property, Plant, and Equipmen_2

Property, Plant, and Equipment - Reconciliation of the Changes in the Carrying Amount of PP&E (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	$ 5,320	$ 5,822
Additions	29	15
Disposals	5
Transfer of assets	(29)	(1)
End of the period	5,556	5,320
Other work performed by entity and capitalised	$ 16	$ 14
Weighted average rate	6%	6%
Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	$ 13,389	$ 13,398
Additions	897	479
Additions from development projects	29	1
Acquisitions		146
Disposals	220	79
Impairment (charges) reversals	(62)	(589)
Retirement of assets	(39)	(121)
Change in foreign exchange rates	153	(27)
Transfer of assets	(6)	(2)
Transfers in (out) of PP&E	(24)	42
End of the period	14,012	13,389
Cost | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	(31)	6
Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(8,069)	(7,576)
Depreciation	538	614
Disposals	(212)	(73)
Retirement of assets	33	112
Change in foreign exchange rates	102	(7)
Transfers in (out) of PP&E	(5)	40
End of the period	(8,456)	(8,069)
Accumulated depreciation | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	(3)	31
Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	184	495
End of the period	963	184
Assets under construction | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	184	495
Additions	891	477
Additions from development projects	17	1
Acquisitions		0
Disposals	0	2
Impairment (charges) reversals	2	(91)
Retirement of assets	0	0
Change in foreign exchange rates	13	0
Transfer of assets	(138)	(676)
Transfers in (out) of PP&E	16	5
End of the period	963	184
Assets under construction | Cost | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	(22)	(25)
Assets under construction | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	0	0
Depreciation	0	0
Disposals	0	0
Retirement of assets	0	0
Change in foreign exchange rates	0	0
Transfers in (out) of PP&E	0	0
End of the period	0	0
Assets under construction | Accumulated depreciation | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	0
Land
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	96	96
End of the period	93	96
Land | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	96	96
Additions	0	0
Additions from development projects	0	0
Acquisitions		0
Disposals	3	1
Impairment (charges) reversals	0	0
Retirement of assets	0	0
Change in foreign exchange rates	0	0
Transfer of assets	0	1
Transfers in (out) of PP&E	0	0
End of the period	93	96
Land | Cost | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	0
Land | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	0	0
Depreciation	0	0
Disposals	0	0
Retirement of assets	0	0
Change in foreign exchange rates	0	0
Transfers in (out) of PP&E	0	0
End of the period	0	0
Land | Accumulated depreciation | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	0
Hydro
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	399	399
End of the period	362	399
Hydro | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	867	846
Additions	0	0
Additions from development projects	0	0
Acquisitions		0
Disposals	0	0
Impairment (charges) reversals	(21)	(3)
Retirement of assets	(9)	(4)
Change in foreign exchange rates	0	0
Transfer of assets	27	27
Transfers in (out) of PP&E	0	0
End of the period	840	867
Hydro | Cost | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	(9)	0
Hydro | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(468)	(447)
Depreciation	21	24
Disposals	0	0
Retirement of assets	8	3
Change in foreign exchange rates	0	0
Transfers in (out) of PP&E	0	0
End of the period	(478)	(468)
Hydro | Accumulated depreciation | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	(3)	0
Wind and Solar
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	2,183	1,777
End of the period	2,005	2,183
Wind and Solar | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	3,276	2,746
Additions	0	0
Additions from development projects	0	0
Acquisitions		146
Disposals	0	0
Impairment (charges) reversals	(43)	(12)
Retirement of assets	(9)	(11)
Change in foreign exchange rates	45	3
Transfer of assets	45	280
Transfers in (out) of PP&E	(22)	(4)
End of the period	3,233	3,276
Wind and Solar | Cost | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	0
Wind and Solar | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(1,093)	(969)
Depreciation	130	130
Disposals	0	0
Retirement of assets	6	6
Change in foreign exchange rates	11	0
Transfers in (out) of PP&E	0	0
End of the period	(1,228)	(1,093)
Wind and Solar | Accumulated depreciation | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	0
Gas generation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	1,909	1,877
End of the period	1,718	1,909
Gas generation | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	4,087	3,935
Additions	0	0
Additions from development projects	0	0
Acquisitions		0
Disposals	1	2
Impairment (charges) reversals	0	(2)
Retirement of assets	(12)	(57)
Change in foreign exchange rates	(4)	(25)
Transfer of assets	35	237
Transfers in (out) of PP&E	437	(5)
End of the period	4,530	4,087
Gas generation | Cost | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	0
Gas generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(2,178)	(2,058)
Depreciation	308	184
Disposals	(1)	(1)
Retirement of assets	10	55
Change in foreign exchange rates	2	(8)
Transfers in (out) of PP&E	335	0
End of the period	(2,812)	(2,178)
Gas generation | Accumulated depreciation | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	0
Energy Transition
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	363	968
End of the period	230	363
Energy Transition | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	4,513	4,901
Additions	0	0
Additions from development projects	0	0
Acquisitions		0
Disposals	216	74
Impairment (charges) reversals	0	(468)
Retirement of assets	(7)	(49)
Change in foreign exchange rates	97	2
Transfer of assets	19	124
Transfers in (out) of PP&E	(442)	46
End of the period	3,974	4,513
Energy Transition | Cost | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	31
Energy Transition | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(4,150)	(3,933)
Depreciation	63	264
Disposals	(211)	(72)
Retirement of assets	7	48
Change in foreign exchange rates	89	2
Transfers in (out) of PP&E	(340)	40
End of the period	(3,744)	(4,150)
Energy Transition | Accumulated depreciation | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	31
Capital spares and other
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	186	210
End of the period	185	186
Capital spares and other | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	366	379
Additions	6	2
Additions from development projects	12	0
Acquisitions		0
Disposals	0	0
Impairment (charges) reversals	0	(13)
Retirement of assets	(2)	0
Change in foreign exchange rates	2	(7)
Transfer of assets	6	5
Transfers in (out) of PP&E	(13)	0
End of the period	379	366
Capital spares and other | Cost | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	0
Capital spares and other | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of the period	(180)	(169)
Depreciation	16	12
Disposals	0	0
Retirement of assets	2	0
Change in foreign exchange rates	0	(1)
Transfers in (out) of PP&E	0	0
End of the period	(194)	(180)
Capital spares and other | Accumulated depreciation | Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Transfer of assets	0	0
Decommissioning and restoration
Disclosure of detailed information about property, plant and equipment [line items]
Disposals	5
Decommissioning and restoration | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	(74)	135
Decommissioning and restoration | Assets under construction | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	0	0
Decommissioning and restoration | Land | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	0	0
Decommissioning and restoration | Hydro | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	(15)	1
Decommissioning and restoration | Wind and Solar | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	(59)	128
Decommissioning and restoration | Gas generation | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	(12)	6
Decommissioning and restoration | Energy Transition | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	10	0
Decommissioning and restoration | Capital spares and other | Cost
Disclosure of detailed information about property, plant and equipment [line items]
Revisions/additions to decommissioning and restoration costs	$ 2	$ 0

Property, Plant, and Equipmen_3

Property, Plant, and Equipment - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about property, plant and equipment [line items]
Capitalized additions	$ 16	$ 14	$ 8
Mine depreciation	0	190	$ 144
Other work performed by entity and capitalised	16	$ 14
Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Mine depreciation	132
Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
Construction in progress	$ 77

Right of Use Assets - Reconcili

Right of Use Assets - Reconciliation of Changes of the Right of Use Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	$ 95	$ 141
Additions	40	1
Acquisitions		13
Depreciation	(11)	(11)
Disposal of assets		(41)
Transfers		(8)
Change in foreign exchange rates	2
Right-of-use assets, ending balance	126	95
Land
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	68	58
Additions	36	0
Acquisitions		13
Depreciation	(4)	(3)
Disposal of assets		0
Transfers		0
Change in foreign exchange rates	2
Right-of-use assets, ending balance	102	68
Buildings
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	20	24
Additions	0	1
Acquisitions		0
Depreciation	(5)	(5)
Disposal of assets		0
Transfers		0
Change in foreign exchange rates	0
Right-of-use assets, ending balance	15	20
Vehicles
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	1	1
Additions	1	0
Acquisitions		0
Depreciation	0	0
Disposal of assets		0
Transfers		0
Change in foreign exchange rates	0
Right-of-use assets, ending balance	2	1
Equipment
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	6	16
Additions	3	0
Acquisitions		0
Depreciation	(2)	(2)
Disposal of assets		0
Transfers		(8)
Change in foreign exchange rates	0
Right-of-use assets, ending balance	7	6
Pipeline
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	0	42
Additions	0	0
Acquisitions		0
Depreciation	0	(1)
Disposal of assets		(41)
Transfers		0
Change in foreign exchange rates	0
Right-of-use assets, ending balance	$ 0	$ 0

Right of Use Assets - Narrative

Right of Use Assets - Narrative (Details) - CAD ($) $ in Millions		12 Months Ended
	Jun. 30, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of quantitative information about right-of-use assets [line items]
Additions		$ 40	$ 1
Lease liabilities recognized		16	15
Interest on lease liabilities		7	7	$ 8
Principal repayments		9	8
Expense relating to short-term and low value leases		2	0	0
Expense relating to variable lease payments		8	6	$ 7
Land
Disclosure of quantitative information about right-of-use assets [line items]
Additions		36	0
Pipeline
Disclosure of quantitative information about right-of-use assets [line items]
Additions		$ 0	$ 0
Derecognition of the right-of-use asset	$ 41
Lease liability	43
Gains on lease liability	$ 2

Intangible Assets (Details)

Intangible Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about intangible assets [abstract]
Project development costs	$ 10	$ 29	$ 25
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	256	313
Change in foreign exchange rates	2
Transfers	(19)	0
Ending balance	252	256
Project development costs	10	29	$ 25
US Wind Projects
Disclosure of detailed information about intangible assets [abstract]
Project development costs	19
Reconciliation of changes in intangible assets other than goodwill [abstract]
Project development costs	19
Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	827	833
Additions	31	9
Impairment charges		(17)
Change in foreign exchange rates	7	(2)
Transfers	3	4
Ending balance	868	827
Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(571)	(520)
Change in foreign exchange rates	2
Amortization	43	51
Ending balance	(616)	(571)
Power sale contracts
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	129	146
Ending balance	114	129
Power sale contracts | Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	269	269
Additions	0	0
Impairment charges		0
Change in foreign exchange rates	3	0
Transfers	0	0
Ending balance	272	269
Power sale contracts | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(140)	(123)
Change in foreign exchange rates	1
Amortization	17	17
Ending balance	(158)	(140)
Software and other
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	123	140
Ending balance	111	123
Software and other | Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	422	412
Additions	0	0
Impairment charges		0
Change in foreign exchange rates	3	(2)
Transfers	12	12
Ending balance	437	422
Software and other | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(299)	(272)
Change in foreign exchange rates	1
Amortization	26	27
Ending balance	(326)	(299)
Intangibles under development
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	4	3
Ending balance	27	4
Intangibles under development | Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	4	3
Additions	31	9
Impairment charges		0
Change in foreign exchange rates	1	0
Transfers	(9)	(8)
Ending balance	27	4
Intangibles under development | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	0	0
Change in foreign exchange rates	0
Amortization	0	0
Ending balance	0	0
Coal rights
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	0	24
Ending balance	0	0
Coal rights | Cost
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	132	149
Additions	0	0
Impairment charges		(17)
Change in foreign exchange rates	0	0
Transfers	0	0
Ending balance	132	132
Coal rights | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(132)	(125)
Change in foreign exchange rates	0
Amortization	0	7
Ending balance	$ (132)	$ (132)

Goodwill (Details)

Goodwill (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) cADPerMegawattHour	Dec. 31, 2021 CAD ($) cADPerMegawattHour
Disclosure of detailed information about intangible assets [line items]
Goodwill	$ 464	$ 463
Impairment of goodwill	0
Hydro
Disclosure of detailed information about intangible assets [line items]
Goodwill	258	258
Wind and Solar
Disclosure of detailed information about intangible assets [line items]
Goodwill	176	175
Energy Marketing
Disclosure of detailed information about intangible assets [line items]
Goodwill	$ 30	$ 30
Minimum
Disclosure of detailed information about intangible assets [line items]
Discount rate used to calculate goodwill impairment	5.90%	5%
Electricity prices | cADPerMegawattHour	28	17
Maximum
Disclosure of detailed information about intangible assets [line items]
Discount rate used to calculate goodwill impairment	8.20%	6.40%
Electricity prices | cADPerMegawattHour	233	136

Other Assets - Disclosure of Co

Other Assets - Disclosure of Components in Other Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of financial assets [abstract]
Loan receivable		$ 55
South Hedland prepaid transmission access and distribution costs	$ 61	65
Long-term prepaids and other assets	56	48
Project development costs	10	29	$ 25
Total current other assets	4	55
Total long-term other assets	160	142
Total Other assets	$ 164	$ 197

Other Assets - Narrative (Detai

Other Assets - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of joint operations [line items]
Loan receivable		$ 55
Transmission infrastructure costs	$ (16)
Kent Hills Wind L.P.
Disclosure of joint operations [line items]
Loan receivable	$ 37
Ownership interests	17%
Interest	4.55%
Repayments received	$ 18

Other Assets - Disclosure of Ch

Other Assets - Disclosure of Change in Project Development Costs (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Change in Project Development Costs [Roll Forward]
Balance, Jan 1	$ 29	$ 25
Additions	29	15
Transfer of assets	(29)	(1)
Transfers to intangible assets	(19)	0
Impairment charges	0	(10)
Balance, Dec. 31	$ 10	$ 29

Decommissioning and Other Pro_3

Decommissioning and Other Provisions - Change in Decommissioning and Other Provision Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of changes in other provisions [abstract]
Balance	$ 827	$ 673
Liabilities incurred	24	30
Liabilities settled	(47)	(80)
Accretion	(49)	32
Acquisition of liabilities		2
Disposals	(5)
Revisions in estimated cash flows	100	179
Revisions in discount rates	(225)	(6)
Reversals	(9)	(3)
Change in foreign exchange rates	15
Balance	729	827
Decommissioning and restoration
Reconciliation of changes in other provisions [abstract]
Balance	793	608
Liabilities incurred	1	8
Liabilities settled	(35)	(18)
Accretion	(49)	32
Acquisition of liabilities		2
Disposals	(5)
Revisions in estimated cash flows	95	167
Revisions in discount rates	(225)	(6)
Reversals	0	0
Change in foreign exchange rates	15
Balance	688	793
Other provisions
Reconciliation of changes in other provisions [abstract]
Balance	34	65
Liabilities incurred	23	22
Liabilities settled	(12)	(62)
Accretion	0	0
Acquisition of liabilities		0
Disposals	0
Revisions in estimated cash flows	5	12
Revisions in discount rates	0	0
Reversals	(9)	(3)
Change in foreign exchange rates	0
Balance	$ 41	$ 34

Decommissioning and Other Pro_4

Decommissioning and Other Provisions - Current and Non-Current Portion of Decommissioning and Other Provisions (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Current portion	$ 70	$ 48
Non-current portion	659	779
Balance	$ 729	$ 827	$ 673

Decommissioning and Other Pro_5

Decommissioning and Other Provisions - Decommissioning and Restoration - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Disclosure of detailed information about borrowings [line items]
Undiscounted cash amount	$ 1,600,000,000
Revisions in estimated cash flows	100,000,000	$ 179,000,000
Decrease in PP&E	(123,000,000)	(6,000,000)
Reversal of impairment loss	(102,000,000)	0
Revisions in discount rates	(225,000,000)	(6,000,000)
Onerous contract provisions	0	(14,000,000)	$ (29,000,000)
Decommissioning and restoration
Disclosure of detailed information about borrowings [line items]
Revisions in estimated cash flows	95,000,000	167,000,000
Decrease in PP&E	(49,000,000)	(133,000,000)
Reversal of impairment loss		(34,000,000)
Revisions in discount rates	(225,000,000)	(6,000,000)
Gas And Energy Transition
Disclosure of detailed information about borrowings [line items]
Decommissioning and restoration provision		(47,000,000)
Minimum
Disclosure of detailed information about borrowings [line items]
Revisions in discount rates	7	3.6
Maximum
Disclosure of detailed information about borrowings [line items]
Revisions in discount rates	0.097	6.5
Gas
Disclosure of detailed information about borrowings [line items]
Decommissioning and restoration provision	(46,000,000)
Centralia Coal Mine
Disclosure of detailed information about borrowings [line items]
Onerous contract provisions	(10,000,000)
Centralia Coal Mine | Surety Bonds
Disclosure of detailed information about borrowings [line items]
Bonds issued				$ 147	$ 147
Alberta Mine | Letters Of Credit
Disclosure of detailed information about borrowings [line items]
Bonds issued	187,000,000	188,000,000
Royalty Contract
Disclosure of detailed information about borrowings [line items]
Onerous contract provisions	(7,000,000)
Wind Sites
Disclosure of detailed information about borrowings [line items]
Decommissioning and restoration provision		$ (120,000,000)
Decommissioning and restoration
Disclosure of detailed information about borrowings [line items]
Decommissioning and restoration provision	$ (225,000,000)

Credit Facilities, Long-Term _3

Credit Facilities, Long-Term Debt and Lease Liabilities - Amounts Outstanding (Details) $ in Millions, $ in Millions, $ in Millions	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2022 AUD ($)	Nov. 15, 2022 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 AUD ($)	Dec. 06, 2021 CAD ($)
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 3,653				$ 3,267
Less: current portion of long-term debt	(170)				(837)
Less: current portion of lease liabilities	(8)				(7)
Total current long-term debt and lease liabilities	(178)				(844)
Total non-current credit facilities, long-term debt and lease liabilities	3,475				2,423
All Borrowings Except Finance Lease Obligations
Disclosure of detailed information about borrowings [line items]
Carrying value	3,518				3,167
Notional amount	3,563				3,198
Committed syndicated bank facility
Disclosure of detailed information about borrowings [line items]
Carrying value	32				0
Notional amount	33				0
Term Facility
Disclosure of detailed information about borrowings [line items]
Carrying value	396				0
Notional amount	400				0
7.3% Medium term notes
Disclosure of detailed information about borrowings [line items]
Carrying value	110				110
Notional amount	110				110
6.9% Medium term notes
Disclosure of detailed information about borrowings [line items]
Carrying value	141				141
Notional amount	141				141
Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 700				$ 700
7.8% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	533				0
Notional amount	542				0
6.5% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	401				378
Notional amount	$ 407				383
4.5% Senior notes
Disclosure of detailed information about borrowings [line items]
Carrying value				$ 400
Interest	4.50%	4.50%	4.50%
4.5% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 0				510
Notional amount	0				511
Melancthon Wolfe Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	202				235
Notional amount	203				237
New Richmond Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	112				120
Notional amount	113				121
Kent Hills Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	206				221
Notional amount	$ 209				221
Interest	4.50%	4.50%	4.50%
Windrise Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 170				171
Notional amount	173				173			$ 173
Interest								3.41%
Pingston bond
Disclosure of detailed information about borrowings [line items]
Carrying value	45				45
Notional amount	45				45
TAPC Holdings LP bond (Poplar Creek)
Disclosure of detailed information about borrowings [line items]
Carrying value	94				102
Notional amount					104
TEC Hedland PTY Ltd bond | AUD
Disclosure of detailed information about borrowings [line items]
Carrying value	711				732
Notional amount	720				742
TransAlta OCP LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	241				263
Notional amount	242				265
Other
Disclosure of detailed information about borrowings [line items]
Carrying value	1				4
Notional amount	1				4
Big Level & Antrim | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	102				106
Notional amount	108	$ 79			112	88
Lakeswind | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	15				18
Notional amount	15	11			18	14
North Carolina Solar | USD
Disclosure of detailed information about borrowings [line items]
Carrying value	6				11
Notional amount	6	$ 5			11	$ 9
South Hedland Bond | AUD
Disclosure of detailed information about borrowings [line items]
Carrying value			$ 786				$ 800
Finance lease obligation
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 135				$ 100
Weighted average | Committed syndicated bank facility
Disclosure of detailed information about borrowings [line items]
Interest	4.70%	4.70%	4.70%		0%	0%	0%
Weighted average | Term Facility
Disclosure of detailed information about borrowings [line items]
Interest	6.50%	6.50%	6.50%		0%	0%	0%
Weighted average | 7.3% Medium term notes
Disclosure of detailed information about borrowings [line items]
Interest	7.30%	7.30%	7.30%		7.30%	7.30%	7.30%
Weighted average | 6.9% Medium term notes
Disclosure of detailed information about borrowings [line items]
Interest	6.90%	6.90%	6.90%		6.90%	6.90%	6.90%
Weighted average | 7.8% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Interest	7.80%	7.80%	7.80%		0%	0%	0%
Weighted average | 6.5% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Interest	6.50%	6.50%	6.50%		6.50%	6.50%	6.50%
Weighted average | 4.5% Senior notes | USD
Disclosure of detailed information about borrowings [line items]
Interest	4.50%	4.50%	4.50%		4.50%	4.50%	4.50%
Weighted average | Melancthon Wolfe Wind LP bond
Disclosure of detailed information about borrowings [line items]
Interest	3.80%	3.80%	3.80%		3.80%	3.80%	3.80%
Weighted average | New Richmond Wind LP bond
Disclosure of detailed information about borrowings [line items]
Interest	4%	4%	4%		4%	4%	4%
Weighted average | Kent Hills Wind LP bond
Disclosure of detailed information about borrowings [line items]
Interest					4.50%	4.50%	4.50%
Weighted average | Windrise Wind LP bond
Disclosure of detailed information about borrowings [line items]
Interest	3.40%	3.40%	3.40%		3.40%	3.40%	3.40%
Weighted average | Pingston bond
Disclosure of detailed information about borrowings [line items]
Interest	3%	3%	3%		3%	3%	3%
Weighted average | TAPC Holdings LP bond (Poplar Creek)
Disclosure of detailed information about borrowings [line items]
Interest	8.90%	8.90%	8.90%		4.40%	4.40%	4.40%
Weighted average | TEC Hedland PTY Ltd bond | AUD
Disclosure of detailed information about borrowings [line items]
Interest	4.10%	4.10%	4.10%		4.10%	4.10%	4.10%
Weighted average | TransAlta OCP LP bond
Disclosure of detailed information about borrowings [line items]
Interest	4.50%	4.50%	4.50%		4.50%	4.50%	4.50%
Weighted average | Other
Disclosure of detailed information about borrowings [line items]
Interest	5.90%	5.90%	5.90%		5.90%	5.90%	5.90%
Borrowings effective interest rate	5.98%	5.98%	5.98%
Weighted average | Big Level & Antrim | USD
Disclosure of detailed information about borrowings [line items]
Interest	6.60%	6.60%	6.60%		6.60%	6.60%	6.60%
Weighted average | Lakeswind | USD
Disclosure of detailed information about borrowings [line items]
Interest	10.50%	10.50%	10.50%		10.50%	10.50%	10.50%
Weighted average | North Carolina Solar | USD
Disclosure of detailed information about borrowings [line items]
Interest	7.30%	7.30%	7.30%		7.30%	7.30%	7.30%

Credit Facilities, Long-Term _4

Credit Facilities, Long-Term Debt and Lease Liabilities - Credit facilities summarized (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about borrowings [line items]
Cash drawings	$ 3,653	$ 3,267
Cash collateral	260	18
Committed
Disclosure of detailed information about borrowings [line items]
Facility size	2,590
Outstanding letters of credit	957
Cash drawings	433
Available capacity	1,200
Non-Committed
Disclosure of detailed information about borrowings [line items]
Facility size	400
Outstanding letters of credit	218
Cash drawings	0
Available capacity	182
TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Cash collateral	304
Syndicated Credit Facility | Committed
Disclosure of detailed information about borrowings [line items]
Facility size	1,250
Outstanding letters of credit	738
Cash drawings	0
Available capacity	512
Syndicated Credit Facility | TransAlta Renewables Inc. | Committed
Disclosure of detailed information about borrowings [line items]
Facility size	700
Outstanding letters of credit	0
Cash drawings	33
Available capacity	667
TransAlta Corporation bilateral credit facilities | Committed
Disclosure of detailed information about borrowings [line items]
Facility size	240
Outstanding letters of credit	219
Cash drawings	0
Available capacity	21
TransAlta Corporation Term Facility
Disclosure of detailed information about borrowings [line items]
Cash drawings	396	$ 0
TransAlta Corporation Term Facility | Committed
Disclosure of detailed information about borrowings [line items]
Facility size	400
Outstanding letters of credit	0
Cash drawings	400
Available capacity	0
Demand Facility | Non-Committed
Disclosure of detailed information about borrowings [line items]
Facility size	250
Outstanding letters of credit	120
Cash drawings	0
Available capacity	130
Demand Facility | TransAlta Renewables Inc. | Non-Committed
Disclosure of detailed information about borrowings [line items]
Facility size	150
Outstanding letters of credit	98
Cash drawings	0
Available capacity	$ 52

Credit Facilities, Long-Term _5

Credit Facilities, Long-Term Debt and Lease Liabilities - Credit Facilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of detailed information about borrowings [line items]
Cash and cash equivalents	$ 1,134	$ 947	$ 703	$ 411
Revolving Term Facility [Member]
Disclosure of detailed information about borrowings [line items]
Floating rate term	2 years
Letter of credit
Disclosure of detailed information about borrowings [line items]
Debt instruments issued	$ 218
Committed syndicated bank facility | Committed credit facilities
Disclosure of detailed information about borrowings [line items]
Undrawn borrowing capacity	1,000	1,300
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash	17	$ 17
Restricted cash principal amount	$ 17

Credit Facilities, Long-Term _6

Credit Facilities, Long-Term Debt and Lease Liabilities - Senior Notes (Details) $ in Millions, $ in Millions	Dec. 31, 2022 USD ($)	Dec. 31, 2022 CAD ($)	Nov. 17, 2022 USD ($)	Nov. 15, 2022 CAD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 CAD ($)
Disclosure of detailed information about borrowings [line items]
Cash drawings		$ 3,653				$ 3,267
Interest rate swap
Disclosure of detailed information about borrowings [line items]
Interest			5.982%
Net investment hedges | Long-term debt
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 370				$ 370
7.750 Per cent Senior Notes Due Nov. 15, 2029
Disclosure of detailed information about borrowings [line items]
Cash drawings			$ 400
Interest			7.75%
Unsecured Senior Notes
Disclosure of detailed information about borrowings [line items]
Cash drawings				$ 400
Interest	4.50%	4.50%

Credit Facilities, Long-Term _7

Credit Facilities, Long-Term Debt and Lease Liabilities - Non-Recourse Debt (Details) - Windrise Wind LP bond - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 06, 2021
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 173	$ 173	$ 173
Interest			3.41%

Credit Facilities, Long-Term _8

Credit Facilities, Long-Term Debt and Lease Liabilities - Other (Details)	Dec. 31, 2022
Other | 5.9% Unsecured Commercial Loan Obligation due 2023
Disclosure of detailed information about borrowings [line items]
Interest	5.90%

Credit Facilities, Long-Term _9

Credit Facilities, Long-Term Debt and Lease Liabilities - Restrictions on Non-Recourse Debt and Security (Details) $ in Millions, $ in Millions		3 Months Ended	12 Months Ended
	Jul. 20, 2018 CAD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 AUD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2020 CAD ($)
Disclosure of detailed information about borrowings [line items]
Other borrowings		$ 735	$ 739		$ 735
PP&E		5,320	5,556		5,320	$ 5,822
Intangible assets		256	252		256	313
Annual cash payments	$ 40		40		40	$ 40
Annual cash payments, net		37
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash		17	17		17
Renewable generation facilities
Disclosure of detailed information about borrowings [line items]
PP&E		1,500	1,500		1,500
Intangible assets		78	70		78
Non-recourse debt
Disclosure of detailed information about borrowings [line items]
Other borrowings		1,900	1,800		1,900
Restricted cash		67	50		67
Non-recourse debt | Secured by first rate ranking charge over subsidiaries
Disclosure of detailed information about borrowings [line items]
Notional amount		1,500	1,400		1,500
Non-recourse debt | Secured by equity interests of the issuer
Disclosure of detailed information about borrowings [line items]
Notional amount		103	94		103
Restricted Use Debt
Disclosure of detailed information about borrowings [line items]
Proceeds received			8	$ 9
Kent Hills Wind Bonds
Disclosure of detailed information about borrowings [line items]
Reserve account balance		0	65		0
Secured Debt | TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 263	$ 241		$ 263

Credit Facilities, Long-Term_10

Credit Facilities, Long-Term Debt and Lease Liabilities - Principal Repayments (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about borrowings [line items]
Principal repayments	$ 3,653	$ 3,267
2023
Disclosure of detailed information about borrowings [line items]
Lease incentive	12
Cost
Disclosure of detailed information about borrowings [line items]
Principal repayments	3,563
Lease liabilities	135
Cost | 2023
Disclosure of detailed information about borrowings [line items]
Principal repayments	170
Lease liabilities	(7)
Cost | 2024
Disclosure of detailed information about borrowings [line items]
Principal repayments	527
Lease liabilities	4
Cost | 2025
Disclosure of detailed information about borrowings [line items]
Principal repayments	142
Lease liabilities	4
Cost | 2026
Disclosure of detailed information about borrowings [line items]
Principal repayments	177
Lease liabilities	3
Cost | 2027
Disclosure of detailed information about borrowings [line items]
Principal repayments	154
Lease liabilities	4
Cost | 2028
Disclosure of detailed information about borrowings [line items]
Principal repayments	2,393
Lease liabilities	$ 127

Credit Facilities, Long-Term_11

Credit Facilities, Long-Term Debt and Lease Liabilities - Restricted Cash and Letters of Credit (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Letter of credit
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	$ 1,175	$ 902
Exercised amount	0	0
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash	17	17
TEC
Disclosure of detailed information about borrowings [line items]
Restricted cash	53	$ 53
TransAlta Corporation bilateral credit facilities
Disclosure of detailed information about borrowings [line items]
Facility size	240
Uncommitted demand letter facility
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	120
Uncommitted demand letter facility | TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Facility size	150
Outstanding letters of credit	$ 98

Credit Facilities, Long-Term_12

Credit Facilities, Long-Term Debt and Lease Liabilities - Currency Impacts (Details) $ in Millions, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 AUD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 AUD ($)	Dec. 31, 2020 CAD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Disclosure of detailed information about borrowings [line items]
Net increase (decrease) in borrowings under credit facilities	$ (449)		$ 114		$ 106
USD | Senior Notes and Tax Equity
Disclosure of detailed information about borrowings [line items]
Notional amount						$ 41	$ 1
AUD | Non-Recourse Senior Secured Notes
Disclosure of detailed information about borrowings [line items]
Net increase (decrease) in borrowings under credit facilities		$ (9)		$ (40)

Exchangeable Securities - Narra

Exchangeable Securities - Narrative (Details) - Brookfield Renewable Partners - CAD ($) $ / shares in Units, $ in Millions			12 Months Ended	25 Months Ended
	Dec. 12, 2022	Mar. 22, 2019	Dec. 31, 2022	May 01, 2021
Disclosure of detailed information about borrowings [line items]
Ownership interests				9%
Aggregate common shares (shares)			35,456,023
Issued and outstanding common shares (shares)			13.20%
Investment Agreement
Disclosure of detailed information about borrowings [line items]
Proceeds on sale of facilities		$ 750
Dividend declared	$ 7
Fixed rate	1.764%
Investment Agreement | Minimum ownership interest threshold
Disclosure of detailed information about borrowings [line items]
Ownership interests			8.50%
Investment Agreement | Hydro | Ownership interest, less than, threshold
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary			49%
Investment Agreement | Hydro | Top up option for ownership interest percentage, 20 day VWAP is not less than $14 per share
Disclosure of detailed information about borrowings [line items]
Additional proportion of ownership interests			10%
Investment Agreement | Hydro | Top Up Option For Ownership Interest Percentage, 20 day VWAP is not less than $17 per share
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary			49%
Investment Agreement | Hydro | Ownership interest threshold exceeded
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary			49%
Investment Agreement | Maximum | Hydro
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary			49%
Investment Agreement | Maximum | Hydro | Top Up Option For Ownership Interest Percentage, 20 day VWAP is not less than $17 per share
Disclosure of detailed information about borrowings [line items]
Weighted average share price (in CAD per shares)			$ 17
Investment Agreement | Minimum | Hydro | Top Up Option For Ownership Interest Percentage, 20 day VWAP is not less than $17 per share
Disclosure of detailed information about borrowings [line items]
Weighted average share price (in CAD per shares)			$ 14

Exchangeable Securities - Sched

Exchangeable Securities - Schedule of Exchangeable Securities (Details) - CAD ($) $ in Millions	Oct. 30, 2020	May 01, 2019	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about borrowings [line items]
Total exchangeable securities			$ 3,475	$ 2,423
Brookfield Renewable Partners | Investment Agreement
Disclosure of detailed information about borrowings [line items]
Investment in tranche	$ 400	$ 350
7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of detailed information about borrowings [line items]
Exchangeable debentures – due May 1, 2039			$ 350	$ 350
Interest		7%	7%	7%
Exchangeable preferred shares			$ 400	$ 400
Total exchangeable securities			750	750
Cost | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of detailed information about borrowings [line items]
Exchangeable debentures – due May 1, 2039			339	335
Exchangeable preferred shares			400	400
Total exchangeable securities			$ 739	$ 735

Exchangeable Securities - Optio

Exchangeable Securities - Option To Exchange (Details) - Option to exchange – embedded derivative - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of detailed information about borrowings [line items]
Base fair value	$ 0	$ 0
Minimum
Disclosure of detailed information about borrowings [line items]
Sensitivity	0	0
Maximum
Disclosure of detailed information about borrowings [line items]
Sensitivity	$ (25)	$ (32)

Defined Benefit Obligation an_3

Defined Benefit Obligation and Other Long-Term Liabilities - Components of Defined Benefit Obligations and Other Long-term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Subclassifications of assets, liabilities and equities [abstract]
Defined benefit obligation	$ 150	$ 228
Long-term incentive accruals	8	4
Retail power contract liability	126	0
Other	10	21
Total	$ 294	$ 253

Defined Benefit Obligation an_4

Defined Benefit Obligation and Other Long-Term Liabilities - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of fair value measurement of liabilities [line items]
Increase (decrease) in defined benefit obligation	$ (78)
Defined benefit obligation	150	$ 228
Voluntary contribution	$ 35
Increase in discount rates	1%
Pro Forma
Disclosure of fair value measurement of liabilities [line items]
Increase (decrease) in defined benefit obligation	$ 39
Level II | Recurring fair value measurement
Disclosure of fair value measurement of liabilities [line items]
Commodity risk management assets and liabilities	173	$ 122
Level II | Recurring fair value measurement | retail power contract liabilities
Disclosure of fair value measurement of liabilities [line items]
Commodity risk management assets and liabilities	129
Risk management assets | Level II | Recurring fair value measurement
Disclosure of fair value measurement of liabilities [line items]
Commodity risk management assets and liabilities	$ 139

Common Shares - Issued and Outs

Common Shares - Issued and Outstanding (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of classes of share capital [line items]
Stock options exercised	$ 3	$ 8
Common shares
Stock options exercised	0.5	1.2
Common shares
Disclosure of classes of share capital [line items]
Issued and outstanding, end of year	$ 2,901	$ 2,896
Purchased and cancelled under the NCIB	(46)	0
Effects of share-based payment plans	5	(3)
Issued and outstanding, end of year	$ 2,863	$ 2,901
Common shares
Issued and outstanding, beginning of year	271	269.8
Purchased and cancelled under the NCIB	(4.3)	0
Effects of share-based payment plans	0.9	0
Issued and outstanding, end of year	268.1	271

Common Shares - The effects of

Common Shares - The effects of the Corporation's purchase and cancellation of the common shares (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	May 24, 2022	May 25, 2021
Disclosure of classes of share capital [line items]
Amount recorded in deficit	$ (2,514)	$ (2,453)
Percentage of public float of common shares			7.16%	7.16%
Shares repurchased but not cancelled	164,300	0
Payments for shares repurchased but not cancelled	$ 52
NCIB Program
Disclosure of classes of share capital [line items]
Total shares purchased	4,342,300	0
Average purchase price per share	$ 12.48	$ 0
Total cost (millions)	$ 54	$ 0
Weighted average book value of shares cancelled	46	0
Amount recorded in deficit	$ (8)	$ 0
Repurchase of maximum common shares (in shares)			14,000,000	14,000,000

Common Shares - Shareholder Rig

Common Shares - Shareholder Rights Plan (Details)	12 Months Ended
	Dec. 31, 2022
Shareholder Rights Plan | Common shares | Minimum
Disclosure of classes of share capital [line items]
Common shares acquired	20%

Common Shares - Earnings per Co

Common Shares - Earnings per Common Share (Details) - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share Capital, Reserves And Other Equity Interest [Abstract]
Net earnings (loss) attributable to common shareholders	$ 4	$ (576)	$ (336)
Basic weighted average number of common shares outstanding (in shares)	271,000	271,000	275,000
Diluted weighted average number of common shares outstanding (in shares)	271,000	271,000	275,000
Net earnings (loss) per share attributable to common shareholders, basic (in CAD per share)	$ 0.01	$ (2.13)	$ (1.22)
Net earnings (loss) per share attributable to common shareholders, diluted (in CAD per share)	$ 0.01	$ (2.13)	$ (1.22)

Common Shares - Dividends (Deta

Common Shares - Dividends (Details)	Dec. 12, 2022 $ / shares
Share Capital, Reserves And Other Equity Interest [Abstract]
Dividends declared per share (in CAD per share)	$ 0.055

Preferred Shares - Issued and O

Preferred Shares - Issued and Outstanding (Details) - CAD ($) shares in Millions, $ in Millions	Dec. 31, 2022	Jun. 30, 2022	Dec. 31, 2021	Mar. 31, 2021
Preferred Shares
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	38.6		38.6
Number of shares issued (in shares)	38.6		38.6
Amount	$ 942		$ 942
Series A
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	9.6		9.6	10.2
Number of shares issued (in shares)	9.6		9.6	10.2
Amount	$ 235		$ 235
Series B
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	2.4		2.4	1.8
Number of shares issued (in shares)	2.4		2.4	1.8
Amount	$ 58		$ 58
Series C
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	10	11	11
Number of shares issued (in shares)	10	11	11
Amount	$ 243		$ 269
Series D
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	1		0
Number of shares issued (in shares)	1		0
Amount	$ 26		$ 0
Series E
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	9		9
Number of shares issued (in shares)	9		9
Amount	$ 219		$ 219
Series G
Disclosure of classes of share capital [line items]
Number of shares outstanding (in shares)	6.6		6.6
Number of shares issued (in shares)	6.6		6.6
Amount	$ 161		$ 161

Preferred Shares - Series Cumul

Preferred Shares - Series Cumulative Redeemable Rate Reset Preferred Shares Conversion (Details) - shares			12 Months Ended
	Sep. 21, 2022	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021	Mar. 31, 2021
Series A
Disclosure of classes of share capital [line items]
Convertible preferred shares tendered for conversion (in shares)					1,417,338
Number of shares issued (in shares)			9,600,000	9,600,000	10,200,000
Number of shares outstanding (in shares)			9,600,000	9,600,000	10,200,000
Series B
Disclosure of classes of share capital [line items]
Convertible preferred shares tendered for conversion (in shares)					871,871
Number of shares issued (in shares)			2,400,000	2,400,000	1,800,000
Number of shares outstanding (in shares)			2,400,000	2,400,000	1,800,000
Basis spread on variable rate					0.01%
Dividend rate on preference shares			2%
Series C
Disclosure of classes of share capital [line items]
Number of shares issued (in shares)		11,000,000	10,000,000	11,000,000
Number of shares outstanding (in shares)		11,000,000	10,000,000	11,000,000
Basis spread on variable rate		0.01%
Number of shares converted into other classes of shares (in shares)		1,044,299
Bond yield, period		5 years
Annualized fixed dividend rate		5.854%
Bond yield		2.754%
Dividend rate on preference shares		3.10%
Series D
Disclosure of classes of share capital [line items]
Number of shares issued (in shares)			1,000,000	0
Number of shares outstanding (in shares)			1,000,000	0
Bond yield, period		5 years
Dividend rate on preference shares		3.10%	3.10%
Series E
Disclosure of classes of share capital [line items]
Number of shares issued (in shares)			9,000,000	9,000,000
Number of shares outstanding (in shares)			9,000,000	9,000,000
Number of shares converted into other classes of shares (in shares)	89,945
Required shares conversion (in shares)	1,000,000
Bond yield, period			5 years
Annualized fixed dividend rate			6.894%
Bond yield			3.244%
Dividend rate on preference shares			3.65%

Preferred Shares - Preferred Sh

Preferred Shares - Preferred Share Series Information (Details) - Preferred Shares	12 Months Ended
	Dec. 31, 2022 $ / shares
Disclosure of classes of share capital [line items]
Fixed rate reset term	5 years
Amount per share redeemable at reset date (in CAD per share)	$ 25

Preferred Shares - Characterist

Preferred Shares - Characteristics Specific to Series of Preferred Shares (Details)	12 Months Ended
	Dec. 31, 2022 $ / shares
Series A
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 0.71924
Series A | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	2.03%
Series B
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.10295
Series B | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	2.03%
Series C
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.34933
Series C | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.10%
Series D
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.40030
Series D | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.10%
Series E
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.51102
Series E | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.65%
Series F
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 0
Series F | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.65%
Series G
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 1.24700
Series G | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.80%
Series H
Disclosure of classes of share capital [line items]
Annual dividend rate per share (in CAD per share)	$ 0
Series H | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over benchmark (per cent)	3.80%

Preferred Shares - Preferred _2

Preferred Shares - Preferred Share Dividends Declared (Details) - CAD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Dec. 12, 2022	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021
Disclosure of classes of share capital [line items]
Dividends declared per share (in CAD per share)	$ 0.055
Series A
Disclosure of classes of share capital [line items]
Total dividends declared			$ 7	$ 7
Dividends declared per share (in CAD per share)	0.17981
Series B
Disclosure of classes of share capital [line items]
Total dividends declared			$ 3	1
Dividend rate on preference shares			2%
Dividends declared per share (in CAD per share)	0.37991
Series C
Disclosure of classes of share capital [line items]
Total dividends declared			$ 14	11
Dividend rate on preference shares		3.10%
Dividends declared per share (in CAD per share)	0.36588
Series D
Disclosure of classes of share capital [line items]
Total dividends declared			$ 1	0
Dividend rate on preference shares		3.10%	3.10%
Dividends declared per share (in CAD per share)	0.45578
Series E
Disclosure of classes of share capital [line items]
Total dividends declared			$ 13	12
Dividend rate on preference shares			3.65%
Dividends declared per share (in CAD per share)	0.43088
Series G
Disclosure of classes of share capital [line items]
Total dividends declared			$ 8	8
Dividends declared per share (in CAD per share)	$ 0.31175
Preferred Shares
Disclosure of classes of share capital [line items]
Total dividends declared			$ 46	$ 39

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Loss) (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		$ 146
Currency translation adjustment
Losses (gains) on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		4	$ 14
Gains (losses) on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax	[1]	(25)	0	$ 11
Cash flow hedges
Losses on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax	[2]	(556)	(200)	20
Other
Intercompany and third-party investments at FVTOCI		(1)	0
Accumulated other comprehensive income, end of the period		(222)	146
Net income tax expense (recovery) relating to gains (losses) on financial instruments		(3)	0	0
Net impact related to cash flow hedges		112	57	23
Net of income tax expense		(12)	(11)	3
Currency translation adjustment
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(35)	(21)
Currency translation adjustment
Losses (gains) on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		21	(14)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax		(25)	0
Other
Accumulated other comprehensive income, end of the period		(39)	(35)	(21)
Cash flow hedges
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		228	436
Cash flow hedges
Losses on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax		(456)	(208)
Other
Accumulated other comprehensive income, end of the period		(228)	228	436
Net impact related to cash flow hedges		(112)	(57)
Employee future benefits
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(29)	(66)
Employee future benefits
Net actuarial gains on defined benefit plans, net of tax		37	37
Other
Accumulated other comprehensive income, end of the period		8	(29)	(66)
Net of income tax expense		12	11
Other
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(18)	(47)
Other
Intercompany and third-party investments at FVTOCI		55	29
Accumulated other comprehensive income, end of the period		$ 37	$ (18)	$ (47)
[1]Net of income tax recovery of $3 million for the year ended Dec. 31, 2022 (2021 and 2020 – nil).[2]Net of income tax recovery of $138 million for the year ended Dec. 31, 2022 (2021 – $55 million recovery, 2020 – $8 million expense).

Share-Based Payment Plans - Nar

Share-Based Payment Plans - Narrative (Details) $ / shares in Units, shares in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($) shares $ / shares	Dec. 31, 2021 CAD ($) $ / shares	Dec. 31, 2020 CAD ($) $ / shares	Mar. 31, 2021 shares
Executive officers
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of share options granted (in shares)	0.3	700,000	700,000
Weighted average exercise price (in CAD per share) | $ / shares	$ 12.66	$ 9.86	$ 9.17
PSUs and RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Performance period	3 years
Vesting period	3 years
Compensation expense (reversal)	$ 20,000,000	$ 14,000,000	$ 15,000,000
PSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Performance period	3 years
RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	3 years
DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Compensation expense (reversal)	$ 0	3,000,000	1,000,000
Stock Options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of shares authorized (in shares) | shares	14.5			14.5
Stock Options | Maximum
Disclosure of terms and conditions of share-based payment arrangement [line items]
Common shares issued and outstanding, percentage	10%
Stock Options | Executive officers
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	3 years
Compensation expense (reversal)	$ 1,000,000	$ 2,000,000	$ 2,000,000
Expiration period of shares granted	7 years

Share-Based Payment Plans - Sto

Share-Based Payment Plans - Stock Options (Details) - Exercise price range one shares in Millions	12 Months Ended
	Dec. 31, 2022 shares $ / shares	Dec. 31, 2022 shares $ / shares
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Number of options (in shares) | shares	3	3
Weighted average remaining contractual life (in years)	3 years 10 months 20 days
Weighted average exercise price (in CAD per share)		$ 8.41
Minimum
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Range of exercise prices (in CAD per share)	$ 5
Maximum
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Range of exercise prices (in CAD per share)	$ 12

Employee Future Benefits - Narr

Employee Future Benefits - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 CAD ($) age	Dec. 31, 2022 CAD ($)	Dec. 31, 2022 CAD ($) Rate
Disclosure of defined benefit plans [line items]
Weighted average duration of defined benefit obligation	9 years 10 months 24 days
Minimum
Disclosure of defined benefit plans [line items]
Employer contribution (as percent)			500%
Maximum
Disclosure of defined benefit plans [line items]
Employer contribution (as percent)			1,100%
Registered | Letter of credit
Disclosure of defined benefit plans [line items]
Letter of credit, posted	$ 96	$ 96	$ 96	$ 96
Other
Disclosure of defined benefit plans [line items]
Maximum age disabled and retired members eligible for benefits		65		65

Employee Future Benefits - Cost

Employee Future Benefits - Costs Recognized (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	$ 2	$ 6	$ 8
Administration expenses	1	1	1
Defined benefit expense	10	6	15
Defined contribution expense	11	8	9
Net expense	21	14	24
Interest cost on defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost on defined benefit obligation	16	14	20
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest on plan assets	(9)	(8)	(12)
Curtailment and amendment gain		(7)	(2)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	1	3	5
Administration expenses	1	1	1
Defined benefit expense	6	1	9
Defined contribution expense	11	8	9
Net expense	17	9	18
Registered | Interest cost on defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost on defined benefit obligation	13	12	16
Curtailment and amendment gain		(7)
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest on plan assets	(9)	(8)	(11)
Curtailment and amendment gain		(7)	(2)
Supplemental
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	1	2	2
Administration expenses	0	0	0
Defined benefit expense	4	4	4
Defined contribution expense	0	0	0
Net expense	4	4	4
Supplemental | Interest cost on defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost on defined benefit obligation	3	2	3
Curtailment and amendment gain		0
Supplemental | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest on plan assets	0	0	(1)
Curtailment and amendment gain		0	0
Other
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	0	1	1
Administration expenses	0	0	0
Defined benefit expense	0	1	2
Defined contribution expense	0	0	0
Net expense	0	1	2
Other | Interest cost on defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost on defined benefit obligation	0	0	1
Curtailment and amendment gain		0
Other | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest on plan assets	$ 0	0	0
Curtailment and amendment gain		$ 0	$ 0

Employee Future Benefits - Stat

Employee Future Benefits - Status of Plans (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	$ (158)	$ (240)
Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(8)	(12)
Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(150)	(228)
Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	289	353	$ 381
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(447)	(593)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(71)	(130)
Registered | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(1)	(4)
Registered | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(70)	(126)
Registered | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	274	339	367
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(345)	(469)	(542)
Supplemental
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(70)	(87)
Supplemental | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(6)	(6)
Supplemental | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(64)	(81)
Supplemental | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	15	14	14
Supplemental | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(85)	(101)	(109)
Other
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(17)	(23)
Other | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(1)	(2)
Other | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(16)	(21)
Other | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	0	0	0
Other | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	$ (17)	$ (23)	$ (24)

Employee Future Benefits - Fair

Employee Future Benefits - Fair Value of Plan Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	$ (240)
Administration expenses	(1)	$ (1)	$ (1)
Net asset, ending of period	(158)	(240)
Voluntary contribution	35
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	353	381
Interest on plan assets	9	8
Net return (loss) on plan assets	(55)	13
Contributions	44	12
Benefits paid	(62)	(60)
Change in foreign exchange rates	1
Net asset, ending of period	289	353	381
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(130)
Administration expenses	(1)	(1)	(1)
Net asset, ending of period	(71)	(130)
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	339	367
Interest on plan assets	9	8
Net return (loss) on plan assets	(55)	14
Contributions	38	5
Benefits paid	(57)	(54)
Change in foreign exchange rates	1
Net asset, ending of period	274	339	367
Supplemental
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(87)
Administration expenses	0	0	0
Net asset, ending of period	(70)	(87)
Supplemental | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	14	14
Interest on plan assets	0	0
Net return (loss) on plan assets	0	(1)
Contributions	6	6
Benefits paid	(5)	(5)
Change in foreign exchange rates	0
Net asset, ending of period	15	14	14
Other
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(23)
Administration expenses	0	0	0
Net asset, ending of period	(17)	(23)
Other | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	0	0
Interest on plan assets	0	0
Net return (loss) on plan assets	0	0
Contributions	0	1
Benefits paid	0	(1)
Change in foreign exchange rates	0
Net asset, ending of period	$ 0	$ 0	$ 0

Employee Future Benefits - Fa_2

Employee Future Benefits - Fair Value of Plan Assets by Major Category (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Disclosure of fair value of plan assets [line items]
Alternative funds	$ 39
Money market and cash and cash equivalents	20	$ 20
Total	289	353
Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	18	33
US
Disclosure of fair value of plan assets [line items]
Equity securities	17	20
International
Disclosure of fair value of plan assets [line items]
Equity securities	79	126
Private
Disclosure of fair value of plan assets [line items]
Equity securities	1	1
AAA
Disclosure of fair value of plan assets [line items]
Bonds	24	28
AA
Disclosure of fair value of plan assets [line items]
Bonds	38	54
A
Disclosure of fair value of plan assets [line items]
Bonds	26	36
Loans	1
BBB
Disclosure of fair value of plan assets [line items]
Bonds	19	25
Loans	1
Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	6	10
Level I
Disclosure of fair value of plan assets [line items]
Alternative funds	0
Money market and cash and cash equivalents	0	0
Total	51	48
Level I | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level I | US
Disclosure of fair value of plan assets [line items]
Equity securities	12	0
Level I | International
Disclosure of fair value of plan assets [line items]
Equity securities	38	47
Level I | Private
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level I | AAA
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Level I | AA
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Level I | A
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Loans	0
Level I | BBB
Disclosure of fair value of plan assets [line items]
Bonds	1	1
Loans	0
Level I | Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Level II
Disclosure of fair value of plan assets [line items]
Alternative funds	0
Money market and cash and cash equivalents	20	20
Total	198	300
Level II | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	18	29
Level II | US
Disclosure of fair value of plan assets [line items]
Equity securities	5	20
Level II | International
Disclosure of fair value of plan assets [line items]
Equity securities	41	79
Level II | Private
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level II | AAA
Disclosure of fair value of plan assets [line items]
Bonds	24	28
Level II | AA
Disclosure of fair value of plan assets [line items]
Bonds	38	54
Level II | A
Disclosure of fair value of plan assets [line items]
Bonds	26	36
Loans	1
Level II | BBB
Disclosure of fair value of plan assets [line items]
Bonds	18	24
Loans	1
Level II | Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	6	10
Level III
Disclosure of fair value of plan assets [line items]
Alternative funds	39
Money market and cash and cash equivalents	0	0
Total	40	5
Level III | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	0	4
Level III | US
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level III | International
Disclosure of fair value of plan assets [line items]
Equity securities	0	0
Level III | Private
Disclosure of fair value of plan assets [line items]
Equity securities	1	1
Level III | AAA
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Level III | AA
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Level III | A
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Loans	0
Level III | BBB
Disclosure of fair value of plan assets [line items]
Bonds	0	0
Loans	0
Level III | Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	$ 0	$ 0

Employee Future Benefits - Defi

Employee Future Benefits - Defined Benefit Obligation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	$ 240
Defined benefit obligation, ending of period	158	$ 240
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	593
Defined benefit obligation, ending of period	447	593
Registered
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	130
Defined benefit obligation, ending of period	71	130
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	469	542
Current service cost	1	3
Interest cost	13	12
Benefits paid	(57)	(54)
Curtailment		(7)
Actuarial gain arising from financial assumptions	(83)	(26)
Actuarial loss (gain) arising from experience adjustments	1	(1)
Change in foreign exchange rates	1
Defined benefit obligation, ending of period	345	469
Supplemental
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	87
Defined benefit obligation, ending of period	70	87
Supplemental | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	101	109
Current service cost	1	2
Interest cost	3	2
Benefits paid	(5)	(5)
Curtailment		0
Actuarial gain arising from financial assumptions	(22)	(7)
Actuarial loss (gain) arising from experience adjustments	7	0
Change in foreign exchange rates	0
Defined benefit obligation, ending of period	85	101
Other
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	23
Defined benefit obligation, ending of period	17	23
Other | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	23	24
Current service cost	0	1
Interest cost	0	0
Benefits paid	1	(1)
Curtailment		0
Actuarial gain arising from financial assumptions	(5)	(1)
Actuarial loss (gain) arising from experience adjustments	(2)	0
Change in foreign exchange rates	0
Defined benefit obligation, ending of period	17	23
Total | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	593	675
Current service cost	2	6
Interest cost	16	14
Benefits paid	(61)	(60)
Curtailment		(7)
Actuarial gain arising from financial assumptions	(110)	(34)
Actuarial loss (gain) arising from experience adjustments	6	(1)
Change in foreign exchange rates	1
Defined benefit obligation, ending of period	$ 447	$ 593

Employee Future Benefits - Cont

Employee Future Benefits - Contributions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 CAD ($)
Registered
Disclosure of defined benefit plans [line items]
Expected employer contributions	$ 1
Supplemental
Disclosure of defined benefit plans [line items]
Expected employer contributions	6
Other
Disclosure of defined benefit plans [line items]
Expected employer contributions	2
Total
Disclosure of defined benefit plans [line items]
Expected employer contributions	$ 9

Employee Future Benefits - Assu

Employee Future Benefits - Assumptions (Details)	12 Months Ended
	Dec. 31, 2022 age	Dec. 31, 2022 Rate	Dec. 31, 2021 Rate
Other, through 2027
Assumed health-care cost trend rate
Health-care cost escalation	4.50%	4.50%
Maximum age disabled and retired members eligible for benefits	65	65
Percentage of reasonably possible decrease in actuarial assumption	0.30%	0.30%
Other, through 2030
Assumed health-care cost trend rate
Health-care cost escalation	4.50%	4.50%	4.50%
Maximum age disabled and retired members eligible for benefits		65	65
Percentage of reasonably possible decrease in actuarial assumption	0.30%	0.30%	0.30%
Other, through 2030 | Canada
Assumed health-care cost trend rate
Health-care cost escalation	4.50%	4.50%	4.50%
Other, 2029 through 2030
Assumed health-care cost trend rate
Maximum age disabled and retired members eligible for benefits			65
Other, 2029 through 2030 | Canada
Assumed health-care cost trend rate
Health-care cost escalation			4.50%
Other, 2029 through 2030 | US
Assumed health-care cost trend rate
Health-care cost escalation			4.50%
Percentage of reasonably possible decrease in actuarial assumption			0.30%
Accrued Benefit Obligation | Registered
Disclosure of defined benefit plans [line items]
Discount rate	4.70%	4.70%	2.80%
Rate of compensation increase	2.60%	2.60%	2.90%
Assumed health-care cost trend rate
Health-care cost escalation	0%	0%	0%
Dental-care cost escalation	0%	0%	0%
Accrued Benefit Obligation | Supplemental
Disclosure of defined benefit plans [line items]
Discount rate	5%	5%	2.80%
Rate of compensation increase	3%	3%	3%
Assumed health-care cost trend rate
Health-care cost escalation	0%	0%	0%
Dental-care cost escalation	0%	0%	0%
Accrued Benefit Obligation | Other, through 2027
Disclosure of defined benefit plans [line items]
Discount rate	5%	5%	2.70%
Rate of compensation increase	0%	0%	0%
Assumed health-care cost trend rate
Health-care cost escalation	7.10%	7.10%	6.80%
Dental-care cost escalation	4.20%	4.20%	4%
Other, through 2027 | Registered
Disclosure of defined benefit plans [line items]
Discount rate	2.80%	2.80%	2.40%
Rate of compensation increase	2.90%	2.90%	2.90%
Assumed health-care cost trend rate
Health-care cost escalation	0%	0%	0%
Dental-care cost escalation	0%	0%	0%
Other, through 2027 | Supplemental
Disclosure of defined benefit plans [line items]
Discount rate	2.80%	2.80%	2.30%
Rate of compensation increase	3%	3%	3%
Assumed health-care cost trend rate
Health-care cost escalation	0%	0%	0%
Dental-care cost escalation	0%	0%	0%
Other, through 2027 | Other, through 2027
Disclosure of defined benefit plans [line items]
Discount rate	2.70%	2.70%	2.30%
Rate of compensation increase	0%	0%	0%
Assumed health-care cost trend rate
Health-care cost escalation	6.80%	6.80%	7.10%
Dental-care cost escalation	4.70%	4.70%	4%

Employee Future Benefits - Sens

Employee Future Benefits - Sensitivity Analysis (Details) $ in Millions	Dec. 31, 2022 CAD ($)
1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible increase in actuarial assumption (as percent)	1%
1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible increase in actuarial assumption (as percent)	1%
1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible increase in actuarial assumption (as percent)	1%
10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible increase in actuarial assumption (as percent)	10%
Registered Pension Plan | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	$ 31
Registered Pension Plan | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1
Registered Pension Plan | Canada | 1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Registered Pension Plan | Canada | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	12
Registered Pension Plan | US | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	2
Registered Pension Plan | US | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Registered Pension Plan | US | 1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Registered Pension Plan | US | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1
Supplemental | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	10
Supplemental | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Supplemental | Canada | 1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Supplemental | Canada | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	2
Other | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	2
Other | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Other | Canada | 1% increase in the health-care cost trend rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1
Other | Canada | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	$ 0

Joint Arrangements (Details)

Joint Arrangements (Details)	12 Months Ended
	Dec. 31, 2022
Wind and Solar | Skookumchuck
Disclosure of joint operations [line items]
Proportion of ownership interest in joint venture	49%
Sheerness | Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50%
Goldfields Power | Australian Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50%
Fort Saskatchewan | Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	60%
Fortescue River Gas Pipeline | Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	43%
McBride Lake | Wind and Solar
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50%
Soderglen | Wind and Solar
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50%
Pingston | Hydro generation
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50%

Cash Flow Information - Disclos

Cash Flow Information - Disclosure of Non-cash Operating Working Capital (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of cash flow statement [Abstract]
Accounts receivable	$ (869)	$ (28)	$ (79)
Prepaid expenses	0	9	2
Income taxes receivable	(61)	0	(4)
Inventory	6	42	6
Accounts payable, accrued liabilities and provisions	548	153	160
Income taxes payable	60	(2)	4
Change in non-cash operating working capital	$ (316)	$ 174	$ 89

Cash Flow Information Changes i

Cash Flow Information Changes in Liabilities from Financing Activities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	$ 4,064	$ 4,150
Cash issuances	981	173
Repayments and dividends paid	(727)	(301)
New leases	40	1
Dividends declared	103	90
Foreign exchange impact	39	(39)
Other	(24)	(10)
Balance at end of the period	4,476	4,064	$ 4,150
Net increase (decrease) in borrowings under credit facilities	449	(114)	(106)
Issuance of long-term debt	532	173	753
Repayment of long-term debt	(621)	(92)	(489)
Decrease in lease liabilities	(9)	(8)	(25)
Long-term debt and lease liabilities
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	3,267	3,361
Cash issuances	981	173
Repayments and dividends paid	(630)	(214)
New leases	40	1
Dividends declared	0	0
Foreign exchange impact	39	(39)
Other	(28)	(15)
Balance at end of the period	3,669	3,267	3,361
Exchangeable securities
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	735	730
Cash issuances	0	0
Repayments and dividends paid	0	0
New leases	0	0
Dividends declared	0	0
Foreign exchange impact	0	0
Other	4	5
Balance at end of the period	739	735	730
Dividends payable (common and preferred)
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	62	59
Cash issuances	0	0
Repayments and dividends paid	(97)	(87)
New leases	0	0
Dividends declared	103	90
Foreign exchange impact	0	0
Other	0	0
Balance at end of the period	$ 68	$ 62	$ 59

Capital - Disclosure of Compone

Capital - Disclosure of Components of Capital (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of components of capital [Line Items]
Long-term debt		$ 3,653	$ 3,267
Increase (decrease) in long-term debt		386
Exchangeable securities		739	735
Increase (decrease) in exchangeable securities		4
Bank overdraft		16	0
Increase (decrease) in bank overdrafts		16
Equity		1,989	2,593	$ 3,436
Less: available cash and cash equivalents		(1,134)	(947)
Increase (decrease) in available cash and cash equivalents		(187)
Less: principal portion of restricted cash on TransAlta OCP bonds		(70)	(70)
Less: fair value asset of hedging instruments on long-term debt		(3)	(2)
Increase (decrease) in fair value asset of hedging instruments on long-term debt		(1)
Total capital		5,243	5,629
Increase (decrease) in total capital		(386)
Common shares
Disclosure of components of capital [Line Items]
Equity		2,863	2,901
Increase (decrease) in equity		(38)
Preferred shares
Disclosure of components of capital [Line Items]
Equity		942	942
Increase (decrease) in equity		0
Contributed surplus
Disclosure of components of capital [Line Items]
Equity		41	46	38
Increase (decrease) in equity		(5)
Deficit
Disclosure of components of capital [Line Items]
Equity		(2,514)	(2,453)	(1,826)
Increase (decrease) in equity		(61)
Accumulated other comprehensive income (loss)
Disclosure of components of capital [Line Items]
Equity	[1]	(222)	146	302
Increase (decrease) in equity		(368)
Non-controlling interests
Disclosure of components of capital [Line Items]
Equity		879	1,011	$ 1,084
Increase (decrease) in equity		(132)
TransAlta OCP
Disclosure of components of capital [Line Items]
Less: principal portion of restricted cash on TransAlta OCP bonds		(17)	$ (17)
Increase (decrease) in principal portion of restricted cash on TransAlta OCP bonds		$ 0
[1]Refer to Note 30 for details on components of and changes in, accumulated other comprehensive income (loss).

Capital - Disclosure of Cash Fl

Capital - Disclosure of Cash Flow Statement (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of classes of share capital [line items]
Cash flow from operating activities	$ 877	$ 1,001	$ 702
Increase (decrease) in cash flow from operating activities	(124)
Change in non-cash working capital	316	(174)	(89)
Increase (decrease) in change in non-cash working capital	490
Cash flow from operations before changes in working capital	1,193	827	613
Increase (decrease) in cash flow from operations before changes in working capital	366
Distributions paid to subsidiaries’ non-controlling interests	187	156	97
Increase (decrease) in dividends paid to non controlling interests	(31)
Property, plant and equipment expenditures	918	480	486
Increase (decrease) in property, plant and equipment expenditure	(438)
Net inflows (outflows) of cash	(9)	104
Increase (decrease) in net inflows (outflows) of cash	(113)
Committed syndicated bank facility | Committed credit facilities
Disclosure of classes of share capital [line items]
Undrawn borrowing capacity	1,000	1,300
Common shares
Disclosure of classes of share capital [line items]
Dividends paid	54	48	47
Increase (decrease) in dividends paid	(6)
Preferred shares
Disclosure of classes of share capital [line items]
Dividends paid	43	$ 39	$ 39
Increase (decrease) in dividends paid	$ (4)

Related Party Transactions - Di

Related Party Transactions - Disclosure of Interests in Subsidiaries (Details)	12 Months Ended
	Dec. 31, 2022
Canada | TransAlta Generation Partnership
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100%
Canada | TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	50.01%
Canada | TransAlta Energy Marketing Corp.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100%
Canada | TransAlta Energy (Australia), Pty Ltd.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	60.10%
US | SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Proportion of ownership interest in joint venture	49%
US | EMG
Disclosure of subsidiaries [line items]
Proportion of ownership interest in joint venture	30%
US | TransAlta Centralia Generation, LLC
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100%
US | TransAlta Energy Marketing (U.S.), Inc.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100%
Australia | TransAlta Energy (Australia), Pty Ltd.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	100%

Related Party Transactions - _2

Related Party Transactions - Disclosure of Information about Key Management Personnel (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Related Party [Abstract]
Total compensation	$ 23	$ 30	$ 27
Short-term employee benefits	11	14	12
Post-employment benefits	1	1	2
Share-based payments	$ 11	$ 15	$ 13

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) $ in Millions, $ in Millions, $ in Millions	Apr. 01, 2022 CAD ($)	Nov. 05, 2021 USD ($) MW	Feb. 26, 2021 CAD ($) MW	Aug. 01, 2020 CAD ($)	Dec. 31, 2022 CAD ($)	Oct. 23, 2022 AUD ($)	Dec. 31, 2021 CAD ($)	Dec. 31, 2021 USD ($)	Apr. 01, 2021 MW
Disclosure of subsidiaries [line items]
Receivables due from associates							$ (18)	$ (14)
Cash drawings					$ 3,653		3,267
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Cash drawings						$ 157
US Wind Projects
Disclosure of subsidiaries [line items]
Exchangeable debentures							$ 7	$ 6
WindCharger Battery Storage Project
Disclosure of subsidiaries [line items]
Aggregate consideration				$ 12
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Aggregate consideration			$ 213
Solar Facilities In North Carolina | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Membership interest		100%
Capacity of facility (in megawatts) | MW		122
Aggregate consideration		$ 102
Ada Cogeneration Facility
Disclosure of subsidiaries [line items]
Capacity of facility (in megawatts) | MW									29
Ada Cogeneration Facility | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Membership interest									100%
Aggregate consideration	$ 43
Skookumchuck
Disclosure of subsidiaries [line items]
Capacity of facility (in megawatts) | MW									137
Skookumchuck | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Membership interest									49%
Aggregate consideration	$ 103
Windrise Wind Facility
Disclosure of subsidiaries [line items]
Capacity of facility (in megawatts) | MW			206
Windrise Wind Facility | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Membership interest			100%

Related Party Transactions - _3

Related Party Transactions - Disclosure of Transactions with Associates (Details) - Associates - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of transactions between related parties [line items]
Power sales	$ 127	$ 27	$ 10
Purchased power	12	3	3
Asset management fees paid	$ 2	$ 2	$ 1

Commitments and Contingencies -

Commitments and Contingencies - Commitments (Details) $ in Millions, $ in Millions	Dec. 31, 2022 CAD ($)	Jul. 30, 2015 USD ($)
Disclosure of Commitments [Line Items]
Coal supply agreements	$ 241
Long-term service agreements	328
Operating leases	42
Growth	446
TransAlta Energy Transition Bill	6	$ 55
Total	1,826
Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	696
Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	67
2023
Disclosure of Commitments [Line Items]
Coal supply agreements	83
Long-term service agreements	51
Operating leases	3
Growth	446
TransAlta Energy Transition Bill	6
Total	655
2023 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	56
2023 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	10
2024
Disclosure of Commitments [Line Items]
Coal supply agreements	87
Long-term service agreements	49
Operating leases	3
Growth	0
TransAlta Energy Transition Bill	0
Total	193
2024 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	47
2024 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	7
2025
Disclosure of Commitments [Line Items]
Coal supply agreements	71
Long-term service agreements	35
Operating leases	3
Growth	0
TransAlta Energy Transition Bill	0
Total	161
2025 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	45
2025 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	7
2026
Disclosure of Commitments [Line Items]
Coal supply agreements	0
Long-term service agreements	32
Operating leases	2
Growth	0
TransAlta Energy Transition Bill	0
Total	82
2026 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	45
2026 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	3
2027
Disclosure of Commitments [Line Items]
Coal supply agreements	0
Long-term service agreements	21
Operating leases	2
Growth	0
TransAlta Energy Transition Bill	0
Total	70
2027 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	46
2027 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	1
2028
Disclosure of Commitments [Line Items]
Coal supply agreements	0
Long-term service agreements	140
Operating leases	29
Growth	0
TransAlta Energy Transition Bill	0
Total	665
2028 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	457
2028 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	$ 39

Commitments and Contingencies_2

Commitments and Contingencies - Narrative (Details) TJ in Millions, $ in Millions, $ in Millions	Dec. 31, 2022 USD ($) TJ	Dec. 31, 2022 CAD ($) TJ	Jul. 30, 2015 USD ($)
Disclosure of Commitments [Line Items]
Total firm natural gas transportation | TJ	75	75
TransAlta Energy Transition Bill		$ 6	$ 55
Funded portion of energy bill commitment | $	$ 50
Kent Hills Wind Rehabilitation Project
Disclosure of Commitments [Line Items]
Capital expenditures | $		$ 120
Pioneer Pipeline
Disclosure of Commitments [Line Items]
Total firm natural gas transportation | TJ	400	400

Segments Disclosures - Addition

Segments Disclosures - Additional Information (Details) - segment	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Disclosure of major customers [line items]
Number of segments	6
Customer 1
Disclosure of major customers [line items]
Percentage of entity's revenue	60%	35%

Segments Disclosures - Reported

Segments Disclosures - Reported Segment Earnings (Loss) and Segment Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of operating segments [line items]
Revenues	$ 2,976	$ 2,721	$ 2,101
Fuel and purchased power	1,263	1,054	805
Carbon compliance	78	178	163
Gross margin	1,635	1,489	1,133
OM&A		511	472
Taxes, other than income taxes	33	32	33
Net other operating (income) loss	(58)	8	(11)
Equity income	9	9	1
Finance lease income	19	25	7
Depreciation and amortization	(599)	(529)	(654)
Asset impairment charges	(9)	(648)	(84)
Net interest expense	262	245	238
Foreign exchange gain	4	16	17
Gain on sale of assets and other	52	54	9
Earnings (loss) before income taxes	353	(380)	(303)
Previously Reported
Disclosure of operating segments [line items]
Revenues	2,976	2,721	2,101
Fuel and purchased power	1,263	1,054	805
OM&A	521	511
Net other operating (income) loss	(58)	8	(11)
Operating segments
Disclosure of operating segments [line items]
Revenues	3,475	2,791	2,164
Fuel and purchased power	1,259	843	618
Carbon compliance	78	178	163
Gross margin	2,138	1,770	1,383
OM&A		491	472
Taxes, other than income taxes	35	33	33
Net other operating (income) loss	(54)	(40)	(39)
Adjusted EBITDA	1,634	1,286	917
Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	2,990	2,739	2,104
Fuel and purchased power	1,263	1,054	805
OM&A	523	513
Net other operating (income) loss	(61)	8	(11)
Operating segments | Unrealized mark-to-market loss
Disclosure of operating segments [line items]
Revenues	378	(34)	42
Operating segments | Realized (gain) loss on closed exchange positions
Disclosure of operating segments [line items]
Revenues	43	23	(10)
Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	46	41	17
Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenues	19	25	7
Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	(1)	(3)	4
Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	(4)	(4)	(4)
Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating (income) loss	7
Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power		(190)	(146)
Operating segments | Coal inventory write-down
Disclosure of operating segments [line items]
Fuel and purchased power		(17)	(37)
Operating segments | Parts and materials write-down
Disclosure of operating segments [line items]
OM&A		(28)
Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A		6
Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating (income) loss		(48)
Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating (income) loss			(28)
Material reconciling items
Disclosure of operating segments [line items]
Revenues	(485)	(52)	(60)
Fuel and purchased power	4	211	187
Carbon compliance	0	0	0
Gross margin	(489)	(263)	(247)
OM&A		22	0
Taxes, other than income taxes	0	0	0
Net other operating (income) loss	(7)	48	28
Material reconciling items | Previously Reported
Disclosure of operating segments [line items]
Revenues	0	0	0
Fuel and purchased power	0	0	0
OM&A	0	0
Net other operating (income) loss	0	0	0
Material reconciling items | Unrealized mark-to-market loss
Disclosure of operating segments [line items]
Revenues	(378)	34	(42)
Material reconciling items | Realized (gain) loss on closed exchange positions
Disclosure of operating segments [line items]
Revenues	(43)	(23)	10
Material reconciling items | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	(46)	(41)	(17)
Material reconciling items | Finance lease income
Disclosure of operating segments [line items]
Revenues	(19)	(25)	(7)
Material reconciling items | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	1	3	(4)
Material reconciling items | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	4	4	4
Material reconciling items | Insurance recovery
Disclosure of operating segments [line items]
Net other operating (income) loss	(7)
Material reconciling items | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power		190	146
Material reconciling items | Coal inventory write-down
Disclosure of operating segments [line items]
Fuel and purchased power		17	37
Material reconciling items | Parts and materials write-down
Disclosure of operating segments [line items]
OM&A		28
Material reconciling items | Curtailment gain
Disclosure of operating segments [line items]
OM&A		(6)
Material reconciling items | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating (income) loss		48
Material reconciling items | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating (income) loss			28
Material reconciling items | Contribution from equity accounted investments
Disclosure of operating segments [line items]
Revenues	(14)	(18)	(3)
Fuel and purchased power	0	0	0
Carbon compliance	0	0	0
Gross margin	(14)	(18)	(3)
OM&A		(2)	0
Taxes, other than income taxes	(2)	(1)	0
Net other operating (income) loss	3	0	0
Material reconciling items | Contribution from equity accounted investments | Previously Reported
Disclosure of operating segments [line items]
Revenues	(14)	(18)	(3)
Fuel and purchased power	0	0	0
OM&A	(2)	(2)
Net other operating (income) loss	3	0	0
Material reconciling items | Contribution from equity accounted investments | Unrealized mark-to-market loss
Disclosure of operating segments [line items]
Revenues	0	0	0
Material reconciling items | Contribution from equity accounted investments | Realized (gain) loss on closed exchange positions
Disclosure of operating segments [line items]
Revenues	0	0	0
Material reconciling items | Contribution from equity accounted investments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	0	0	0
Material reconciling items | Contribution from equity accounted investments | Finance lease income
Disclosure of operating segments [line items]
Revenues	0	0	0
Material reconciling items | Contribution from equity accounted investments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	0	0	0
Material reconciling items | Contribution from equity accounted investments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Material reconciling items | Contribution from equity accounted investments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating (income) loss	0
Material reconciling items | Contribution from equity accounted investments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Material reconciling items | Contribution from equity accounted investments | Coal inventory write-down
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Material reconciling items | Contribution from equity accounted investments | Parts and materials write-down
Disclosure of operating segments [line items]
OM&A		0
Material reconciling items | Contribution from equity accounted investments | Curtailment gain
Disclosure of operating segments [line items]
OM&A		0
Material reconciling items | Contribution from equity accounted investments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating (income) loss		0
Material reconciling items | Contribution from equity accounted investments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating (income) loss			0
Hydro | Operating segments
Disclosure of operating segments [line items]
Revenues	607	383	152
Fuel and purchased power	22	16	8
Carbon compliance	0	0	0
Gross margin	585	367	144
OM&A		42	37
Taxes, other than income taxes	3	3	2
Net other operating (income) loss	0	0	0
Adjusted EBITDA	527	322	105
Hydro | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	606	383	152
Fuel and purchased power	22	16	8
OM&A	55	42
Net other operating (income) loss	0	0	0
Hydro | Operating segments | Unrealized mark-to-market loss
Disclosure of operating segments [line items]
Revenues	1	0	0
Hydro | Operating segments | Realized (gain) loss on closed exchange positions
Disclosure of operating segments [line items]
Revenues	0	0	0
Hydro | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	0	0	0
Hydro | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenues	0	0	0
Hydro | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	0	0	0
Hydro | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Hydro | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating (income) loss	0
Hydro | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Hydro | Operating segments | Coal inventory write-down
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Hydro | Operating segments | Parts and materials write-down
Disclosure of operating segments [line items]
OM&A		0
Hydro | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A		0
Hydro | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating (income) loss		0
Hydro | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating (income) loss			0
Wind and Solar | Operating segments
Disclosure of operating segments [line items]
Revenues	407	348	334
Fuel and purchased power	31	17	25
Carbon compliance	1	0	0
Gross margin	375	331	309
OM&A		59	53
Taxes, other than income taxes	12	10	8
Net other operating (income) loss	(16)	0	0
Adjusted EBITDA	311	262	248
Wind and Solar | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	303	323	332
Fuel and purchased power	31	17	25
OM&A	68	59
Net other operating (income) loss	(23)	0	0
Wind and Solar | Operating segments | Unrealized mark-to-market loss
Disclosure of operating segments [line items]
Revenues	104	25	2
Wind and Solar | Operating segments | Realized (gain) loss on closed exchange positions
Disclosure of operating segments [line items]
Revenues	0	0	0
Wind and Solar | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	0	0	0
Wind and Solar | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenues	0	0	0
Wind and Solar | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	0	0	0
Wind and Solar | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Wind and Solar | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating (income) loss	7
Wind and Solar | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Wind and Solar | Operating segments | Coal inventory write-down
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Wind and Solar | Operating segments | Parts and materials write-down
Disclosure of operating segments [line items]
OM&A		0
Wind and Solar | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A		0
Wind and Solar | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating (income) loss		0
Wind and Solar | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating (income) loss			0
Gas | Operating segments
Disclosure of operating segments [line items]
Revenues	1,521	1,126	848
Fuel and purchased power	637	374	221
Carbon compliance	83	118	120
Gross margin	801	634	507
OM&A		173	166
Taxes, other than income taxes	15	13	13
Net other operating (income) loss	(38)	(40)	(39)
Adjusted EBITDA	629	488	367
Gas | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	1,209	1,109	787
Fuel and purchased power	641	457	325
OM&A	195	175
Net other operating (income) loss	(38)	(40)	(11)
Gas | Operating segments | Unrealized mark-to-market loss
Disclosure of operating segments [line items]
Revenues	251	(40)	33
Gas | Operating segments | Realized (gain) loss on closed exchange positions
Disclosure of operating segments [line items]
Revenues	(4)	(6)	0
Gas | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	46	41	17
Gas | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenues	19	25	7
Gas | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	0	(3)	4
Gas | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	(4)	(4)	(4)
Gas | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating (income) loss	0
Gas | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power		(79)	(100)
Gas | Operating segments | Coal inventory write-down
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Gas | Operating segments | Parts and materials write-down
Disclosure of operating segments [line items]
OM&A		(2)
Gas | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A		0
Gas | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating (income) loss		0
Gas | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating (income) loss			(28)
Energy Transition
Disclosure of operating segments [line items]
Asset impairment charges		(191)
Energy Transition | Operating segments
Disclosure of operating segments [line items]
Revenues	724	728	690
Fuel and purchased power	566	432	352
Carbon compliance	(1)	60	48
Gross margin	159	236	290
OM&A		97	106
Taxes, other than income taxes	4	6	9
Net other operating (income) loss	0	0	0
Adjusted EBITDA	86	133	175
Energy Transition | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	714	709	704
Fuel and purchased power	566	560	435
OM&A	69	117
Net other operating (income) loss	0	48	0
Energy Transition | Operating segments | Unrealized mark-to-market loss
Disclosure of operating segments [line items]
Revenues	10	19	(14)
Energy Transition | Operating segments | Realized (gain) loss on closed exchange positions
Disclosure of operating segments [line items]
Revenues	0	0	0
Energy Transition | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	0	0	0
Energy Transition | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenues	0	0	0
Energy Transition | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	0	0	0
Energy Transition | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Energy Transition | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating (income) loss	0
Energy Transition | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power		(111)	(46)
Energy Transition | Operating segments | Coal inventory write-down
Disclosure of operating segments [line items]
Fuel and purchased power		(17)	(37)
Energy Transition | Operating segments | Parts and materials write-down
Disclosure of operating segments [line items]
OM&A		(26)
Energy Transition | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A		6
Energy Transition | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating (income) loss		(48)
Energy Transition | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating (income) loss			0
Energy Marketing | Operating segments
Disclosure of operating segments [line items]
Revenues	218	202	133
Fuel and purchased power	0	0	0
Carbon compliance	0	0	0
Gross margin	218	202	133
OM&A		36	30
Taxes, other than income taxes	0	0	0
Net other operating (income) loss	0	0	0
Adjusted EBITDA	183	166	103
Energy Marketing | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	160	211	122
Fuel and purchased power	0	0	0
OM&A	35	36
Net other operating (income) loss	0	0	0
Energy Marketing | Operating segments | Unrealized mark-to-market loss
Disclosure of operating segments [line items]
Revenues	12	(38)	21
Energy Marketing | Operating segments | Realized (gain) loss on closed exchange positions
Disclosure of operating segments [line items]
Revenues	47	29	(10)
Energy Marketing | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	0	0	0
Energy Marketing | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenues	0	0	0
Energy Marketing | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	(1)	0	0
Energy Marketing | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Energy Marketing | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating (income) loss	0
Energy Marketing | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Energy Marketing | Operating segments | Coal inventory write-down
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Energy Marketing | Operating segments | Parts and materials write-down
Disclosure of operating segments [line items]
OM&A		0
Energy Marketing | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A		0
Energy Marketing | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating (income) loss		0
Energy Marketing | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating (income) loss			0
Corporate | Operating segments
Disclosure of operating segments [line items]
Revenues	(2)	4	7
Fuel and purchased power	3	4	12
Carbon compliance	(5)	0	(5)
Gross margin	0	0	0
OM&A		84	80
Taxes, other than income taxes	1	1	1
Net other operating (income) loss	0	0	0
Adjusted EBITDA	(102)	(85)	(81)
Corporate | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	(2)	4	7
Fuel and purchased power	3	4	12
OM&A	101	84
Net other operating (income) loss	0	0	0
Corporate | Operating segments | Unrealized mark-to-market loss
Disclosure of operating segments [line items]
Revenues	0	0	0
Corporate | Operating segments | Realized (gain) loss on closed exchange positions
Disclosure of operating segments [line items]
Revenues	0	0	0
Corporate | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	0	0	0
Corporate | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenues	0	0	0
Corporate | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	0	0	0
Corporate | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Corporate | Operating segments | Insurance recovery
Disclosure of operating segments [line items]
Net other operating (income) loss	$ 0
Corporate | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Corporate | Operating segments | Coal inventory write-down
Disclosure of operating segments [line items]
Fuel and purchased power		0	0
Corporate | Operating segments | Parts and materials write-down
Disclosure of operating segments [line items]
OM&A		0
Corporate | Operating segments | Curtailment gain
Disclosure of operating segments [line items]
OM&A		0
Corporate | Operating segments | Royalty onerous contract and contract termination penalties
Disclosure of operating segments [line items]
Net other operating (income) loss		$ 0
Corporate | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating (income) loss			$ 0

Segments Disclosures - Selected

Segments Disclosures - Selected Consolidated Statements of Financial Position Information (Details) - CAD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of operating segments [line items]
PP&E	$ 5,556	$ 5,320	$ 5,822
Right-of-use assets	126	95	141
Intangible assets	252	256	$ 313
Goodwill	464	463
Wind and Solar
Disclosure of operating segments [line items]
Goodwill	176	175
Energy Marketing
Disclosure of operating segments [line items]
Goodwill	30	30
Corporate
Disclosure of operating segments [line items]
PP&E	111	33
Right-of-use assets	14	18
Intangible assets	31	36
Goodwill	0	0
Operating segments | Hydro
Disclosure of operating segments [line items]
PP&E	437	466
Right-of-use assets	6	5
Intangible assets	2	3
Goodwill	258	258
Operating segments | Wind and Solar
Disclosure of operating segments [line items]
PP&E	2,837	2,304
Right-of-use assets	98	64
Intangible assets	157	147
Goodwill	176	175
Operating segments | Gas
Disclosure of operating segments [line items]
PP&E	1,858	2,036
Right-of-use assets	6	7
Intangible assets	49	56
Goodwill	0	0
Operating segments | Energy Transition
Disclosure of operating segments [line items]
PP&E	313	481
Right-of-use assets	2	1
Intangible assets	5	9
Goodwill	0	0
Operating segments | Energy Marketing
Disclosure of operating segments [line items]
PP&E	0	0
Right-of-use assets	0	0
Intangible assets	8	5
Goodwill	$ 30	$ 30

Segments Disclosures - Additi_2

Segments Disclosures - Additions to non-current assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of operating segments [line items]
PP&E	$ 918	$ 480	$ 486
Intangible assets	31	9	14
Corporate
Disclosure of operating segments [line items]
PP&E	75	28	13
Intangible assets	9	8	13
Operating segments | Hydro
Disclosure of operating segments [line items]
PP&E	36	29	22
Intangible assets	0	0	0
Operating segments | Wind and Solar
Disclosure of operating segments [line items]
PP&E	745	166	174
Intangible assets	19	0	0
Operating segments | Gas
Disclosure of operating segments [line items]
PP&E	43	167	199
Intangible assets	0	0	0
Operating segments | Energy Transition
Disclosure of operating segments [line items]
PP&E	19	90	78
Intangible assets	0	1	1
Operating segments | Energy Marketing
Disclosure of operating segments [line items]
PP&E	0	0	0
Intangible assets	$ 3	$ 0	$ 0

Segments Disclosures - Deprecia

Segments Disclosures - Depreciation and Amortization on the Consolidated Statements of Cash Flows (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of operating segments [abstract]
Depreciation and amortization expense on the Consolidated Statements of Earnings (Loss)	$ 599	$ 529	$ 654
Depreciation included in fuel and purchased power	0	190	144
Depreciation and amortization on the Consolidated Statements of Cash Flows	$ 599	$ 719	$ 798

Segments Disclosures - Geograph

Segments Disclosures - Geographic Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disclosure of geographical areas [line items]
Total revenue from contracts with customers	$ 2,976	$ 2,721	$ 2,101
PP&E	5,556	5,320	5,822
Right-of-use assets	126	95	141
Intangible assets	252	256	313
Total long-term other assets	160	142
Canada
Disclosure of geographical areas [line items]
Total revenue from contracts with customers	1,905	1,854	1,227
PP&E	3,817	4,051
Right-of-use assets	49	52
Intangible assets	123	141
Total long-term other assets	62	15
US
Disclosure of geographical areas [line items]
Total revenue from contracts with customers	940	731	716
PP&E	1,307	860
Right-of-use assets	74	39
Intangible assets	101	85
Total long-term other assets	34	61
Australia
Disclosure of geographical areas [line items]
Total revenue from contracts with customers	131	136	$ 158
PP&E	432	409
Right-of-use assets	3	4
Intangible assets	28	30
Total long-term other assets	$ 64	$ 66

Subsequent Events (Details)

Subsequent Events (Details) - Major business combination - Montem Resources Limited $ in Millions	Feb. 16, 2023 CAD ($) MW
Pumped Hydro Development Project
Disclosure of non-adjusting events after reporting period [line items]
Membership interest	50%
Capacity of facility (in megawatts) | MW	320
Cash consideration | $	$ 8
Contingent consideration | $	17
Aggregate consideration | $	$ 25
Green Hydrogen Electrolyser
Disclosure of non-adjusting events after reporting period [line items]
Capacity of facility (in megawatts) | MW	100
Wind Development Project
Disclosure of non-adjusting events after reporting period [line items]
Capacity of facility (in megawatts) | MW	100