TransAlta (TAC) 40-F 24 Feb 22 2021 FY Annual report (Canada) Financial data

Cover

Cover	12 Months Ended
	Dec. 31, 2021shares
Cover [Abstract]
Document Type	40-F
Document Period End Date	Dec. 31, 2021
Amendment Flag	false
Entity Central Index Key	0001144800
Entity Registrant Name	TRANSALTA CORPORATION
Entity Current Reporting Status	Yes
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Entity Emerging Growth Company	false
Entity Incorporation, State or Country Code	Z4
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Interactive Data Current	Yes
Entity Address, Address Line One	110-12th Avenue S.W., Box 1900, Station “M”
Entity Address, City or Town	Calgary
Entity File Number	001-15214
Entity Address, State or Province	AB
Entity Address, Postal Zip Code	T2P 2M1
City Area Code	403
Local Phone Number	267-7110
ICFR Auditor Attestation Flag	true
Document Annual Report	true
Document Registration Statement	false
Entity Common Stock, Shares Outstanding	271,034,933
Entity Addresses [Line Items]
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
Entity Current Reporting Status	Yes
Business Contact
Cover [Abstract]
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
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, 2021
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Profit or loss [abstract]
Revenues	$ 2,721	$ 2,101	$ 2,347
Fuel and purchased power	1,054	805	881
Carbon compliance	178	163	205
Gross margin	1,489	1,133	1,261
Operations, maintenance, and administration	511	472	475
Depreciation and amortization	529	654	590
Asset impairment charge	648	84	25
Gain on termination of Keephills 3 coal rights contract	0	0	(88)
Taxes, other than income taxes	32	33	29
Termination of Sundance B and C PPAs	0	0	(56)
Net other operating loss (income)	8	(11)	(49)
Operating income (loss)	(239)	(99)	335
Equity income	9	1	0
Finance lease income	25	7	6
Net interest expense	(245)	(238)	(179)
Foreign exchange gain (loss)	16	17	(15)
Gain on sale of assets and other (Note 4 and 18)	54	9	46
Earnings (loss) before income taxes	(380)	(303)	193
Income tax expense (recovery)	45	(50)	17
Net earnings (loss)	(425)	(253)	176
Net earnings (loss) attributable to:
TransAlta shareholders	(537)	(287)	82
Non-controlling interests (Note 12)	112	34	94
Net earnings (loss)	(425)	(253)	176
Preferred share dividends (Note 25)	39	49	30
Net earnings (loss) attributable to common shareholders	$ (576)	$ (336)	$ 52
Weighted average number of common shares outstanding in the year (in shares)	271,000	275,000	283,000
Net earnings (loss) per share attributable to common shareholders, basic (in CAD per share)	$ (2.13)	$ (1.22)	$ 0.18
Net earnings (loss) per share attributable to common shareholders, diluted (in CAD per share)	$ (2.13)	$ (1.22)	$ 0.18

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Earnings (Loss) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of comprehensive income [abstract]
Net earnings (loss)		$ (425)	$ (253)	$ 176
Other comprehensive loss
Net actuarial gains (losses) on defined benefit plans, net of tax	[1]	37	(11)	(26)
Losses on derivatives designated as cash flow hedges, net of tax		0	(1)	0
Total items that will not be reclassified subsequently to net earnings		37	(12)	(26)
Losses on translating net assets of foreign operations, net of tax		(14)	(11)	(59)
Gains on financial instruments designated as hedges of foreign operations, net of tax		0	11	21
Gains (losses) on derivatives designated as cash flow hedges, net of tax	[2]	(200)	20	61
Reclassification of gains on derivatives designated as cash flow hedges to net earnings, net of tax	[3]	(8)	(110)	(42)
Total items that will be reclassified subsequently to net earnings		(222)	(90)	(19)
Other comprehensive loss		(185)	(102)	(45)
Total comprehensive earnings (loss)		(610)	(355)	131
Total comprehensive earnings (loss) attributable to:
TransAlta shareholders		(693)	(439)	54
Non-controlling interests		$ 83	$ 84	$ 77
[1]	Net of income tax expense of $11 million for the year ended Dec. 31, 2021 (2020 — $3 million recovery, 2019 — $7 million recovery).
[2]	Net of income tax recovery of $55 million for the year ended Dec. 31, 2021 (2020 —$8 million expense, 2019 — $16 million expense).
[3]	Net of reclassification of income tax recovery of $2 million for the year ended Dec. 31, 2021 (2020 —$31 million recovery,  2019 — $10 million recovery).

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Earnings (Loss) (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of comprehensive income [abstract]
Net actuarial gains (losses)	$ 11	$ (3)	$ (7)
Gain (losses) on derivatives designated as cash flow hedges, income tax expense (recovery)	(55)	8	16
Reclassification of gains on derivatives designated as cash flow hedges to net earnings, income tax expense (recovery)	$ (2)	$ (31)	$ (10)

Consolidated Statements of Fina

Consolidated Statements of Financial Position - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Assets [abstract]
Cash and cash equivalents	$ 947	$ 703
Restricted cash	70	71
Trade and other receivables	651	583
Prepaid expenses	29	31
Risk management assets	308	171
Inventory	167	238
Assets held for sale	25	105
Current assets	2,197	1,902
Investments	105	100
Long-term portion of finance lease receivable	185	228
Risk management assets	399	521
PP&E	5,320	5,822
Right-of-use assets	95	141
Intangible assets	256	313
Goodwill	463	463
Deferred income tax assets	64	51
Other assets	142	206
Total assets	9,226	9,747
Liabilities [abstract]
Accounts payable and accrued liabilities	689	599
Current portion of decommissioning and other provisions	48	59
Risk management liabilities	261	94
Current contract liabilities	19	1
Income taxes payable	8	18
Dividends payable	62	59
Current portion of long-term debt and finance lease obligations	844	105
Current liabilities	1,931	935
Credit facilities, long-term debt and lease liabilities	2,423	3,256
Exchangeable securities	735	730
Decommissioning and other provisions	779	614
Deferred income tax liabilities	354	396
Risk management liabilities	145	68
Non-current contract liabilities	13	14
Defined benefit obligation and other long-term liabilities	253	298
Equity
Issued capital, ordinary shares	2,901	2,896
Issued capital, preference shares	942	942
Contributed surplus	46	38
Deficit	(2,453)	(1,826)
Accumulated other comprehensive income	146	302
Equity attributable to shareholders	1,582	2,352
Non-controlling interests	1,011	1,084
Total equity	2,593	3,436
Total liabilities and equity	9,226	9,747
Gross carrying amount
Assets [abstract]
PP&E	13,389	13,398
Intangible assets	827	833
Liabilities [abstract]
Accounts payable and accrued liabilities	689
Dividends payable	62
Exchangeable securities	750
Accumulated depreciation
Assets [abstract]
PP&E	(8,069)	(7,576)
Intangible assets	$ (571)	$ (520)

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - CAD ($) $ in Millions	Total	Common shares	Preferred shares	Issued capitalCommon shares	Issued capitalPreferred shares	Contributed surplus	Deficit	DeficitCommon shares	DeficitPreferred shares	Accumulated other comprehensive income	[1]	Attributable to shareholders	Attributable to shareholdersCommon shares	Attributable to shareholdersPreferred shares	Attributable to non-controlling interests
Balance, beginning of year at Dec. 31, 2019	$ 4,062			$ 2,978	$ 942	$ 42	$ (1,455)			$ 454		$ 2,961			$ 1,101
Changes in equity [abstract]
Net earnings (loss)	(253)						(287)					(287)			34
Other comprehensive loss
Net losses on derivatives designated as cash flow hedges, net of tax	(91)									(91)		(91)
Net actuarial losses on defined benefits plans, net of tax	(11)									(11)		(11)
Intercompany FVOCI investments	0									(50)		(50)			50
Total comprehensive earnings (loss)	(355)						(287)			(152)		(439)			84
Dividends	(49)	$ (58)	$ (49)					$ (58)	$ (49)				$ (58)	$ (49)
Changes in non-controlling interests in TransAlta Renewables (Note 13)	20						5					5			15
Shares purchased under NCIB	(61)			(79)			18					(61)
Effect of share-based payment plans (Note 30)	(7)			(3)		(4)						(7)
Distributions paid, and payable, to non-controlling interests	(116)														(116)
Balance, end 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 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)			0
Net actuarial losses on defined benefits plans, net of tax	37									37		37
Intercompany FVOCI investments	0											29			(29)
Total comprehensive earnings (loss)	(610)						(537)			(156)		(693)			83
Dividends	(39)	$ (51)	$ (39)					$ (51)	$ (39)				$ (51)	$ (39)
Effect of share-based payment plans (Note 30)	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
[1]	Refer to Note 29 for details on components of, and changes in, accumulated other comprehensive earnings (loss).

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating activities
Net earnings (loss)	$ (425)	$ (253)	$ 176
Depreciation and amortization	719	798	709
Net gain on sale of assets	(54)	(9)	(45)
Accretion of provisions	32	30	23
Decommissioning and restoration costs settled	(18)	(18)	(34)
Deferred income tax recovery	(11)	(85)	(18)
Unrealized (gain) loss from risk management activities	(34)	42	(32)
Unrealized foreign exchange (gain) loss	(24)	1	13
Provisions	(41)	9	13
Asset impairment charges	648	84	25
Equity income, net of distributions from investments (Note 10)	(5)	(1)	0
Other non-cash items	40	15	(102)
Cash flow from operations before changes in working capital	827	613	728
Change in non-cash operating working capital balances	174	89	121
Cash flow from operating activities	1,001	702	849
Investing activities
Additions to property, plant and equipment	(480)	(486)	(417)
Additions to intangibles	(9)	(14)	(14)
Restricted cash	(1)	(39)	34
Loan receivable	(3)	(5)	(10)
Acquisitions, net of cash acquired	(120)	(32)	(117)
Acquisition of investments (Note 10)	0	(102)	0
Investment in the Pioneer Pipeline	0	0	(83)
Proceeds on sale of Pioneer Pipeline	128	0	0
Proceeds on sale of property, plant and equipment	39	6	13
Realized gains (losses) on financial instruments	(6)	2	3
Decrease in finance lease receivable	41	17	24
Other	(16)	(12)	23
Change in non-cash investing working capital balances	(45)	(22)	32
Cash flow used in investing activities	(472)	(687)	(512)
Financing activities
Net increase (decrease) in borrowings under credit facilities	(114)	(106)	(119)
Repayment of long-term debt	(92)	(489)	(96)
Issuance of long-term debt	173	753	166
Issuance of exchangeable securities	0	400	350
Repurchase of common shares under NCIB	(4)	(57)	(68)
Proceeds on issuance of common shares	8	0	0
Realized gains on financial instruments	3	3	0
Distributions paid to subsidiaries' non-controlling interests	(156)	(97)	(106)
Decrease in finance lease obligations	(8)	(25)	(21)
Financing fees and other	(4)	(11)	(35)
Change in non-cash financing working capital balances	(1)	(13)	0
Cash flow from (used in) financing activities	(282)	272	(14)
Cash flow from operating, investing, and financing activities	247	287	323
Effect of translation on foreign currency cash	(3)	5	(1)
Increase in cash and cash equivalents	244	292	322
Cash and cash equivalents, beginning of year	703	411	89
Cash and cash equivalents, end of year	947	703	411
Supplemental cash flow information
Cash taxes paid	57	36	35
Cash interest paid	220	201	185
Common shares
Financing activities
Dividends paid	(48)	(47)	(45)
Preferred shares
Financing activities
Dividends paid	$ (39)	$ (39)	$ (40)

Corporate Information

Corporate Information	12 Months Ended
	Dec. 31, 2021
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. Its head office is located in Calgary, Alberta. I. Generation Segments During the fourth quarter of 2021, the Company realigned its current operating segments to better reflect a change in how TransAlta’s President and Chief Executive Officer (the chief operating decision maker) ("CODM") reviews financial information in order to allocate resources and assess performance. The primary changes are the elimination of the Alberta Thermal and the Centralia segments, and the reorganization of the North American Gas and Australia Gas segments into a new "Gas" segment. The Alberta Thermal facilities that have been converted to gas have been included in the Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets and those facilities not converted to gas and the remaining Centralia unit, are included in a new "Energy Transition" segment. No changes were made to the Hydro and Wind and Solar segments. This change better aligns with the Company's long-term strategy and reflects its Clean Electricity Growth Plan. The four generation segments of the Company are as follows: Hydro, Wind and Solar, Gas, and Energy Transition. Previously, the six generation segments were as follows: Hydro, Wind and Solar, North American Gas, Australian Gas, Alberta Thermal, and Centralia. The Company directly or indirectly owns and operates hydro, wind and solar, natural- gas-fired and coal-fired facilities, related mining operations 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. Revenues are derived from the availability and production of electricity and steam as well as ancillary services. Comparative segmented results for 2020 and 2019 have been restated to align with the 2021 operating segments. II. Energy Marketing Segment The Energy Marketing segment derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives. No change was made to the Energy Marketing segment. Energy Marketing manages available generating capacity as well as the fuel and transmission needs of the generation segments by utilizing contracts of various durations for the forward sales of electricity and for the purchase of natural gas and transmission capacity. Energy Marketing is also responsible for recommending portfolio optimization decisions. The results of these optimization activities are included in each generation segment. III. Corporate and Other Segment The Corporate and Other 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. Since 2020, the Corporate and Other segment also includes the investment in EMG International, LLC ("EMG"), a wastewater treatment processing company. 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. 23, 2022. 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, 2021
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Material Accounting Policies	Material Accounting Policies The Company has reviewed the accounting policies disclosed in accordance with the amendments to IAS 1 to disclose the material accounting policy information rather than significant 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. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the good or services is 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 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, 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 (i.e., 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 (i.e., 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 (i.e., 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 Canadian and US coal operations, and the sale of coal to third parties. Obligations 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) are comprised of 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 ("PPA"). Contracts for differences is a financial contract whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh. A virtual PPA is where 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 (“FVOCI”). 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 FVOCI 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. 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 earnings ("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 earnings ("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 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 are comprised of cash and highly liquid investments with original maturities of three months or less. D. Inventory I. Fuel The Company’s inventory balance is comprised 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 internally produced coal inventory is determined using absorption costing, which is defined as the sum of all applicable expenditures and charges directly incurred in bringing inventory to its existing condition and location. Available coal inventory tends to increase during the second and third quarters as a result of favourable weather conditions and lower electricity production as maintenance is performed. Due to the limited number of processing steps incurred in mining coal and preparing it for consumption and its relatively low value on a per-unit basis, management does not distinguish between work in process and coal available for consumption. 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, 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 assets 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. Capital 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. Other 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 2-51 years Wind generation 2-30 years Gas generation 2-36 years Energy Transition 2-16 years Capital spares and other 2-51 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 and fuel and purchased power in the Consolidated Statements of Earnings (Loss). Amortization commences when th e intangible asset is available for use and is computed on a straight-line basis over the intangible asset’s estimated useful life. Est imated 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 2-7 years Power sale contracts 1-19 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 inc

Accounting Changes

Accounting Changes	12 Months Ended
	Dec. 31, 2021
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Accounting Changes	Accounting Changes A. Current Accounting Changes I. Amendments to IAS 1 Presentation of Financial Statements: Material Accounting Policies Effective for the 2021 annual financial statements, the Company early adopted amendments to IAS 1 Presentation of Financial Statements in advance of its mandatory effective date of Jan. 1, 2023, which requires entities to disclose their material accounting policy information rather than their significant accounting policies. The Company has updated the accounting policies disclosed in Note 2 based on its assessment of the amended standard. II. Amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use Effective Jan. 1, 2021, the Company early adopted amendments to IAS 16 Property, plant and equipment (“IAS 16 Amendments”) in advance of its mandatory effective date of Jan. 1, 2022. The Company adopted the IAS 16 Amendments retroactively. No cumulative effect of initially applying the guidance arose. The IAS 16 Amendments prohibit deducting from the cost of an item of property, plant and equipment any proceeds from selling items produced while bringing that asset to the location and condition necessary for it to be capable of operating in a manner intended by management. Instead, an entity recognizes the proceeds from selling such items, and the cost of producing those items, in profit or loss. No adjustments resulted from early adopting the amendments. III. IFRS 7 Financial Instruments: Disclosures — Interest Rate Benchmark Reform The transition of the London Interbank Offered Rates ("LIBOR") has begun with the cessation of the publication of one-week and two-month USD LIBOR occurring on Dec. 31, 2021. The remaining overnight, one-, three-, six-, and 12-month USD LIBOR will continue to be published until their cessation date on June 30, 2023. Existing financial instruments may continue to use USD LIBOR while they are published until they mature, however, new financial instruments will not be using USD LIBOR if entered into after Dec. 31, 2021. The IASB issued Interest Rate Benchmark Reform — Phase 2 in August 2020, which amends IFRS 9 Financial Instruments , IAS 39 Financial instruments: Recognition and Measurement , IFRS 7 Financial Instruments: Disclosures and IFRS 16 Leases . The amendments were effective Jan. 1, 2021, and were adopted by the Company on Jan. 1, 2021. There was no financial impact upon adoption. The Company's credit facilities references USD LIBOR for US-dollar drawings and the Canadian Dollar Offered Rate for Canadian drawings, and includes appropriate fallback language to replace these benchmark rates if a benchmark transition event were to occur. For the year ended Dec. 31, 2021, there were no drawings under the credit facilities. The Company has interest rate swap agreements in place with a notional amount of US$150 million referencing three-month LIBOR, expected to settle in the third quarter of 2022. B. Future Accounting Changes I. Amendments to 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 will be adopted by the Company in 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 financial impact is expected upon adoption. II. 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. III. Amendments to IAS 1 Classification of Liabilities as Current or Non‐Current In January 2020, 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, provide 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, 2023, and are to be applied retrospectively. The Company has not yet determined the impact of these amendments 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 and Dives

Business Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2021
Business Combinations [Abstract]
Business Acquisitions and Divestitures	Business Acquisitions and Divestitures 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 (A) Ada facility (B) Assets Cash and cash equivalents 4 1 Accounts receivable 4 3 Property, plant and equipment 146 1 Intangible assets (1) — 37 Right of use assets 13 — Inventory — 1 Prepaid expenses — 1 Liabilities Accounts payable and accrued liabilities (4) — Lease liabilities (13) — Tax equity liability (20) — Deferred taxes (3) — Risk management liabilities (current and long-term) — (5) Decommissioning provisions (4) (1) Net assets acquired 123 38 Cash consideration 120 32 Working capital consideration 3 6 Total purchase consideration transferred 123 38 1) This relates to the power sales contract acquired and is being amortized over six years. A. 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. The acquisition was funded using existing liquidity. The North Carolina Solar facility consists of 20 solar photovoltaic sites across North Carolina. The sites were commissioned between November 2019 and May 2021 and are all operational. The facility is secured by long-term PPAs with Duke Energy, which have an average remaining term of 12 years. Under the PPAs, Duke Energy receives the renewable electricity, capacity and environmental attributes from each facility. Certain assets and liabilities have been measured on a provisional basis. If new facts and circumstances are obtained within one year from the date of acquisition that existed at the date of acquisition, any identified adjustments to the above amounts or additional provisions that existed at the date of acquisition, may result in a revision to the accounting for the acquisition. Had North Carolina Solar been acquired at the beginning of the year, the assets would have contributed an estimated $16 million to revenues and $9 million to net earnings before taxes. At the closing of the acquisition, TransAlta Renewables Inc. ("TransAlta Renewables"), a subsidiary of the Company, acquired a 100 per cent economic interest in North Carolina Solar from a wholly owned subsidiary of the Company through a tracking preferred share structure for aggregate consideration of approximately US$102 million. B. Acquisition of the Ada Facility On May 19, 2020, the Company closed the acquisition of a contracted natural-gas-fired cogeneration facility from two private companies for a purchase price of US$27 million. The Ada facility is a 29 MW cogeneration facility in Michigan that is contracted under a PPA and a steam sale agreement for approximately 6 years with Consumers Energy and Amway. C. Sale of Pioneer Pipeline On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. ("ATCO") for the aggregate sale price of $255 million. The net cash proceeds to TransAlta from the sale of its 50 per cent interest was approximately $128 million, subject to certain adjustments. As a result of this sale, the Company has derecognized the related Pioneer Pipeline assets that were classified as assets held for sale of $97 million and recognized a gain on sale of $31 million o n the statement of earnings. In addition, as part of the transaction, the natural gas transp ortation agreement with the Pioneer Pipeline Limited Partnership was terminated, which resulted in the derecognition of the right-of-use asset of $41 million and a lease liability of $43 million related to the pipeline, resulting in a gain

Revenue

Revenue	12 Months Ended
	Dec. 31, 2021
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 physical 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, 2021 Hydro Wind and Gas (1) Energy Transition (2) Energy Corporate and Other Total Revenues from contracts with customers Power and other (3) 28 207 395 24 — — 654 Environmental attributes — 28 — — — — 28 Revenue from contracts with customers 28 235 395 24 — — 682 Revenue from leases (4) — — 19 — — — 19 Revenue from derivatives and other — (25) (118) 138 211 4 210 Merchant revenue and other (3)(5) 355 95 813 547 — — 1,810 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) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details. (2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details. (3) The Alberta PPAs for certain facilities included in the Hydro, Gas and Energy Transition segments with the Balancing Pool expired at Dec. 31, 2020. These facilities began operating on a merchant basis in the Alberta market on Jan. 1, 2021. (4) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. (5) Includes merchant revenue, government incentives and other miscellaneous. Year ended Dec. 31, 2020 Hydro Wind and Gas (1) Energy Transition (2) Energy Corporate and Other Total Revenues from contracts with customers Power and other 141 238 465 156 — — 1,000 Environmental attributes — 23 — — — — 23 Revenue from contracts with customers 141 261 465 156 — — 1,023 Revenue from leases (3) — — 123 — — — 123 Revenue from derivatives and — (2) (8) 283 122 12 407 Merchant revenue and other (4) 11 70 207 265 — (5) 548 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) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details. (2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details. (3) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. (4) Includes merchant revenue, government incentives and other miscellaneous. Year ended Dec. 31, 2019 Hydro Wind and Gas (1) Energy Transition (2) Energy Corporate and Other Total Revenues from contracts with customers Power and other 142 221 497 185 — — 1,045 Environmental attributes — 23 — — — — 23 Revenue from contracts with customers 142 244 497 185 — — 1,068 Revenue from leases (3) — — 130 — — — 130 Revenue from derivatives and — 18 (15) 160 129 4 296 Merchant revenue and other (4) 14 50 239 560 — (10) 853 Total revenue 156 312 851 905 129 (6) 2,347 Revenues from contracts with customers Timing of revenue recognition At a point in time — 27 5 46 — — 78 Over time 142 217 492 139 — — 990 Total revenue from contracts with customers 142 244 497 185 — — 1,068 (1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details. (2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details. (3) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. (4) Includes merchant revenue, government incentives and other miscellaneous. B. Contract Liabilities The Company has recognized the following revenue-related contract liabilities: Contract liabilities 2021 2020 Balance, beginning of the year 15 15 Amounts transferred to revenue included in opening balance (1) (1) Consideration received 8 1 Increases due to amounts billed to customers — 2 Changes in transaction price 11 — Performance obligations satisfied (1) (2) Balance, end of year 32 15 Current portion 19 1 Long-term portion 13 14 The contract liabilities outstanding a t Dec. 31, 2021, and Dec. 31, 2020, primarily relate to prepayments relating to the Company's New Richmond and Bone Creek facilities where the Company still has to fulfil its performance obligations. In addition, the Company recognized a provision for liquidated damages due to the Sarnia outages that occurred in the second quarter of 2021. C. Remaining Performance Obligations The following disclosures regarding the aggregate amounts of transaction prices allocated to remaining performance obligations (contract revenues that have not yet been recognized) for contracts in place at the end of the reporting period exclude revenues related to contracts that qualify for the invoice practical expedient and contracts with an original expected duration of less than 12 months. Additionally, 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. Future revenues that are related to constrained variable consideration are not included in the disclosure of remaining performance obligations until the constraints are resolved. Contracts with customers that are accounted for as derivatives are excluded from these disclosures. Refer to Note 15 for further details. Contracts that have been executed for development projects are excluded until commercial operations have been achieved. As a result, the amounts of future revenues disclosed below represent only a portion of future revenues that are expected to be realized by the Company from its contractual portfolio. Hydro At Dec. 31, 2020, the Company's PPA with the Balancing Pool to provide the capacity of 12 hydro facilities throughout the province of Alberta concluded. Commencing Jan. 1, 2021, production has been sold into the Alberta merchant market. The Company has contracts for services at specific hydro facilities, which will conclude at the end of 2030. The Company also has a contract with the Government of Alberta to manage water for flood and drought mitigation purposes, which concludes in 2026. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2021, are approximately $46 million. Wind and Solar At Dec. 31, 2021, the Company had long-term contracts with customers to deliver electricity and the associated renewable energy credits from three wind facilities located in Alberta, Minnesota and Quebec, for which the invoice practical expedient is not applied. The PPAs generally require all available generation to be provided to customers at fixed prices, with certain pricing subject to annual escalations for inflation. The Company expects to recognize such amounts as revenue as it delivers electricity over the remaining terms of the contracts, until 2024, 2034 and 2033, respectively. The variable revenues under the contracts are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Company also has contracts to sell renewable energy certificates generated at merchant wind facilities and expects to recognize revenues as it delivers the renewable energy certificates to the purchasers over the remaining terms of the contracts, from 2022 through 2024. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2021, are approximately $9 million. Gas At Dec. 31, 2020, the Company's PPAs with the Balancing Pool for capacity and electricity from the Keephills Unit 2 and Sheerness Units 1 and 2 legacy coal facilities concluded. Future production has been sold into the merchant market. At Dec. 31, 2021, the Company has contracts with customers to deliver energy services from one of its gas facilities in Ontario. The contracts all consist of a single performance obligation requiring the Company to stand ready to deliver electricity and steam. On May 12, 2021, the Company executed an Amended and Restated Energy Supply Agreement with one of its large industrial customers at the Sarnia cogeneration facility that provides for the supply of electricity and steam. This agreement will extend the term of the original agreement from Dec. 31, 2022 to Dec. 31, 2032. However, if TransAlta is unable to enter into a new contract with the Ontario Independent Electricity System Operator or enter into agreements with its other industrial customers at the Sarnia cogeneration facility that extend past Dec. 31, 2025, then the Company has the option to provide notice of termination in 2022 that would terminate the Amended and Restated Energy Supply Agreement four years following such notice. The Company currently expects to recognize revenue as it delivers electricity and steam to the other industrial customers at the Sarnia cogeneration facility until the completion of the contracts in late 2025, or 2032, if the contract is extended. At the same gas facility, the Company has a contract with the local power authority with fixed capacity charges that are adjusted for seasonal fluctuations, steam demand from the plant’s other customers and for deemed net revenue related to production of electricity into the market. As a result, revenues recognized in the future will vary as they are dependent upon factors outside of the Company’s control and are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Company expects to recognize such revenue as it stands ready to deliver electricity until the completion of the contract term on Dec. 31, 2025. At Dec. 31, 2021, the Company had contracts with customers to deliver steam, hot water and chilled water from one of its other gas facilities in Ontario, extending through 2023 and 2033. Prices under these contracts include fixed annual fees, variable thermal energy charges based on gas prices, and fixed base amounts per gigajoule, subject to escalation annually for both gas prices and inflation. One contract includes minimum annual take-or-pay volumes. Estimated future revenues related to the remaining performance obligations for this contract as of Dec. 31, 2021, are approximately $31 million. The Company has a contract with its customer for provision of steam and electricity output at its Alberta cogeneration facility extending through to Dec. 31, 2029. The contract is considered an operating lease resulting in some revenues being classified for accounting purposes as variable lease revenues. Other revenue streams are based on cost-recovery mechanisms and are variable in nature and considered to be fully constrained and are these revenues are excluded from these disclosures. The Company has a contract, commencing in late 2023, for the sale of capacity and electricity, exercisable at the option of the customer in Canada, under which the Company will receive a fixed capacity payment and variable energy payments based on production. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2021, are approximately $336 million, of which the Company expects to recognize on average, between $5 million to $10 million in 2023 and $40 million to $45 million annually thereafter for the duration of the contracts. At Dec. 31, 2021, the Company has PPAs with customers to deliver electricity from its gas facilities located in Australia. The PPAs generally call for all available generation to be provided to customers. Pricing terms include fixed and variable price components for delivered electricity and fixed capacity payments. The variable revenues under the contracts are considered to be fully constrained and are excluded from these disclosures. Another one of the Company's PPA to deliver electricity from its gas facilities is considered a finance lease resulting in some revenues being classified for accounting purposes as finance lease income and are excluded from these disclosures. The Company also earns revenues from providing operation and maintenance services for the facility for a fixed monthly fee. Estimated future revenues related to the remaining performance obligations for these contracts as at Dec. 31, 2021, are approximately $2.5 billion, of which the Company expects to recognize approximately $285 million in total over the next two fiscal years and on average, between approximately $85 million to $145 million annually thereafter for the duration of the remaining contract. Energy Transition

Expenses by Nature

Expenses by Nature	12 Months Ended
	Dec. 31, 2021
Analysis of income and expense [abstract]
Expenses by Nature	Expenses by Nature Fuel and purchased power and operations, maintenance and administrative ("OM&A") expenses classified by nature are as follows: Year ended Dec. 31 2021 2020 2019 Fuel and OM&A Fuel and OM&A Fuel and OM&A Gas fuel costs (1) 306 — 159 — 133 — Coal fuel costs (1)(2) 164 — 269 — 310 — Royalty, land lease, other direct costs 19 — 20 — 21 — Purchased power 339 — 163 — 246 — Mine depreciation (3) 190 — 144 — 119 — Salaries and benefits 36 234 50 235 52 228 Other operating expenses (4) — 277 — 237 — 247 Total 1,054 511 805 472 881 475 (1) During 2021, fuel costs have been split to show natural gas and coal fuel costs separately within the above table and carbon compliance costs have been reclassified from fuel and purchased power to a separate line called carbon compliance costs on the Consolidated Statements of Earnings (Loss). Prior periods have been adjusted to reflect these reclassifications. (2) Included in coal fuel costs for 2021 was $17 million related to the impairment of coal inventory recorded during 2021 (2020 — $15 million). Refer to Note 17 for further details. (3) Included in mine depreciation for 2021 was $48 million related to the mine depreciation that was initially recorded in the standard cost of coal inventory and then subsequently impaired during 2021 (2020 — $22 million) . Refer to Note 17 for further details.

Asset Impairment

Asset Impairment	12 Months Ended
	Dec. 31, 2021
Disclosure of impairment of assets [Abstract]
Asset Impairment	Asset Impairment 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 for each CGU by calculating an approximate fair value less costs of disposal using discounted cash flow projections based on the Company’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to the Company’s long-range forecast, including changes to fuel costs, operating costs, capital expenditures, external power prices and useful lives of the assets extending to the last planned asset retirement in 2072. 2021 2020 2019 PP&E Impairments: Energy Transition facilities and projects (reversals) 345 79 (151) Energy Transition - Centralia mine decommissioning and restoration provision — 3 141 Changes in decommissioning and restoration provisions for retired assets (1) 32 — 2 Highvale mine 195 — — Kaybob Cogeneration Project 27 — — Wind 12 — — Hydro 5 2 — Gas 5 — — Intangible asset impairment - coal rights (2) 17 — — Assets held for sale (3) — — 15 Project development costs (4) 10 — 18 Asset impairment 648 84 25 (1) Changes related to changes in discount rates on retired assets. (2) Impaired to nil as no future coal will be extracted from this area of the mine. (3) 2019 amounts relate to trucks and associated inventory to be sold within the Energy Transition segment and accordingly, these items were impaired to net realizable value. (4) During 2021, the Company recorded an impairment 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. During 2020, the Company wrote off nil (2019 — $18 million) in project development costs related to projects that are no longer proceeding within the Corporate segment. A. Energy Transition Asset Impairments 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), 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 equipment for 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, of which $25 million was related to assets held for sale. 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 2020, the Company recognized an impairment 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. In 2019, an internal valuation indicated the fair value less costs of disposal of the Centralia thermal facility CGU exceeded the carrying value, resulting in a recoverability test in 2019. The updated fair value included sustained changes in the market power price and cost of coal due to contract renegotiation. As a result of the recoverability test, an impairment reversal of $151 million was recorded in the Centralia segment. B. Highvale Mine 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. C. Kaybob Cogeneration Project On Oct. 1, 2019, TransAlta and Energy Transfer Canada ("ET Canada" formerly known as SemCAMS Midstream ULC) entered into definitive agreements to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant. The facility was expected to receive its final regulatory approvals in the second half of 2020 and begin construction in December 2020. On Sept. 25, 2020, the Alberta Utilities Commission ("AUC") released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. TransAlta will not be proceeding with the Kaybob cogeneration facility as a result of ET Canada's purported termination of the agreements to develop, construct and operate the 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant. As a result, the Company recorded an impairment 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. TransAlta has commenced an arbitration seeking compensation for ET Canada's wrongful termination of the agreements. Refer to Note 36 for further details. D. Wind Facilities During the third quarter of 2021, the Company recorded an impairment of $10 million for a wind asset as result of an increase in estimated decommissioning costs after the review of a recent engineering study on the decommissioning costs of the wind sites. Refer to Note 23 for more details for changes in decommissioning and restoration provisions. The resulting fair value measurement less cost of disposal is categorized as a Level III fair value measurement and the Company has adjusted the expected value down to $65 million using discount rates of 5.0 per cent (Dec. 31, 2020 — 5.3 per cent). The key assumptions impacting the determination of fair value are electricity production, sales prices and cost inputs, which are subject to measurement uncertainty. During 2021, the Company recognized an impairment 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. Refer to Note 24 for further details. E. Impairment on Decommissioning and Restoration Provision on Retired Assets

Finance Lease Receivables

Finance Lease Receivables	12 Months Ended
	Dec. 31, 2021
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 2021 2020 Minimum Present value of Minimum Present value of Within one year 58 54 63 56 Second to fifth years inclusive 127 105 169 126 More than five years 80 66 100 82 265 225 332 264 Less: unearned finance lease income 40 — 68 — Total finance lease receivables 225 225 264 264 Included in the Consolidated Statements of Financial Position as: Current portion of finance lease receivables (Note 14) 40 36 Long-term portion of finance lease receivables 185 228 Total finance lease receivables 225 264

Net Other Operating Expense (In

Net Other Operating Expense (Income)	12 Months Ended
	Dec. 31, 2021
Analysis of income and expense [abstract]
Net Other Operating Expense (Income)	Net Other Operating Expense (Income) Net other operating income includes the following: Year ended Dec. 31 2021 2020 2019 Alberta Off-Coal Agreement (40) (40) (40) Supplier settlements 34 — — Onerous contract provisions 14 29 — Insurance recoveries and other (1) — — (9) Net other operating expense (income) 8 (11) (49) (1) There were no insurance recoveries in 2021 or 2020. In 2019, the Company received $10 million in insurance recoveries related to insurance proceeds for tower fires at Wyoming and Summerview. 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. In July 2018, the Company obtained financing against the OCA payments. Refer to Note 24 for further details. B. Supplier Settlements During 2021, $34 million was expensed relating 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. C. 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, 2021
Interests In Other Entities [Abstract]
Investments	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. The change in investments is as follows: Skookumchuck EMG Total Balance, Dec. 31, 2019 — — — Contributions 86 16 102 Equity income 1 — 1 Change in foreign exchange rates (2) (1) (3) Balance, Dec. 31, 2020 85 15 100 Equity income 12 (3) 9 Distributions received (4) — (4) Balance, Dec. 31, 2021 93 12 105 A. Skookumchuck Wind Project On Nov. 25, 2020, TransAlta completed the purchase of a 49 per cent interest in SP Skookumchuck Investments, LLC from Southern Power for cash consideration of $86 million (US$66 million). Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state consisting of 38 Vestas V136 wind turbines. The project has a 20-year PPA with Puget Sound Energy. B. EMG International Acquisition On Nov. 30, 2020, TransAlta acquired a 30 per cent equity interest in EMG. Included in the purchase price of US$12 million is an estimated component contingent on EMG realizing certain earnings metrics in 2020 and 2021, following the acquisition. The final contingent amount will be calculated based on actual earnings metrics achieved. EMG is an established company with over 25 years of experience in process wastewater treatment and specializes in the design and construction of high-rate anaerobic digester systems. The investment provides an opportunity for TransAlta to leverage its expertise in on-site generation to support further advancements by EMG in the waste-to-energy space and will advance the Company's Clean Electricity Growth plan in the US market . 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 2021 2020 Results of operations Revenues 19 3 Expenses (10) (2) Proportionate share of net earnings 9 1 Joint arrangements at Dec. 31, 2021, 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 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, 2021
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 2021 2020 2019 Interest on debt 163 158 161 Interest on exchangeable debentures (Note 25) 29 29 20 Interest on exchangeable preferred shares (Note 25) 28 5 — Interest income (11) (10) (13) Capitalized interest (Note 18) (14) (8) (6) Interest on lease liabilities 7 8 4 Credit facility fees, bank charges and other interest 18 18 15 Tax shield on tax equity financing (Note 24) (1) (9) 1 (35) Interest on line loss rule proceeding (Note 36(H)(I)) — 5 — Other (2) 2 2 10 Accretion of provisions (Note 23) 32 30 23 Net interest expense 245 238 179 (1) Credit in 2021 primarily relates to the tax benefit associated with investment tax credits claimed in 2021 on the North Carolina Solar projects that was assigned to the tax equity investor. Credit in 2019 primarily relates to the tax benefit associated with bonus tax depreciation claimed in 2019 on the Big Level and Antrim projects 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. (2) In 2021, other interest expense included approximately nil (2020 — nil , 2019 — $5 million) for the significant financing component required under IFRS 15.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Taxes [Abstract]
Income Taxes	Income Taxes A. Consolidated Statements of Earnings I. Rate Reconciliations Year ended Dec. 31 2021 2020 2019 Earnings (loss) before income taxes (380) (303) 193 Net earnings (loss) attributable to non-controlling interests not subject to tax (33) 2 (26) Adjusted earnings (loss) before income taxes (413) (301) 167 Statutory Canadian federal and provincial income tax rate (%) 23.6 % 24.5 % 26.5 % Expected income tax expense (recovery) (98) (74) 44 Increase (decrease) in income taxes resulting from: Differences in effective foreign tax rates 4 3 5 Deferred income tax expense related to temporary difference on investment in — 9 — Write-down (reversal of write-down) of unrecognized deferred income tax assets 134 8 (9) Statutory and other rate differences 4 (7) (31) Other 1 11 8 Income tax expense (recovery) 45 (50) 17 Effective tax rate (%) (11 %) 17 % 10 % II. Components of Income Tax Expense The components of income tax expense are as follows: Year ended Dec. 31 2021 2020 2019 Current income tax expense 56 35 35 Deferred income tax expense (recovery) related to the origination and reversal of temporary differences (145) (95) 22 Deferred income tax expense related to temporary difference on investment in subsidiary — 9 — Deferred income tax recovery resulting from changes in tax rates or laws — (7) (31) Deferred income tax expense (recovery) arising from the unrecognized deferred income tax assets (1) 134 8 (9) Income tax expense (recovery) 45 (50) 17 Year ended Dec. 31 2021 2020 2019 Current income tax expense 56 35 35 Deferred income tax recovery (11) (85) (18) Income tax expense (recovery) 45 (50) 17 (1) During the year ended Dec. 31, 2021, the Company recorded a write-down of deferred tax assets of $134 million (2020 —$8 million write-down, 2019 — $9 million write-down reversal). In the current year additional deferred tax assets were created from the recognition of other comprehensive losses in the US. The deferred income tax assets mainly relate to the tax benefits of losses associated with the Company’s directly owned US operations and Canadian operations. The Company evaluates at each period end, whether it is probable that sufficient future taxable income would be available from the Company’s directly owned US operations to utilize the underlying tax losses. 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 2021 2020 2019 Income tax expense (recovery) related to: Net impact related to cash flow hedges (57) (23) 6 Net actuarial gains (losses) 11 (3) (7) Income tax recovery reported in equity (46) (26) (1) C. Consolidated Statements of Financial Position Significant components of the Company’s deferred income tax assets (liabilities) are as follows: As at Dec. 31 2021 2020 Net operating loss carryforwards (1) 530 469 Future decommissioning and restoration costs 183 140 Property, plant and equipment (651) (717) Risk management assets and liabilities, net (53) (107) Employee future benefits and compensation plans 53 62 Interest deductible in future periods 17 22 Foreign exchange differences on US-denominated debt 16 31 Other deductible temporary differences (5) 2 Net deferred income tax liability, before write-down of deferred income tax assets 90 (98) Unrecognized deferred income tax assets (380) (247) Net deferred income tax liability, after write-down of deferred income tax assets (290) (345) (1) Net operating losses expire between 2031 and 2040. The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows: As at Dec. 31 2021 2020 Deferred income tax assets (1) 64 51 Deferred income tax liabilities (354) (396) Net deferred income tax liability (290) (345) (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, 2021, the Company had recognized a net liability of nil (2020 — nil) related to uncertain tax positions. Ongoing CRA Audit The Company is subject to routine audits of its tax filing positions by the Canada Revenue Agency ("CRA") on an ongoing basis. The CRA is currently examining the Company's tax filings for the 2015 taxation year and, in connection with such audit, is reviewing the internal reorganization completed in 2015. To date, the CRA has not proposed any reassessment of the Company's tax liability as a consequence of such audit and management believes that any reassessment would be without merit. The Company strongly believes that the Company's tax filing positions are appropriate, and accordingly no amounts have been accrued in the consolidated financial statements in respect of any such potential reassessment. If a notice of reassessment were issued, the Company would expect to vigorously oppose any such reassessment. If the CRA were to issue such a reassessment, the Company would be required to pay, on a provisional basis, up to 50 per cent of the amounts assessed, estimated to be between nil and $57 million. Any payment made by the Company in this context would be held by CRA until the final resolution of the dispute. The Company firmly believes it will be able to successfully defend its original filing position so that, ultimately, no increased income tax payable will result from the CRA's audit and any amounts paid to the CRA by the Company would be refunded.

Non-Controlling Interests

Non-Controlling Interests	12 Months Ended
	Dec. 31, 2021
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, 2021 TransAlta Cogeneration L.P. 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, L.P. (“TA Cogen”) operates a portfolio of cogeneration facilities in Canada and owns 50 per cent of a dual-fuel generating facility. TransAlta Renewables 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. 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 the 167 MW Kent Hills wind facility located in New Brunswick. Year ended Dec. 31 2021 2020 2019 Revenues 470 436 446 Net earnings 139 97 183 Total comprehensive earnings 66 223 138 Amounts attributable to the non-controlling interests: Net earnings 50 40 73 Total comprehensive earnings 21 90 56 Distributions paid to non-controlling interests 100 80 69 As at Dec. 31 2021 2020 Current assets 430 743 Long-term assets 3,319 2,913 Current liabilities (593) (364) Long-term liabilities (1,033) (987) Total equity (2,123) (2,305) Equity attributable to non-controlling interests (869) (948) Non-controlling interests’ share (per cent) 39.9 39.9 In 2020, the Company's ownership per cent decreased from 60.4 per cent in 2019 to 60.1 per cent due to TransAlta Renewables issuing approximately 1 million common shares under their Dividend Reinvestment Plan ("DRIP"). The Company did not participate in this plan. In the fourth quarter of 2020, TransAlta Renewables suspended the DRIP in respect of any future declared dividends. B. TA Cogen Year ended Dec. 31 2021 2020 2019 Results of operations Revenues 265 146 181 Net earnings (loss) 103 (13) 43 Total comprehensive earnings (loss) 103 (13) 43 Amounts attributable to the non-controlling interest: Net earnings (loss) 62 (6) 21 Total comprehensive earnings (loss) 62 (6) 21 Distributions paid to Canadian Power Holdings Inc. 56 17 37 As at Dec. 31 2021 2020 Current assets 66 69 Long-term assets 312 323 Current liabilities (52) (78) Long-term liabilities (36) (37) Total equity (290) (277) Equity attributable to Canadian Power Holdings Inc. (142) (136) Non-controlling interest share (per cent) 49.99 49.99 In 2020, the Balancing Pool PPA concluded and the Sheerness facility became a merchant facility in 2021. This resulted in new protocols under the amended contractual agreement whereby the revenue and cost of sales for the facility are allocated based on dispatch activities. Capital and operating expenses continue to be allocated based on ownership interest.

Trade and Other Receivables

Trade and Other Receivables	12 Months Ended
	Dec. 31, 2021
Subclassifications of assets, liabilities and equities [abstract]
Trade and Other Receivables	Trade and Other Receivables As at Dec. 31 2021 2020 Trade accounts receivable 499 488 Collateral paid (Note 16) 55 49 Current portion of finance lease receivables (Note 8) 40 36 Loan receivable (Note 22) 55 — Income taxes receivable 2 10 Trade and other receivables 651 583

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2021
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, 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 receivable — — 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 (Note 25) — — 735 735 (1) Includes cash equivalents of nil. (2) Includes current portion. Carrying value as at Dec. 31, 2020 Derivatives Derivatives Amortized cost Total Financial assets Cash and cash equivalents (1) — — 703 703 Restricted cash — — 71 71 Trade and other receivables — — 583 583 Long-term portion of finance lease receivables — — 228 228 Risk management assets Current 102 69 — 171 Long-term 471 50 — 521 Other assets (Note 22) — — 52 52 Financial liabilities Accounts payable and accrued liabilities — — 599 599 Dividends payable — — 59 59 Risk management liabilities Current 10 84 — 94 Long-term — 68 — 68 Credit facilities, long-term debt and lease liabilities (2) — — 3,361 3,361 Exchangeable securities (Note 25) — — 730 730 (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 to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by reference to prices for that 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. 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 historical bootstrap 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. 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 businesses 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, 2021, are as follows: Level I — $12 million net asset (Dec. 31, 2020 — $13 million net liability), Level II — $122 million net asset (Dec. 31, 2020 — $27 million net liability) and Level III — $159 million net asset (Dec. 31, 2020 — $582 million net asset). Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2021, are primarily attributable to volatility in market prices on both existing contracts and new contracts as well as contract settlements. The following tables summarize 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, 2021 and 2020, respectively: Year ended Dec. 31, 2021 Year ended Dec. 31, 2020 Hedge Non-hedge Total Hedge Non-hedge Total Opening balance 573 9 582 678 8 686 Changes attributable to: Market price changes on existing contracts (181) 4 (177) (18) 3 (15) Market price changes on new contracts — (134) (134) — 7 7 Contracts settled (107) (5) (112) (71) (10) (81) Change in foreign exchange rates — — — (16) 1 (15) Net risk management assets (liabilities) at end of period 285 (126) 159 573 9 582 Additional Level III information: Losses recognized in other comprehensive earnings (181) — (181) (34) — (34) Total gains (losses) included in earnings before income 107 (130) (23) 71 11 82 Unrealized gains (losses) included in earnings before — (135) (135) — 1 1 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, 2021, the total Level III risk management asset balance was $305 million (2020 — $615 million) and Level III risk management liability balance was $146 million (2020 — $33 million). 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. 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. During 2021, the sensitivities include the effects of liquidity and credit value adjustments. As at Dec. 31, 2021 Description Sensitivity Valuation technique Unobservable input Reasonable possible change Long-term power sale – US +22 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$3 or price increase of US$20 -145 Coal +3 Numerical derivative valuation Illiquid future power prices (per MWh) Price decrease of US$3 or price increase of US$20 Volatility 80% to 120% -18 Rail rate escalation zero to 4% Full requirements +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 of 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 As at Dec. 31, 2020 Description Sensitivity Valuation technique Unobservable input Reasonable possible change Long-term power +35 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$3 or a price increase of US$5 -59 Coal +3 Numerical derivative valuation Illiquid future power prices (per MWh) Price decrease of US$3 or a price increase of US$5 Volatility 80% to 120% -5 Rail rate escalation zero to 4% Full +3 Historical bootstrap Volume 95% to 105% -3 Cost of supply (+/-) US$1 per MWh Long-term wind +22 Long-term price forecast Illiquid future power prices (per MWh) Price increase or decrease of US$6 -22 Illiquid future REC prices (per unit) Price increase or decrease of US$1 Others +5 -5 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 2023, 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 remained consistent from Dec. 31, 2020, to Dec. 31, 2021, resulting in the sensitivity values remaining consistent. The balance for this contract at Dec. 31, 2021 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, with a contract start date of Jan. 1, 2021, that extends until Dec. 31, 2025. Option pricing techniques have been utilized to value the obligation associated with this component of the deal. The key unobservable inputs used in the valuation include non-liquid power prices, option volatility and rail rate escalation. Reasonably possible alternative inputs were used to determine sensitivity on the fair value measurements. For periods beyond 2023, 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. Reasonable possible alternative inputs are used to determine sensitivity on the fair value measurement. iv. Long-Term Wind Energy Sale – Eastern US In relation to the Big Level wind facility, the Company has a long-term contract for differences whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh as well as the physical delivery of renewable energy credits based on proxy generation. Commercial operation of the facility was achieved in December 2019, with the contract commencing on July 1, 2019, and extending for 15 years after the commercial operation date. The contract is accounted for at fair value through profit or loss. The key unobservable inputs used in the valuation of the contract are expected proxy generation volumes and non-liquid forward prices for power and RECs. v. Long-Term Wind Energy Sale – Canada In relation to the Garden Plain wind project, the Company has entered into a virtual PPA whereby the Company receives the difference between the fixed contract price per MWh and the Alberta Electric System Operator ("AESO") settled pool price per MWh. The contract commences on commercial operation of the facility, which is expected by the end of 2022, and extending for 18 years pa st that date. The energy component of the contract is accounted for at fair value through profit or loss. In addition to the virtual PPA contract, the Company has entered into a "bridge contract" that runs 16 months from Sept. 1, 2021 through Dec. 31, 2022, with the potential for extension at the virtual PPA price, depending on the commencement of commercial operations. Under a separate agreement, Pembina has the option to purchase a 37.7 per cent interest in the project (49 per cent of the PPA). The option must be exercised no later than 30 days after commercial operational date. The key unobservable inputs used in the valuation of the contracts are the non-liquid forward prices for power and monthly wind discounts. vi. Long-Term Wind Energy Sale – Central US On Dec. 22, 2021, TransAlta executed two long-term virtual PPAs for the off take of 100 per cent of the generation from its 300 M W White Rock East and White Rock West wind power projects ( collectively, the "White Rock Wind Projects") to be located in Caddo County, Oklahoma. The Company receives the difference between the fixed contract price per MWh and the settled pool price per MWh. The contracts commence on commercial operation of the facilities, which is expected within the second half of 2023, and extend for 15 years past that date. The energy component of the contracts is accounted for at fair value through profit or loss. The key unobservable inputs used in the valuation of the contracts are the non-liquid forward prices for power and monthly 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 asset fair value of $8 million as at Dec. 31, 2021 (Dec. 31, 2020 – $12 million net liability) are classified as Level II fair value measurements. The significant changes in other net risk management assets and liabilities during the year ended Dec. 31, 2021, are primarily attributable to favourable market prices on existing contracts. 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, 2021 — 770 — 770 735 Long-term debt — Dec. 31, 2021 — 3,272 — 3,272 3,167 Exchangeable securities — Dec. 31, 2020 — 769 — 769 730 Long-term debt — Dec. 31, 2020 — 3,480 — 3,480 3,227 (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 paid, accounts payable and accrued liabilities, collateral received and dividends payable) approximates fair value due to the liquid nature of the asset or liability. The fair values of the loan receivable (see Note 22) and the finance lease receivables (see Note 8) approximate the carrying amounts. 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 15 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, and a reconciliation of changes is as follows: As at Dec. 31 2021 2020 2019 Unamortized net gain (loss) at beginning of year (33) 9 49 New inception gain (loss) (1) (50) (13) 3 Amortization recorded in net earnings during the year (19) (29) (43) Unamortized net gain (loss) at end of year (2) (102) (33) 9 (1) During 2021, the Company entered into PPAs for the White Rock Wind Projects 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 power agreement contract period. 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. (2) During 2020, the net inception gain on the long-term fixed price power sale contract in the US changed to a loss position based on the day one forward price curve at inception of the contract.

Risk Management Activities

Risk Management Activities	12 Months Ended
	Dec. 31, 2021
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, 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 As at Dec. 31, 2020 Cash flow Not Total Commodity risk management Current 101 (11) 90 Long-term 471 (19) 452 Net commodity risk management assets (liabilities) 572 (30) 542 Other Current (9) (4) (13) Long-term — 1 1 Net other risk management liabilities (9) (3) (12) Total net risk management assets (liabilities) 563 (33) 530 I. 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 2021 2020 Current Long-term Current Long-term Current Long-term Current Long-term Gross amounts recognized 394 330 (306) (122) 120 69 (132) (104) Gross amounts set-off (137) (53) 138 54 (69) (10) 69 10 Net amounts as included in the 257 277 (168) (68) 51 59 (63) (94) 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 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 pre-defined 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 and for its portfolio of merchant power exposure in Alberta, including a long-term physical power sale contract at Centralia and fixed price financial swaps for the Alberta portfolio to hedge the prices. Both hedging strategies fall under the Company’s risk management strategy used to hedge commodity price risk. There is no source of hedge ineffectiveness for the merchant power exposure in Alberta. 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. 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, 2021, associated with the Company’s proprietary trading activities was $2 million (2020 — $1 million, 2019 — $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, 2021, associated with the Company’s commodity derivative instruments used in generation hedging activities was $33 million (2020 — $12 million, 2019 — $25 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, 2021, associated with these transactions was $51 million (2020— $15 million, 2019 — $8 million). iii. Commodity Price Risk Management – Hedges The Company’s outstanding commodity derivative instruments designated as hedging instruments are as follows: As at Dec. 31 2021 2020 Type Notional Notional Notional Notional Electricity (MWh) (1) — — 95 — (1) Excludes the long-term power sale - US contract. For further details on this contract, refer to Note 15(B)(I)(c)(i). During 2021, unrealized pre-tax losses of $1 million (2020 — $1 million gains, 2019 — $1 million gains) related to certain power hedging relationships that were previously de-designated and deemed ineffective for accounting purposes were released from AOCI and recognized in net earnings. iv. Commodity Price Risk Management – Non-Hedges The Company’s outstanding commodity derivative instruments not designated as hedging instruments are as follows: As at Dec. 31 2021 2020 Type Notional Notional Notional Notional Electricity (MWh) 46,139 14,951 12,944 8,258 Natural gas (GJ) 7,501 173,898 23,035 177,448 Transmission (MWh) 37 1,097 — 1,578 Emissions (MWh) 445 2,030 1,831 2,112 Emissions (tonnes) 350 350 2,160 2,365 Coal (tonnes) — 9,352 — 9,078 b. Interest Rate Risk Management Interest rate risk arises as the fair value of future cash flows from a financial instrument fluctuates because of changes in market interest rates. Changes in interest rates can impact the Company’s borrowing costs. Changes in the cost of capital may also affect the feasibility of new growth initiatives. The Company's credit facility and the Poplar Creek non-recourse bond are the only debt instruments subject to floating interest rates, which represent 3 per cent of the Company’s debt as at Dec. 31, 2021 (2020 – 7 per cent). Interest rate risk is managed with the use of derivatives. The Company's outstanding interest rate derivative instruments are as follows: In 2021, the Company had interest rate swap agreements in place with a notional amount of US$150 million (2020 —US$150 million) whereby the Company receives a variable rate of interest equal to the three-month LIBOR rate and pays interest at a fixed rate equal to 0.94 per cent (2020 — 0.94 per cent) on the notional amount. The swaps are being used to hedge interest rate exposure on a highly probable future US$400 million fixed rate debt issuance, expected to occur in 2022. In 2021, the Company had bond lock agreements in place with a total notional amount of US$150 million (2020 — $75 million) whereby on the pricing date, if the difference between the underlying 1.375 per cent US Treasury bond (2020 — 5.75 per cent Government of Canada bond) and the forward bond yield (2020 — $150 million forward yield 1.20 per cent) is positive, the Company receives settlement. If the difference is negative, the Company pays settlement. The bond lock is being used to hedge interest rate exposure on a highly probable future US$400 million (2020 —$150 million) fixed rate debt issuance. The $75 million bond lock outstanding at Dec. 31, 2020, was settled in 2021. There were no interest rate derivative instruments outstanding in 2019. LIBOR 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 facility references LIBOR for US dollar drawings and Canadian Dollar Offer Rate ("CDOR") for Canadian dollar drawings, and includes appropriate fallback language to replace these benchmark rates if a benchmark transition event were to occur. Currently there are no drawings on the facility. The non-recourse bond references the three-month CDOR: however, only the six- and 12-month CDOR have been discontinued with no expectation to stop publishing other CDOR rates at this time. In addition, the Company has interest rate swap agreements in place with a notional amount of US$150 million referencing the three-month LIBOR, expected to settle in the third quarter of 2022. The cessation date for three-month LIBOR is June 30, 2023. 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 (2020 — US$370 million). ii. Cash Flow Hedges The Company uses foreign exchange forward contracts to hedge a portion of its future foreign-denominated receipts and expenditures, and both foreign exchange forward contracts and cross-currency swaps to manage foreign exchange exposure on foreign-denominated debt not designated as a net investment hedge. As at Dec. 31 2021 2020 Notional Notional Fair value Maturity Notional Notional Fair value liability Maturity Foreign exchange forward contracts - foreign-denominated receipts/expenditures CAD10 USD8 — 2022 CAD71 USD54 (2) 2021 AUD19 USD14 — 2022 — — — — iii. Non-Hedges The Company also uses foreign currency contracts to manage its expected foreign operating cash flows. Hedge accounting is not applied to these foreign currency contracts. As at Dec. 31 2021 2020 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign exchange forward contracts – foreign-denominated receipts/expenditures AUD28 CAD26 (5) 2022-2025 AUD197 CAD181 (14) 2021 - 2024 USD271 CAD357 8 2022-2025 USD47 CAD72 9 2021 - 2024 AUD4 USD3 — 2021 CAD1 EUR1 — 2021 Foreign exchange forward contracts – foreign-denominated debt CAD191 USD150 1 2022 CAD191 USD150 2 2022 iv. 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 cent (2020 — three cent, 2019 — three cent) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter. Year ended Dec. 31 2021 2020 2019 Currency Net earnings increase (decrease) (1) OCI gain (1)(2) Net earnings decrease (1) OCI gain (1)(2) Net earnings decrease (1) OCI gain (1)(2) USD (13) 1 (8) 1 (18) 2 AUD 1 — (4) — (6) — Total (12) 1 (12) 1 (24) 2 (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, 2021: Investment grade (Per cent) Non-investment grade (Per cent) Total (Per cent) Total Trade and other receivables (1,2) 89 11 100 651 Long-term finance lease receivable 100 — 100 185 Risk management assets (1) 86 14 100 707 Total 1,543 (1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts. (2) Includes loan receivable with a counterparty that has no external credit ratin g. Refer to Note 22 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, 2021. The Company’s maximum exposure to credit risk at Dec. 31, 2021, 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, 2021, was $37 million (2020 — $22 million). Amidst the current economic conditions resulting from the COVID-19 pandemic, TransAlta has implemented the following additional measures to monitor its counterparties for changes in their ability to meet obligations: ▪ Daily monitoring of events impacting counterparty creditworthiness and counterparty credit downgrades; ▪ Weekly oversight and follow-up, if applicable, of accounts receivables; and ▪ Review and monitoring of key suppliers, counterparties and customers (i.e., offtakers). As needed, additional risk mitigation tactics will be taken to reduce the risk to TransAlta. These risk mitigation tactics may include, but are not limited to, immediate follow-up on overdue amounts, adjusting payment terms to ensure a portion of funds are received sooner, requiring additional collateral, reducing transaction terms and working closely with impacted counterparties on negotiated solutions. III. Liquidity Risk Liquidity risk relates to the Company’s ability to access capital to be used for proprietary trading activities, commodity hedging, capital projects, debt refinancing and general corporate purposes. As at Dec. 31, 2021, TransAlta maintains an investment grade rating from one credit rating agency and below investment grade ratings from two credit rating agencies. Between 2022 and 2024, the Company has approximately $1 billion of debt maturing, comprised of approximately $515 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments and the classification of the Kent Hills Wind LP bond as current. 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 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 is as follows: 2022 2023 2024 2025 2026 2027 and thereafter Total Accounts payable and accrued liabilities 689 — — — — — 689 Long-term debt (1) Debentures — — — — — 251 251 Senior Notes 511 — — — — 383 894 Non-recourse — Hydro — 45 — — — — 45 Non-recourse — Wind & Solar 263 49 52 54 51 283 752 Non-recourse — Gas 44 45 47 59 61 855 1,111 Tax equity financing 15 15 14 14 15 68 141 Other 3 1 — — — — 4 Exchangeable securities (2) — — — 750 — — 750 Commodity risk management (assets) (45) (35) (117) (95) 1 (2) (293) Other risk management (assets) liabilities (2) (3) (3) 1 — (1) (8) Lease liabilities (3) (6) 4 3 3 3 93 100 Interest on long-term debt and lease liabilities (4) 149 120 115 109 104 787 1,384 Interest on exchangeable securities (2, 4) 53 53 62 — — — 168 Dividends payable 62 — — — — — 62 Total 1,736 294 173 895 235 2,717 6,050 (1) Excludes impact of hedge accounting and derivatives. (2) Assumes the exchangeable securities will be exchanged on Jan. 1, 2025. Refer to Note 25 for further details. (3) Lease liabilities include a lease incentiv e of $13 million expec ted to be received in 2022. (4) Not recognized as a financial liability on the Consolidated Statements of Financial Position. IV. Equity Price Risk a. Total Return Swaps The Company has certain compensation, deferred and restricted share unit programs, the values of which depend on the common share price of the Company. The Company has fixed a portion of the settlement cost of these programs by entering into a total return swap for which hedge accounting has not been applied. The total return swap is cash settled every quarter based upon the difference between the fixed price and the market price of the Company’s common shares at the end of each quarter. D. Hedging Instruments – Uncertainty of Future Cash Flows The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount, timing and uncertainty of future cash flows: Maturity 2022 2023 2024 2025 2026 2027 and thereafter Cash flow hedges Foreign currency forward contracts Notional amount ($ millions) CAD/USD 8 — — — — — AUD/USD 14 — — — — — Average Exchange Rate CAD/USD 0.7893 — — — — — AUD/USD 0.7352 — — — — — Commodity derivative instruments Electricity Notional amount (thousands MWh) 3,329 3,329 3,338 2,628 — — Average price ($ per MWh) 71.95 73.76 75.6 77.49 — — 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, 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 13 MMWh 285 Risk management assets (181) Interest rate risk Cash flow hedges Interest rate swap USD300 3 Risk management assets 3 Foreign currency risk Cash flow hedges Foreign-denominated expenditures USD8 — Risk management assets — Foreign-denominated expenditures USD14 — Risk management assets — Net investment hedges Foreign-denominated debt USD370 CAD473 Credit facilities, long-term debt and lease liabilities — As at Dec. 31, 2020 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 16 MMWh 573 Risk management assets (33) Interest rate risk Cash flow hedges Interest rate swap USD150 (3) Risk management liabilities 3 Interest rate swap CAD75 (4) Risk management liabilities 4 Foreign currency risk Net investment hedges Foreign-denominated debt USD370 CAD472 Credit facilities, long-term debt and lease liabilities 11 The impact of the hedged items on the statement of financial position is as follows: As at Dec. 31 2021 2020 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 – (181) 226 (33) 417 Interest rate risk Cash flow hedges Interest expense on long-term 3 2 7 19 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 — (35) 11 (21) (1) Included in AOCI. The hedging 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 hedged items designated in hedging relationships on OCI and net earnings is: 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 on — Property, plant 1 Foreign exchange — Forward starting interest rate 13 Interest expense 4 Interest expense — OCI impact (255) OCI impact (8) Net earnings impact — Over the next 12 months, the Company estimates that approximately $25 million of after-tax gain 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, 2020 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 41 Revenue (137) Revenue — Foreign exchange forwards on (1) Property, plant — Foreign exchange — Forward starting interest rate (12) Interest expense (4) Interest expense — OCI impact 28 OCI impact (141) Net earnings impact — Year ended Dec. 31, 2019 Effective portion Ineffective portion Derivatives in cash flow Pre-tax Location of (gain) Pre-tax Location of (gain) loss Pre-tax Commodity contracts 77 Revenue (59) Revenue — Forward starting interest rate — Interest expense 6 Interest expense — OCI impact 77 OCI impact (53) Net earnings impact — II. Effect of Non-Hedges For the year ended Dec. 31, 2021, the Company recognized a net unrealized gain of $97 million (2020 — gain of $43 million, 2019 — gain of $33 million) related to commodity derivatives. For the year ended Dec. 31, 2021, a gain of $6 million (2020 — gain of $11 million, 2019 —gain of $24 million) related to foreign exchange and other derivatives was recognized, which consists of net unrealized gains of $4 million (2020 — loss of $2 million, 2019 — gain of $6 million) and net realized gains of $2 million (2020 — gains of $13 million, 2019 — gains of $18 million), respectively. F. Collateral I. Financial Assets Provided as Collateral At Dec. 31, 2021, the Company provided $55 million (2020 – $49 million) in cash and cash equivalents as collateral to regulated clearing agents as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents. Collateral provided is included in accounts receivable in the Consolidated Statements of Financial Position. II. Financial Assets Held as Collateral At Dec. 31, 2021, the Company held $18 million (2020 – nil) 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 included in accounts payable 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 rat

Inventory

Inventory	12 Months Ended
	Dec. 31, 2021
Disclosure of inventories [Abstract]
Inventory	Inventory The components of inventory are as follows: As at Dec. 31 2021 2020 Parts and materials 82 107 Coal 27 83 Deferred stripping costs — 8 Natural gas 3 2 Purchased emission credits (1) 55 38 Total 167 238 (1) Purchased emissions credits increased due to trading and compliance credits purchased, including those for Alberta compliance under the Technology Innovation and Emissions Reduction program. No inventory is pledged as security for liabilities. Carbon compliance costs are regulated costs that the business incurs as a result of greenhouse gas emissions generated from our operating units. TransAlta’s exposure to carbon compliance costs is mitigated through the use of eligible emission credits generated from the Company’s Wind and Solar and Hydro segments, as well as, purchasing emission credits from the market at prices lower than the regulated compliance price of carbon. Emission credits generated from our Alberta business have no recorded book value but are expected to be used to offset emission obligations from our gas facilities located in Canada in the future when the compliance price of carbon is expected to increase, resulting in a reduced cash cost for carbon compliance. At Dec. 31, 2021, the Company currently holds 2,033,752 purchased emission credits (2020 — 1,434,761) recorded at $55 million (2020 — $38 million) and approximately 1,922,973 (2020 — 1,211,230) emission credits with no recorded book value. The change in inventory is as follows: 2021 2020 Balance, Jan. 1 238 251 Net additions (use) 22 26 Write-downs, coal (65) (37) Write-downs, parts and materials (28) — Change in foreign exchange rates — (2) Balance, Dec. 31 167 238 With the decision in 2020 to adjust the useful life of the Highvale mine assets to align with the Company's conversion to gas plans, the standard cost of coal increased during 2021 and 2020 as a result of increased depreciation costs and reduced coal consumption. During the same period, as the cost of the coal was not expected to be recovered based on power pricing, the Company recognized a $65 million (2020 — $37 million) write-down to net realizable value on its internally produced coal inventory for the year ended Dec. 31, 2021, of which $48 million relates to increased depreciation from the accelerated closure of the mine.

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2021
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: Land Renewable Gas generation (1) Energy Transition (1) Assets under Capital spares and other (2) Total Cost As at Dec. 31, 2019, as previously reported 91 3,574 1,671 7,342 228 489 13,395 Adjustments due to re-segmentation — — 2,402 (2,402) — — — As at Dec 31, 2019, adjusted 91 3,574 4,073 4,940 228 489 13,395 Additions — — — — 478 8 486 Acquisitions (Note 4) — — 1 — — — 1 Disposals (2) — — (1) — (2) (5) Impairment (Note 7) (9) (2) — (69) — (1) (81) Revisions and additions to decommissioning and restoration costs (Note 23) — 8 1 85 — — 94 Retirement of assets — (7) (47) (3) — (1) (58) Change in foreign exchange rates (1) (14) 45 (39) — 6 (3) Transfers 17 33 (138) (12) (211) (120) (431) As at Dec. 31, 2020, adjusted 96 3,592 3,935 4,901 495 379 13,398 Additions — — — — 478 2 480 Acquisitions (Note 4) — 146 — — — — 146 Disposals (1) — (2) (74) (2) — (79) Impairment (Note 7) — (15) (2) (468) (91) (13) (589) Revisions and additions to decommissioning and restoration costs (Note 23) — 129 6 — — — 135 Retirement of assets — (15) (57) (49) — — (121) Change in foreign exchange rates — 3 (25) 2 — (6) (26) Transfers 1 303 232 201 (696) 4 45 As at Dec. 31, 2021 96 4,143 4,087 4,513 184 366 13,389 Accumulated depreciation As at Dec. 31, 2019, as previously reported — 1,284 900 4,836 — 168 7,188 Adjustments due to re-segmentation — — 1,137 (1,137) — — — As at Dec 31, 2019, adjusted — 1,284 2,037 3,699 — 168 7,188 Depreciation — 141 258 304 — 14 717 Retirement of assets — (5) (43) (3) — — (51) Disposals — — — (1) — (1) (2) Change in foreign exchange rates — (4) 18 (37) — 2 (21) Transfers — — (212) (29) — (14) (255) As at Dec. 31, 2020, adjusted — 1,416 2,058 3,933 — 169 7,576 Depreciation — 154 184 264 — 12 614 Retirement of assets — (9) (55) (48) — — (112) Disposals — — (1) (72) — — (73) Change in foreign exchange rates — — (8) 2 — (1) (7) Transfers — — — 71 — — 71 As at Dec. 31, 2021 — 1,561 2,178 4,150 — 180 8,069 Carrying amount As at Dec. 31, 2019, adjusted 91 2,290 2,036 1,241 228 321 6,207 As at Dec. 31, 2020, adjusted 96 2,176 1,877 968 495 210 5,822 As at Dec. 31, 2021 96 2,582 1,909 363 184 186 5,320 (1) The gas generation and energy transition includes the previously disclosed coal generation and mining property and equipment categories. (2) Includes major spare parts and stand-by equipment available, but not in service and spare parts used for routine, preventive or planned maintenance. A. Renewable Generation During 2021, the Company acquired North Carolina Solar (Refer to Note 4 for further details). During the third quarter of 2021, Kent Hills 2 had a tower collapse resulting in an impairment of $2 million. Following extensive independent engineering assessments and root cause failure analysis, the Company announced on Jan. 11, 2022, that all 50 turbine foundations at the Kent Hills 1 and Kent Hills 2 sites require a full foundation replacement. As the turbines will not be returning to service until the foundations are replaced, the foundations were written off, resulting in an increase in depreciation of $12 million. Transfers from assets under construction in 2021 are related to the Windrise wind facility of $255 million, Kent Hills wind rehabilitation project of $7 million and the balance is related to other wind and hydro facilities. Transfers between the classifications of PP&E in 2020 relate to the WindCharger project and planned major maintenance. B. Gas Generation During 2021, the Company completed the full conversion of Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 from thermal coal to natural gas. Transfers from assets under construction of $200 million relates to the planned coal to gas conversions and the balance is related to the Australian and US gas facilities. During 2019, the sale of Genesee 3 resulted in a gain of $77 million, which was recognized in gains on sale of assets and other on the statement of earnings during the fourth quarter. Transfers out of PP&E in 2020 mainly relate to removing the Southern Cross assets from PP&E to a finance lease receivable and moving the Pioneer Pipeline and mine equipment to assets held for sale. Transfers between the classifications of PP&E in 2020 relate to the Sundance Unit 6 conversion to gas. C. Energy Transition Generation Keephills Unit 1, Sundance Unit 5 and Sundance Unit 3 were retired from service effective Dec. 31, 2021, Nov. 1, 2021, and July 31, 2020, respectively. Sundance Unit 4 will be retired effective April 1, 2022. During 2021, the Company sold equipment related to coal generation that resulted in a gain of sale of $23 million. Centralia Unit 1 was retired from service effective Dec. 31, 2020, as originally planned. Transfers from assets under construction in 2021 are mainly related to Keephills Unit 1 of $20 million, Sundance Unit 5 of $78 million and the mining property and equipment related to SunHills and Centralia of $100 million. The Company transferred certain generation assets from the Energy Transition segment to assets held for sale as a result of its assessment under IFRS 5 — Non-current Assets Held for Sale and Discontinued Operations . As part of this review there were no impairment charges recognized against the carrying value of $25 million. Transfers between the classifications of PP&E in 2020 relate to the Centralia land purchase. During the third quarter of 2020, the Board approved the accelerated shutdown of the Highvale mine by the end of 2021 and accordingly the useful life of the related assets was adjusted to align with the Company's conversion to gas plans. This resulted in an increase of $15 million in depreciation expense that was recognized in the Consolidated Statements of Earnings (Loss) during the second half of 2020. D. Assets Under Construction Initial construction activities on the Garden Plain wind project started in the third quarter of 2021. In addition, the Company commenced construction in the fourth quarter of 2021 on the Northern Goldfields Solar Project. The Northern Goldfields Solar Project comprises the 27 MW Mount Keith Solar Farm, 11 MW Leinster Solar Farm, 10MW/5MWh Leinster battery energy storage system and interconnecting transmission infrastructure, all of which will be integrated into our existing 169 MW Southern Cross Energy North remote network in Western Australia. Upon completion of construction, these will be transferred to finance lease receivables. Additions in 2021 are related to the Windrise wind project of $96 million (2020 — $156 million), White Rock Wind Projects of $32 million (2020 — nil), Garden Plain wind project of $38 million (2020 — nil), the Kaybob cogeneration project of $14 million (2020 — $31 million), coal to gas conversions of $91 million (2020 — $93 million) and planned major maintenance expenditures. In 2020, the additions included the WindCharger battery storage project of $6 million and Centralia mine land of $17 million. Transfers out to assets held for sale include $25 million related to salvage values for Sundance Unit 5 repowering project.

Right of Use Asset

Right of Use Asset	12 Months Ended
	Dec. 31, 2021
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, 2019 58 16 2 25 45 146 Additions 3 13 — — — 16 Depreciation (3) (5) (1) (9) (3) (21) 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 (Note 4) — — — — (41) (41) Transfers — — — (8) — (8) As at Dec. 31, 2021 68 20 1 6 — 95 On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO. A s part of the transaction, the natural gas transp ortation agreement with th e Pioneer P ipeline 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, 2021, TransAlta paid $15 million (2020 — $33 million) related to recognized lease liabilities, consisting of $7 million in interest (2020 — $8 million) and $8 million ( 2020 — $25 million) in principal repayments. Short-term leases (term of less than 12 months) and leases with total lease payments below the Company's capitalization threshold do not require recognition as lease liabilities and right-of-use assets.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2021
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, 2019 250 378 11 149 788 Additions — — 14 — 14 Acquisition (Note 4) 37 — — — 37 Disposals — (1) — — (1) Change in foreign exchange rates (2) — — — (2) Transfers (16) 35 (22) — (3) As at Dec. 31, 2020 269 412 3 149 833 Additions — — 9 — 9 Impairment (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 Accumulated amortization As at Dec. 31, 2019 107 246 — 117 470 Amortization 15 28 — 8 51 Disposals — (1) — — (1) Transfers 1 (1) — — — As at Dec. 31, 2020 123 272 — 125 520 Amortization 17 27 — 7 51 As at Dec. 31, 2021 140 299 — 132 571 Carrying amount As at Dec. 31, 2019 143 132 11 32 318 As at Dec. 31, 2020 146 140 3 24 313 As at Dec. 31, 2021 129 123 4 — 256

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2021
Disclosure of detailed information about goodwill [Abstract]
Goodwill	Goodwill Goodwill acquired through business combinations has been allocated to CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments are as follows: As at Dec. 31 2021 2020 Hydro 258 258 Wind and Solar 175 175 Energy Marketing 30 30 Total goodwill 463 463 For the purposes of the 2021 goodwill impairment review, the Company determined the recoverable amounts of the Wind and Solar segment 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 2052. The resulting fair value measurement is categorized within Level III of the fair value hierarchy. In 2021, the Company relied on the recoverable amounts determined in 2019 for the Hydro and Energy Marketing segments in performing the 2021 goodwill impairment review. No impairment of goodwill arose for any segment. The key assumptions impacting the determination of fair value for the Wind and Solar and Hydro segments are the following: ▪ Discount rates used for the goodwill impairment calculation in 2021 for the Wind and Solar segment ranged from 5.0 per cent to 6.4 per cent (2020 – 4.8 per cent to 6.3 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, 2021
Disclosure of financial assets [abstract]
Other Assets	Other Assets The components of other assets are as follows: As at Dec. 31 2021 2020 South Hedland prepaid transmission access and distribution costs 65 70 Project development costs 29 25 Long-term prepaids and other assets 48 59 Loan receivable 55 52 Total other assets 197 206 Included in the Consolidated Statements of Financial Position as: Total current other assets (Note 14) 55 — Total long-term other assets 142 206 Total other assets 197 206 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. Project development costs primarily include the project costs for US wind and Australian development projects. Some project costs were written off in 2021 due to the uncertainty on timing of when the projects will proceed (see Note 7). Long-term prepaids and other assets includes: the funded portion of rail transportation commitments discussed in Note 36(C), the funded portion of the TransAlta Energy Transition Bill commitments discussed in Note 36(G) and other contractually required prepayments and deposits.

Decommissioning and Other Provi

Decommissioning and Other Provisions	12 Months Ended
	Dec. 31, 2021
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 restoration Other provisions Total Balance, Dec. 31, 2019 501 45 546 Liabilities incurred 1 34 35 Liabilities settled (18) (19) (37) Accretion 30 — 30 Acquisition of liabilities 1 — 1 Revisions in estimated cash flows 61 11 72 Revisions in discount rates (1) 36 — 36 Reversals — (6) (6) Change in foreign exchange rates (4) — (4) Balance, Dec. 31, 2020 608 65 673 Liabilities incurred 8 22 30 Liabilities settled (Note 36) (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 (1) Discount rates at Dec. 31, 2020, are generally lower than those at Dec. 31, 2019, due to decreases in the underlying risk-free US and Canadian benchmark yields and changes in credit spreads due to volatility within the market as a result of COVID-19. On average, these rates decreased by approximately 0.3 to 0.9 per cent. Decommissioning and Other Total Balance, Dec. 31, 2020 608 65 673 Current portion 21 38 59 Non-current portion 587 27 614 Balance, Dec. 31, 2021 793 34 827 Current portion 35 13 48 Non-current portion 758 21 779 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 2022 and 2072. The majority of the costs will be incurred between 2025 and 2050. In 2021, the Company adjusted the wind assets decommissioning and restoration provision as estimates were updated a fter the review of a recent engineering study on the decommissioning costs of the wind sites. The Company's current best estimate of the decommissioning and restoration provision increased by $120 million. The change in estimate is unrelated to the tower failure identified in the fourth quarter of 2021. The Company also increased the decommissioning and restoration provision by approximately $47 million for the Sundance and Keephills Units included in the Gas and Energy Transition segments to reflect the change in the timing of the expected reclamation work resulting from asset retirements and change in useful lives. These changes resulted in an increase in the related assets in PP&E. At Dec. 31, 2021, the Company had provided a surety bond in the amount of US$147 million (2020 – US$147 million) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2021, the Company had provided letters of credit in the amount of $188 million (2020 – $131 million) in support of future decommissioning obligations at the Highvale mine. In the fourth quarter of 2020, the Company adjusted the Sarnia decommissioning and restoration provision to reflect an updated engineering study. The Company's current best estimate of the decommissioning and restoration provision decreased by $15 million. This resulted in a decrease in the related assets in PP&E. In the third quarter of 2020, the Company adjusted the Highvale mine decommissioning and restoration provision to reflect the mine closure advancement, an updated mine plan and current mining activity including increased volume of material movement. The Company's current best estimate of the decommissioning and restoration provision increased by $75 million. This resulted in an increase in the related assets in PP&E. B. Other Provisions Other provisions also include provisions arising from ongoing business activities and include amounts related to commercial disputes between the Company and customers or suppliers. 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. During the third quarter of 2021, an onerous contract provision for future royalty payments of $14 million was recognized as a result of a decision to accelerate the plans to shut down the Highvale mine, with the effect that any remaining future royalty payments related to the extraction of coal has no future economic benefit. Payments required under the royalty contract will continue through 2023. At Dec. 31, 2021, the remaining balance of the provision was $14 million. During the fourth quarter of 2020, an onerous contract provision of $29 million

Credit Facilities, Long-Term De

Credit Facilities, Long-Term Debt and Lease Liabilities	12 Months Ended
	Dec. 31, 2021
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 2021 2020 Segment Maturity Currency Carrying Face Interest (1) Carrying Face Interest Credit facilities Committed syndicated bank facility (2) Corporate 2025 CAD — — — % 114 114 2.7 % Debentures 7.3% Medium term notes Corporate 2029 CAD 110 110 7.3 % 109 110 7.3 % 6.9% Medium term notes Corporate 2030 CAD 141 141 6.9 % 140 141 6.9 % Senior notes (3) 6.5% Senior notes Corporate 2040 USD 378 383 6.5 % 380 383 6.5 % 4.5% Senior notes Corporate 2022 USD 510 511 4.5 % 506 511 4.5 % Non-recourse Melancthon Wolfe Wind LP Wind & Solar 2028 CAD 235 237 3.8 % 268 270 3.8 % New Richmond Wind LP Wind & Solar 2032 CAD 120 121 4.0 % 127 128 4.0 % Kent Hills Wind LP bond (4) Wind & Solar 2033 CAD 221 221 4.5 % 230 233 4.5 % Windrise Wind LP bond Wind & Solar 2041 CAD 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 102 104 4.4 % 111 113 4.5 % TEC Hedland PTY Ltd bond (5) Gas 2042 AUD 732 742 4.1 % 772 782 4.1 % TransAlta OCP LP bond Gas 2030 CAD 263 265 4.5 % 284 287 4.5 % Tax equity financing Big Level & Antrim (6) Wind & Solar 2029 USD 106 112 6.6 % 112 119 6.6 % Lakeswind (7) Wind & Solar 2029 USD 18 18 10.5 % 22 22 10.5 % North Carolina Solar (8) Wind & Solar 2028 USD 11 11 7.3 % — — — Other Corporate 2023 CAD 4 4 5.9 % 7 6 5.9 % Total long-term debt 3,167 3,198 3,227 3,264 Lease liabilities 100 134 3,267 3,361 Less: current portion of long-term debt (837) (97) Less: current portion of lease liabilities (7) (8) Total current long-term debt and lease liabilities (844) (105) Total credit facilities, long-term debt and lease liabilities 2,423 3,256 ( 1) Interest 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, 2021 — US$700 million (Dec. 31, 2020 — US$700 million). (4) Kent Hills Wind LP bond is classified as a current liability. Refer to section B - Restrictions Related to Non-Recourse Debt and Other Debt, for more information. (5) AU face value at Dec. 31, 2021 — AU$800 million related to the TEC offering (2020 — AU$800 million). (6) US face value at Dec. 31, 2021 — US$88 million (2020 — US$94 million). (7) US face value at Dec. 31, 2021 — US$14 million (2020 — US$16 million). (8) US face value at Dec. 31, 2021 — US$9 million (2020 — nil). The Company's credit facilities are summarized in the table below: As at Dec. 31, 2021 Facility Utilized Available Maturity Outstanding letters of credit (1) Actual drawings TransAlta Corporation Committed syndicated bank facility (2) 1,250 618 — 632 Q2 2025 Canadian committed bilateral credit facilities 240 186 — 54 Q2 2023 TransAlta Renewables Committed credit facility (2) 700 98 — 602 Q2 2025 Total 2,190 902 — 1,288 (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. At Dec. 31, 2021, TransAlta provided cash collateral of $55 million. (2) Includes letters of credit issued under the demand facilities for TransAlta and TransAlta Renewables. The Company has $2 billion (2020 — $2 billion) of committed syndicated bank facilities and $0.2 billion of committed bilateral credit facilities, of which $1.3 billion was available as at Dec. 31, 2021 (2020 — $1.5 billion) and including the undrawn letters of credit are the primary source for short-term liquidity after the cash flow generated from the Company's business. This includes a $1.3 billion credit facility that was converted into a facility with a Sustainability Linked Loan ("SLL") and that was extended to June 30, 2025. The facility's financing terms will align the cost of borrowing to TransAlta's greenhouse gas emission reductions and gender diversity targets, which are part of the Company's overall plan for environment, social and governance. The SLL will have a cumulative pricing adjustment to the borrowing costs on the facilities and a corresponding adjustment to the standby fee (the "Sustainability Adjustment"). Depending on performance against interim targets that have been set for each year of the credit facility term, the Sustainability Adjustment is structured as a two-way mechanism and could move either up, down or remain unchanged for each sustainability performance target based on performance. In addition, the Company's committed bilateral credit facilities were also extended to June 30, 2023. Interest rates on the credit facilities vary depending on the option selected – Canadian prime, bankers' acceptances, USD LIBOR or US base rate – 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 $1.3 billion available under the credit facilities, the Company also has $947 million of available cash and cash equivalents 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 $157 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities. Debentures On Nov. 25, 2020, the Company redeemed $400 million of its then due 5.0 per cent medium term notes. Senior notes A total of US$370 million (2020 — US$370 million) of the senior notes has been designated as a hedge of the Company’s net investment in US foreign operations. Non-recourse debt On Dec. 6, 2021, TransAlta completed a secured green bond offering by way of private placement for approximately $173 million (the "Offering"). The 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 intends to use proceeds of the Offering to finance or refinance eligible green projects, including renewable energy facilities and to fund a construction reserve account. On Oct. 22, 2020, TEC closed an AU$800 million senior secured note offering, by way of a private placement, which is secured by, among other things, a first ranking charge over all assets of TEC. The notes bear interest at 4.07 per cent per annum, payable quarterly and matures on June 30, 2042, with principal payments starting on March 31, 2022. Funds were used to repay indebtedness on the credit facility and to fund future growth opportunities within TransAlta Renewables. The TEC Offering has a rating of BBB by Kroll Bond Rating Agency. 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 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 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 - on March 31, 2030, 10 years from commercial operation of the projects; Lakeswind - March 31, 2029, and North Carolina Solar on Dec. 31, 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, 2021, the Company was in compliance with all debt covenants except the Kent Hills non-recourse bond as discussed below. B. Restrictions Related to Non-Recourse Debt and Other Debt The Melancthon Wolfe Wind LP, Pingston, 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 $1.9 billion as at Dec. 31, 2021 (Dec. 31, 2020 — $1.8 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 2021, except the Kent Hills non-recourse bond as discussed below. However, 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 2022. At Dec. 31, 2021, $67 million (Dec. 31, 2020 —$73 million) of cash was subject to these financial restrictions. At Dec. 31, 2021, Kent Hills cash in the amount of $6 million is not able to be distributed or accessed by other corporate entities, as discussed below. Proceeds received from the TEC Notes in the amount of $3 million (AU$4 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. As a result of the determination that all 50 foundations require replacement, as well as certain resulting amendments to applicable insurance policies, the Company has provided notice to BNY Trust Company of Canada, as trustee (the “Trustee”), for the approximately $221 million outstanding non-recourse project bonds (the “KH Bonds”) secured by, among other things, the Kent Hills 1, 2 and 3 wind sites, that events of default may have occurred under the trust indenture governing the terms of the KH Bonds. Upon the occurrence of any event of default, holders of more than 50 per cent of the outstanding principal amount of the KH Bonds have the right to direct the Trustee to declare the principal and interest on the KH Bonds and all other amounts due, together with any make-whole amount (Dec. 31, 2021 — $39 million), to be immediately due and payable and to direct the Trustee to exercise rights against certain collateral. The Company is in discussions with the Trustee and holders of the Kent Hills bonds to negotiate required waivers and amendments while the Company works to remedy the matters described in the notice. Although the Company expects that it will reach agreement with the Trustee and holders of the KH Bonds with respect to terms of an acceptable waiver and amendment, there can be no assurance that the Company will receive such waivers and amendments. Accordingly, the Company has classified the entire carrying value of the KH Bonds as a current liability as at Dec. 31, 2021. C. Security Non-recourse debts totalling $1.5 billion as at Dec. 31, 2021 (Dec. 31, 2020 — $1.4 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, 2021 (Dec. 31, 2020 — $1 billion) and intangible assets with total carrying amounts of $78 million (Dec. 31, 2020 — $88 million). At Dec. 31, 2021, a non-recourse bond of approximately $103 million (Dec. 31, 2020 — $111 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 $263 million (Dec. 31, 2020 — $285 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 2022 (1) 2023 2024 2025 2026 2027 and thereafter Total Principal repayments (2) 836 155 113 127 127 1,840 3,198 Lease liabilities (3) (6) 4 3 3 3 93 100 (1) Includes the Kent Hills Wind LP non-recourse bonds. The successful receipt of waivers and amendments would extend principal repayments beyond 2022. (2) Excludes impact of hedge accounting and derivatives. (3) Lease liabilities include a lease incentive of $13 million, expected to be received in 2022. E. Restricted Cash At Dec. 31, 2021, the Company had nil (Dec. 31, 2020 – $9 million) in restricted cash related to the Big Level tax equity financing that is held in a construction reserve account. The proceeds were released from the construction reserve account in 2021. The Company had $17 million (Dec. 31, 2020 – $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 the next scheduled debt repayment in February 2022. The Company also had $53 million (Dec. 31, 2020 – $45 million) of restricted cash related to the TEC Notes; reserves are required to be held under TEC 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 committed syndicated credit facility, its $240 million bilateral committed credit facilities and its two uncommitted $150 million and $100 million demand letters of credit facilities. Letters of credit issued by TransAlta Renewables are drawn on its uncommitted $150 million demand letter of credit facility.

Exchangeable Securities

Exchangeable Securities	12 Months Ended
	Dec. 31, 2021
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"). Upon entering into the Investment Agreement and as required under the terms of the agreement, the Company paid Brookfield a $7.5 million structuring fee. A commitment fee of $15 million was also paid upon completion of the initial funding. These transaction costs, representing three per cent of the total investment of $750 million, have been recognized as part of the carrying value of the unsecured subordinated debentures. 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. On Oct. 30, 2020, Brookfield invested the second tranche of $400 million in exchange for redeemable, retractable first preferred shares. A. $750 million Exchangeable Securities As at Dec. 31, 2021 Dec. 31, 2020 Carrying value Face value Interest Carrying value Face value Interest Exchangeable debentures – due May 1, 2039 335 350 7 % 330 350 7 % Exchangeable preferred shares (1) 400 400 7 % 400 400 7 % Total long-term debt 735 750 730 750 (1) Exchangeable preferred share dividends are reported as interest expense. On Dec. 13, 2021, 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, 2022. The Exchangeable Preferred Shares are considered debt for accounting purposes, and as such, dividends are reported as interest expense (Note 11). B. Option to Exchange As at Dec. 31, 2021 Dec. 31, 2020 Description Base fair value Sensitivity Base fair value Sensitivity Option to exchange – embedded derivative — +nil -32 — +nil -33 The Investment Agreement allows Brookfield the option, after Dec. 31, 2024, to exchange all of the outstanding exchangeable securities 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 o f Dec. 31, 2021, Brookfield, through its affiliates, held, owned or had control over an aggregate of 35,425,696 common shares, representing approximately 13.1 per cent of the issued and outstanding common shares, calculated on an und

Defined Benefit Obligation and

Defined Benefit Obligation and Other Long-Term Liabilities	12 Months Ended
	Dec. 31, 2021
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 2021 2020 Defined benefit obligation (Note 31) 228 282 Long-term incentive accruals (Note 30) 4 4 Other 21 12 Total 253 298

Common Shares

Common Shares	12 Months Ended
	Dec. 31, 2021
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 2021 2020 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 269.8 2,896 277.0 2,978 Purchased and cancelled under the NCIB — — (7.3) (79) Effects of share-based payment plans — (3) — (3) Stock options exercised 1.2 8 0.1 — Issued and outstanding, end of year 271.0 2,901 269.8 2,896 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 2021 2020 Total shares purchased (1) — 7,352,600 Average purchase price per share — $8.33 Total cost — 61 Weighted average book value of shares cancelled — 79 Amount recorded in deficit — 18 (1) As at Dec. 31, 2021, includes nil (2020 — 456,200) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. 2021 On May 25, 2021, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement an NCIB for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2021 and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election. No common shares have been repurchased under the current and previous NCIB in 2021. 2020 On May 26, 2020, 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, the Company was permitted to purchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its issued and common shares as at May 25, 2020. C. Shareholder Rights Plan The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 26, 2019, to reflect current market practice and to reflect changes to the take-over bid regime. 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 26, 2019, and will need to be approved at the annual meeting of shareholders in 2022. 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 shareholder 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 2021 2020 2019 Net earnings (loss) attributable to common shareholders (576) (336) 52 Basic and diluted weighted average number of common shares outstanding (millions) 271 275 283 Net earnings (loss) per share attributable to common shareholders, basic and diluted (2.13) (1.22) 0.18 E. Dividends On Dec. 13, 2021, the Company declared a quarterly dividend of $0.05 per common share, payable on April 1, 2022. 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 2021 2020 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 10.2 248 Series B 2.4 58 1.8 45 Series C 11.0 269 11.0 269 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 I. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On March 18, 2021, the Company announced that 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") were tendered for conversion, on a one-for-one basis, into Series B Shares and Series A Shares, respectively after having taken into account all election notices. As a result of the conversion, the Company had 9.6 million Series A Shares and 2.4 million Series B Shares issued and outstanding at March 31, 2021. II. Preferred Share Series Information The holders are entitled to receive cumulative fixed quarterly cash dividends at a specified rate, 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 $25.00 per share, plus all declared and unpaid dividends at the time of redemption. ▪ Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Company and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2021, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over benchmark (per cent) Convertible to A Fixed 0.71924 March 31, 2026 2.03 B B Floating 0.53866 March 31, 2026 2.03 A C Fixed 1.00676 June 30, 2022 3.10 D D Floating — — 3.10 C E Fixed 1.29852 Sept. 30, 2022 3.65 F F Floating — — 3.65 E G Fixed 1.24700 Sept. 30, 2024 3.80 H H Floating — — 3.80 G B. Dividends The following table summarizes the value of the preferred share dividends declared in 2021 and 2020: Total dividends declared Series 2021 (1) 2020 A 7 9 B (2) 1 1 C 11 14 E 12 15 G 8 10 Total for the year 39 49 (1) No dividends were declared in the first quarter of 2021 as the quarterly dividend related to the period covering the first quarter of 2021 was declared in December 2020. (2) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.03 per cent. On Dec. 13, 2021, the Company declared a quarterly dividend of $0.1798 per share on the Series A preferred shares, $0.1331 per share on the Series B preferred shares, $0.2517 per share on the Series C preferred shares, $0.3246 per share on the Series E preferred shares, and $0.3118 per share on the Series G preferred shares, all payable on March 31, 2022. TransAlta’s capital is comprised of the following: As at Dec. 31 2021 2020 Increase/ Long-term debt (1) 3,267 3,361 (94) Exchangeable securities 735 730 5 Equity Common shares 2,901 2,896 5 Preferred shares 942 942 — Contributed surplus 46 38 8 Deficit (2,453) (1,826) (627) Accumulated other comprehensive earnings 146 302 (156) Non-controlling interests 1,011 1,084 (73) Less: available cash and cash equivalents (2) (947) (703) (244) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (17) (11) (6) Less: fair value asset of hedging instruments on long-term debt (4) (2) (2) — Total capital 5,629 6,811 (1,182) (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 because 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, 2021
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 2021 2020 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 269.8 2,896 277.0 2,978 Purchased and cancelled under the NCIB — — (7.3) (79) Effects of share-based payment plans — (3) — (3) Stock options exercised 1.2 8 0.1 — Issued and outstanding, end of year 271.0 2,901 269.8 2,896 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 2021 2020 Total shares purchased (1) — 7,352,600 Average purchase price per share — $8.33 Total cost — 61 Weighted average book value of shares cancelled — 79 Amount recorded in deficit — 18 (1) As at Dec. 31, 2021, includes nil (2020 — 456,200) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. 2021 On May 25, 2021, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement an NCIB for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2021 and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election. No common shares have been repurchased under the current and previous NCIB in 2021. 2020 On May 26, 2020, 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, the Company was permitted to purchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its issued and common shares as at May 25, 2020. C. Shareholder Rights Plan The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 26, 2019, to reflect current market practice and to reflect changes to the take-over bid regime. 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 26, 2019, and will need to be approved at the annual meeting of shareholders in 2022. 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 shareholder 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 2021 2020 2019 Net earnings (loss) attributable to common shareholders (576) (336) 52 Basic and diluted weighted average number of common shares outstanding (millions) 271 275 283 Net earnings (loss) per share attributable to common shareholders, basic and diluted (2.13) (1.22) 0.18 E. Dividends On Dec. 13, 2021, the Company declared a quarterly dividend of $0.05 per common share, payable on April 1, 2022. 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 2021 2020 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 10.2 248 Series B 2.4 58 1.8 45 Series C 11.0 269 11.0 269 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 I. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On March 18, 2021, the Company announced that 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") were tendered for conversion, on a one-for-one basis, into Series B Shares and Series A Shares, respectively after having taken into account all election notices. As a result of the conversion, the Company had 9.6 million Series A Shares and 2.4 million Series B Shares issued and outstanding at March 31, 2021. II. Preferred Share Series Information The holders are entitled to receive cumulative fixed quarterly cash dividends at a specified rate, 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 $25.00 per share, plus all declared and unpaid dividends at the time of redemption. ▪ Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Company and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2021, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over benchmark (per cent) Convertible to A Fixed 0.71924 March 31, 2026 2.03 B B Floating 0.53866 March 31, 2026 2.03 A C Fixed 1.00676 June 30, 2022 3.10 D D Floating — — 3.10 C E Fixed 1.29852 Sept. 30, 2022 3.65 F F Floating — — 3.65 E G Fixed 1.24700 Sept. 30, 2024 3.80 H H Floating — — 3.80 G B. Dividends The following table summarizes the value of the preferred share dividends declared in 2021 and 2020: Total dividends declared Series 2021 (1) 2020 A 7 9 B (2) 1 1 C 11 14 E 12 15 G 8 10 Total for the year 39 49 (1) No dividends were declared in the first quarter of 2021 as the quarterly dividend related to the period covering the first quarter of 2021 was declared in December 2020. (2) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.03 per cent. On Dec. 13, 2021, the Company declared a quarterly dividend of $0.1798 per share on the Series A preferred shares, $0.1331 per share on the Series B preferred shares, $0.2517 per share on the Series C preferred shares, $0.3246 per share on the Series E preferred shares, and $0.3118 per share on the Series G preferred shares, all payable on March 31, 2022. TransAlta’s capital is comprised of the following: As at Dec. 31 2021 2020 Increase/ Long-term debt (1) 3,267 3,361 (94) Exchangeable securities 735 730 5 Equity Common shares 2,901 2,896 5 Preferred shares 942 942 — Contributed surplus 46 38 8 Deficit (2,453) (1,826) (627) Accumulated other comprehensive earnings 146 302 (156) Non-controlling interests 1,011 1,084 (73) Less: available cash and cash equivalents (2) (947) (703) (244) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (17) (11) (6) Less: fair value asset of hedging instruments on long-term debt (4) (2) (2) — Total capital 5,629 6,811 (1,182) (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 because 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 Earnings	12 Months Ended
	Dec. 31, 2021
Disclosure of analysis of other comprehensive income by item [abstract]
Accumulated Other Comprehensive Earnings	Accumulated Other Comprehensive Earnings The components of, and changes in, accumulated other comprehensive earnings are as follows: 2021 2020 Currency translation adjustment Opening balance, Jan. 1 (21) (21) Losses on translating net assets of foreign operations, net of reclassifications to net earnings, (14) (11) Gains on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax — 11 Balance, Dec. 31 (35) (21) Cash flow hedges Opening balance, Jan. 1 436 527 Losses on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax (1) (208) (91) Balance, Dec. 31 228 436 Employee future benefits Opening balance, Jan. 1 (66) (55) Net actuarial gains (losses) on defined benefit plans, net of tax (2) 37 (11) Balance, Dec. 31 (29) (66) Other Opening balance, Jan. 1 (47) 3 Intercompany investments at FVOCI 29 (50) Balance, Dec. 31 (18) (47) Accumulated other comprehensive earnings 146 302 (1) Net of income tax of $57 million for the year ended Dec. 31, 2021 (2020 — $23 million). (2) Net of income tax of $11 million for the year ended Dec. 31, 2021 (2020 — $3 million).

Share-Based Payment Plans

Share-Based Payment Plans	12 Months Ended
	Dec. 31, 2021
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 PSU and RSU Plan, grants 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 two to three 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 2021 was $14 million (2020 — $15 million, 2019 — $19 million), which is included in operations, maintenance and administration expense in the Consolidated Statements of Earnings (Loss). B. Deferred Share Unit (“DSU”) Plan Under the DSU 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 DSUs was $3 million in 2021 (2020 — $1 million, 2019 — $2 million). C. Stock Option Plans On May 4, 2021, the Company approved amendments to the Stock Option Plan to reduce the total aggregate number of common shares held in reserve for issuance under this program. The amendments reduce the aggregate total number of shares reserved for issuance to 14.5 million common shares as at March 31, 2021 (Dec. 31, 2020 — 16.5 million common shares). The Company is authorized to grant options to purchase up to an aggregate of 14.5 million common shares at prices based on the market price of the shares on the TSX as determined on the grant date. The plan provides for grants of options to all full-time employees, including executives, designated by the Human Resources Committee from time to time. In 2021, the Company granted executive officers of the Company a total of 0.7 million stock options with a weighted average exercise price of $9.86 that vest after a three-year period and expire seven years after issuance (2020 — 0.7 million stock options at $9.17; 2019 — 1.4 million stock options at $5.65). The expense recognized relating to these grants during 2021 was approximately $2 million (2020 — approximately $2 million, 2019 — approximately $1 million). The total options outstanding and exercisable under these stock option plans at Dec. 31, 2021, are outlined below: Options outstanding Range of exercise prices (1) ($ per share) Number of options (millions) Weighted average remaining contractual life (years) Weighted average exercise price ($ per share) 5.00 - 9.00 3.2 4.2 7.54 (1) Options currently exercisable as at Dec. 31, 2021.

Employee Future Benefits

Employee Future Benefits	12 Months Ended
	Dec. 31, 2021
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, 2021. The latest actuarial valuation for accounting purposes of the Highvale and Canadian pension plans was at Dec. 31, 2019. 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, 2021. 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 pla n but is obligated to pay benefits under the terms of the plan as they come due. The Company posted a letter o f credit in March 2021 for the amount of $97 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, 2019, and Jan. 1, 2021, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2021. The Company provides several defined contribution plans, including an Australian superannuation plan and a US 401(k) savings plan, that provide for company contributions fr om 5 per cent to 10 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, 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 Year ended Dec. 31, 2019 Registered Supplemental Other Total Current service cost 7 2 1 10 Administration expenses 2 — — 2 Interest cost on defined benefit obligation 19 3 1 23 Interest on plan assets (12) (1) — (13) Curtailment and amendment gain (3) — — (3) Defined benefit expense 13 4 2 19 Defined contribution expense 9 — — 9 Net expense 22 4 2 28 C. Status of Plans The status of the defined benefit pension and other post-employment benefit plans is as follows: 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) Year ended Dec. 31, 2020 Registered Supplemental Other Total Fair value of plan assets 367 14 — 381 Present value of defined benefit obligation (542) (109) (24) (675) Funded status – plan deficit (175) (95) (24) (294) Amount recognized in the consolidated financial statements: Accrued current liabilities (5) (5) (2) (12) Other long-term liabilities (170) (90) (22) (282) Total amount recognized (175) (95) (24) (294) 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, 2019 373 13 — 386 Interest on plan assets 11 1 — 12 Net return on plan assets 25 (1) — 24 Contributions 6 6 1 13 Benefits paid (45) (5) (1) (51) Administration expenses (1) — — (1) Effect of translation on US plans (2) — — (2) As at Dec. 31, 2020 367 14 — 381 Interest on plan assets 8 — — 8 Net return 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 The fair value of the Company’s defined benefit plan assets by major category is as follows: Year ended 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 Year ended Dec. 31, 2020 Level I Level II Level III Total Equity securities Canadian — 64 — 64 US — 30 — 30 International — 103 — 103 Private — — 1 1 Bonds AAA — 36 — 36 AA — 67 — 67 A — 34 — 34 BBB 1 22 — 23 Below BBB — 4 — 4 Money market and cash and cash equivalents — 19 — 19 Total 1 379 1 381 Plan assets do not include any common shares of the Company at Dec. 31, 2021 and Dec. 31, 2020. The Company charged the registered plan nil for administrative services provided for the year ended Dec. 31, 2021 (2020 — nil). 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, 2019 543 99 22 664 Current service cost 5 2 1 8 Interest cost 16 3 1 20 Benefits paid (45) (5) (1) (51) Curtailment (2) — — (2) Actuarial loss arising from financial assumptions 43 10 2 55 Actuarial gain arising from experience adjustments (17) — — (17) Effect of translation on US plans (1) — (1) (2) 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 The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2021, is 13.6 years. F. Contributions The expected employer contributions for 2022 for the defined benefit pension and other post-employment benefit plans are as follows: Registered Supplemental Other Total Expected employer contributions 5 6 2 13 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: As at Dec. 31, 2021 As at Dec. 31, 2020 (per cent) Registered Supplemental Other Registered Supplemental Other Accrued benefit obligation 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 (1)(3) — — 6.8 — — 6.8 Dental-care cost escalation — — 4.0 — — 4.0 Benefit cost for the year Discount rate 2.4 2.3 2.3 3.0 3.0 3.0 Rate of compensation increase 2.9 3.0 — 2.9 3.0 — Assumed health-care cost trend rate Health-care cost escalation (2)(4) — — 7.1 — — 7.1 Dental-care cost escalation — — 4.0 — — 4.0 (1) 2021 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2030 for Canada. (2) 2021 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2030 for Canada. (3) 2020 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2030 for Canada. (4) 2020 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% 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, 2021 Registered Supplemental Other Pension Other 1% decrease in the discount rate 61 15 2 3 1 1% increase in the salary scale 3 — — — — 1% increase in the health-care cost trend rate — — 2 — — 10% improvement in mortality rates 20 4 — 1 —

Joint Arrangements

Joint Arrangements	12 Months Ended
	Dec. 31, 2021
Disclosure of interests in other entities [Abstract]
Joint arrangements	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. The change in investments is as follows: Skookumchuck EMG Total Balance, Dec. 31, 2019 — — — Contributions 86 16 102 Equity income 1 — 1 Change in foreign exchange rates (2) (1) (3) Balance, Dec. 31, 2020 85 15 100 Equity income 12 (3) 9 Distributions received (4) — (4) Balance, Dec. 31, 2021 93 12 105 A. Skookumchuck Wind Project On Nov. 25, 2020, TransAlta completed the purchase of a 49 per cent interest in SP Skookumchuck Investments, LLC from Southern Power for cash consideration of $86 million (US$66 million). Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state consisting of 38 Vestas V136 wind turbines. The project has a 20-year PPA with Puget Sound Energy. B. EMG International Acquisition On Nov. 30, 2020, TransAlta acquired a 30 per cent equity interest in EMG. Included in the purchase price of US$12 million is an estimated component contingent on EMG realizing certain earnings metrics in 2020 and 2021, following the acquisition. The final contingent amount will be calculated based on actual earnings metrics achieved. EMG is an established company with over 25 years of experience in process wastewater treatment and specializes in the design and construction of high-rate anaerobic digester systems. The investment provides an opportunity for TransAlta to leverage its expertise in on-site generation to support further advancements by EMG in the waste-to-energy space and will advance the Company's Clean Electricity Growth plan in the US market . 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 2021 2020 Results of operations Revenues 19 3 Expenses (10) (2) Proportionate share of net earnings 9 1 Joint arrangements at Dec. 31, 2021, 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 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, 2021
Disclosure of cash flow statement [Abstract]
Cash Flow Information	Cash Flow Information A. Change in Non-Cash Operating Working Capital Year ended Dec. 31 2021 2020 2019 (Use) source: Accounts receivable (28) (79) 261 Prepaid expenses 9 2 — Income taxes receivable — (4) (6) Inventory 42 6 (13) Accounts payable, accrued liabilities and provisions 153 160 (130) Income taxes payable (2) 4 9 Change in non-cash operating working capital 174 89 121 B. Changes in Liabilities from Financing Activities Balance Dec. 31, 2020 Cash issuances Repayments and dividends paid New leases Dividends declared Foreign exchange impact Other Balance Dec. 31, 2021 Long-term debt and lease 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 Balance Dec. 31, 2019 Cash issuances Repayments and dividends paid New leases Dividends declared Foreign exchange impact Other Balance Long-term debt and lease 3,212 753 (620) 16 — 5 (5) 3,361 Exchangeable securities 326 400 — — — — 4 730 Dividends payable (common and preferred) 37 — (86) — 107 — 1 59 Total liabilities from financing activities 3,575 1,153 (706) 16 107 5 — 4,150

Capital

Capital	12 Months Ended
	Dec. 31, 2021
Disclosure of notes and other explanatory information [Abstract]
Capital	Capital TransAlta’s capital is comprised of the following: As at Dec. 31 2021 2020 Increase/ Long-term debt (1) 3,267 3,361 (94) Exchangeable securities 735 730 5 Equity Common shares 2,901 2,896 5 Preferred shares 942 942 — Contributed surplus 46 38 8 Deficit (2,453) (1,826) (627) Accumulated other comprehensive earnings 146 302 (156) Non-controlling interests 1,011 1,084 (73) Less: available cash and cash equivalents (2) (947) (703) (244) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (17) (11) (6) Less: fair value asset of hedging instruments on long-term debt (4) (2) (2) — Total capital 5,629 6,811 (1,182) (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 because 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 its 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 (stable outlook). During 2021, Moody's reaffirmed its issuer rating of Ba1 with a stable outlook; DBRS reaffirmed the Company’s Unsecured Debt rating and Medium-Term Notes rating of BBB (low), the Preferred Shares rating of Pfd-3 (low) and Issuer Rating of BBB (low) with a stable outlook; and Standard and Poor’s reaffirmed the Company’s Unsecured Debt rating and Issuer 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, 2021 and 2020, 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 is available to fund operations, pay dividends, distribute payments to subsidiaries' non-controlling interests and invest in PP&E. Year ended Dec. 31 2021 2020 Increase Cash flow from operating activities 1,001 702 299 Change in non-cash working capital (174) (89) (85) Cash flow from operations before changes in working capital 827 613 214 Dividends paid on common shares (48) (47) (1) Dividends paid on preferred shares (39) (39) — Distributions paid to subsidiaries’ non-controlling interests (156) (97) (59) Property, plant and equipment expenditures (480) (486) 6 Inflow (outflow) 104 (56) 160 TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2021, $1.3 billion (2020 — $1.5 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 to maintain its capital structure and credit metrics within targeted ranges.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2021
Related Party [Abstract]
Related Party Transactions	Related-Party Transactions Details of the Company’s principal operating subsidiaries at Dec. 31, 2021, 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 2021 2020 2019 Total compensation 30 27 30 Comprised of: Short-term employee benefits 14 12 13 Post-employment benefits 1 2 2 Termination benefits — — 2 Share-based payments 15 13 13

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
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: 2022 2023 2024 2025 2026 2027 and thereafter Total Natural gas, transportation and 47 54 45 44 45 508 743 Transmission 9 9 6 6 2 — 32 Coal supply and mining agreements 1 76 98 90 75 — — 339 Long-term service agreements 89 46 43 32 25 54 289 Operating leases 4 3 3 1 1 31 43 Growth 941 276 — — — — 1,217 TransAlta Energy Transition Bill 6 6 — — — — 12 Total 1,172 492 187 158 73 593 2,675 (1) Relates to coal supply and mining agreements for Centralia Unit 2. A. Natural Gas, Transportation and Other Contracts The Company has fixed price or volume natural gas purchase and transportation contracts. Upon closing of the sale of the Pioneer Pipeline, additional 15-year natural gas transportation agreements for 275 terajoules ("TJ") per day on a firm basis by 2023 arose, bringing the total firm natural gas transportation to 400 TJ per day. Additionally, on June 30, 2021, the Company's agreement to purchase 139 TJ per day of natural gas from Tidewater Midstream & Infrastructure Ltd. was terminated and the commitment related to commodity dispatching was discharged, resulting in a reduction to the commitments disclosed at Dec. 31, 2020, by approximately $1.3 billion. 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 and Mining 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. Pricing is reflective of current market conditions. Commitments related to mining agreements for the Company’s share of its Sheerness joint operation have been reduced due to the accelerated plans to eliminate coal as a fuel source at the Sheerness facility. Amounts due under the contract and a mining royalty agreement for the Highvale mine have been recognized as onerous contract provisions, with the result that no amounts are included as future commitments. For additional information refer to Note 9. 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, coal facilities, equipment for coal and 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: White Rock Wind Projects, Garden Plain wind project, Horizon Hill wind project and the Northern Goldfields Solar Project. 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, 2021, the Company has funded approximately US$46 million of the commitment, which is recognized in other assets in the Consolidated Statements of Financial Position. H. 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. I. Transmission Line Loss Rule Proceeding The Company has been participating in a line loss rule proceeding before the AUC. The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed the AESO to recalculate loss factors for 2006 to 2016. The AUC approved an invoice settlement process and all three planned settlements have been received. The first two invoices were settled by the first quarter of 2021 and the third invoice settled in the second quarter of 2021. The true-up invoices issued by the AESO in the fourth quarter of 2021 were settled by Dec. 31, 2021, with no further invoices expected. II. Fortescue Metals Group Ltd. ("FMG") at South Hedland Power Station On May 2, 2021, the Company entered into a conditional settlement with FMG. The settlement was concluded and the actions were formally dismissed in the Supreme Court of Western Australia on Dec. 7, 2021. The settlement amount has been recorded as revenue in the fourth quarter of 2021, while all other balances previously provided for have been reversed. The settlement has resulted in FMG continuing as a customer of the South Hedland facility. III. Mangrove Claim On April 23, 2019, the Mangrove Partners Master Fund Ltd. ("Mangrove") commenced an action in the Ontario Superior Court of Justice naming the Company, the incumbent members of the Board of the Company on such date, and Brookfield as defendants. Mangrove was seeking to set aside the 2019 Brookfield transaction. The parties reached a confidential settlement and the action was discontinued in the Ontario Superior Court of Justice on April 30, 2021. IV. Keephills 1 Stator Force Majeure The Balancing Pool and ENMAX Energy Corporation ("ENMAX")are seeking to set aside an arbitration award on the basis that they did not receive a fair hearing. The Alberta Court of Queen’s Bench ("ABQB") dismissed the Balancing Pool and ENMAX’s allegations of unfairness on June 26, 2019. The Balancing Pool and ENMAX, however, sought leave to appeal the ABQB’s decision at the Court of Appeal, which was granted on Feb. 13, 2020. The appeal was heard on July 8, 2021. After the hearing, counsel for ENMAX raised concerns that one of the three justices on the appeal panel was distracted during the hearing. The justice has since recused herself from the hearing and the parties made submissions with respect to whether the remaining two justices can continue to issue the decision or whether a new hearing is required. On Nov. 8, 2021, the Alberta Court of Appeal released its decision and ordered that the appeal be re-heard by a new three-person panel of the Court of Appeal , which was heard on Jan. 27, 2022. TransAlta remains of the view that the Court of Appeal will affirm the ABQB decision that the arbitration proceeding was fair. V. Keephills 1 Superheater Force Majeure Keephills Unit 1 was taken offline from March 17, 2015, to May 17, 2015, as a result of a large leak in the secondary superheater. TransAlta claimed force majeure under the Alberta PPA. ENMAX, the purchaser under the Alberta PPA at the time, did not dispute the force majeure but the Balancing Pool attempted to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The parties reached a confidential settlement on April 21, 2021, and this matter is now resolved. VI. Sundance A Decommissioning TransAlta filed an application with the 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 late 2022 or early 2023. TransAlta expects to receive payment from the Balancing Pool for its decommissioning costs; however, the amount that the AUC will award is uncertain. VII. Hydro Power Purchase Arrangement ("Hydro PPA") Emission Performance Credits The Balancing Pool claims to be entitled to emission performance credits ("EPCs") earned by the Hydro facilities as a result of opting those facilities into the Carbon Competitiveness Incentive Regulation from 2018-2020 inclusive. The Balancing Pool claims ownership of the EPCs because it believes the change-in-law provisions under the Hydro PPA require the EPCs to be passed through to the Balancing Pool. TransAlta has not received any benefit from the EPCs or 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 is scheduled for Feb. 6-10, 2023. VIII. Direct Assigned Capital Deferral Account ("DACDA") Application AltaLink Management Ltd. ("AltaLink") and TransAlta (as a secondary applicant) filed an application before the AUC to recover its 2016-2018 DACDA costs incurred for the 240 kV line upgrades for the Edmonton Region Project. The AUC disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta disputed this finding and filed a permission to appeal application with the Court of Appeal and a review and variance application with the AUC (the “R&V”). The AUC dismissed the R&V application on April 22, 2021. The permission to appeal was subsequently discontinued on July 5, 2021, which concludes this matter. IX. Sarnia Outages The Sarnia cogeneration facility experienced three separate outages between May 19, 2021, and June 9, 2021, that resulted in steam interruptions to its industrial customers. As a result, the customers have submitted claims for liquidated damages. Steam supply disruptions of this nature are atypical and infrequent a t the Sarnia cogeneration facility. The Company conducted an investigation to determine the root cause of each of the three events, which concluded all three outages were within TransAlta's control. As such, liquidated damages in an amount dictated by the applicable agreements are payable by TransAlta to the customers for the three outages. X. Kaybob 3 Cogeneration Dispute The Company is engaged in a dispute with ET Canada as a result of ET Canada’s purported termination of agreements between the parties to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing facility. TransAlta commenced an arbitration seeking full compensation for ET Canada's wrongful termination of the agreements. ET Canada seeks a declaration that the agreements were lawfully terminated. A hearing is scheduled for two weeks starting Jan. 9, 2023.

Segments Disclosures

Segments Disclosures	12 Months Ended
	Dec. 31, 2021
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 CODM reviews 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 and 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, 2021 Hydro Wind & Solar (1) Gas (2) Energy Transition (3) Energy Corporate Total Equity 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 (gain) loss — 25 (40) 19 (38) — (34) — 34 — Decrease in finance lease receivable — — 41 — — — 41 — (41) — Finance lease income — — 25 — — — 25 — (25) — Unrealized foreign exchange gain on commodity — — (3) — — — (3) — 3 — Adjusted revenues 383 348 1,132 728 173 4 2,768 (18) (29) 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 power 16 17 374 432 — 4 843 — 211 1,054 Carbon compliance (4) — — 118 60 — — 178 — — 178 Gross margin 367 331 640 236 173 — 1,747 (18) (240) 1,489 OM&A 42 59 175 117 36 84 513 (2) — 511 Reclassifications and adjustments: Parts and materials write-down — — (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 taxes 3 10 13 6 — 1 33 (1) — 32 Net other operating expense (income) — — (40) 48 — — 8 — — 8 Reclassifications and adjustments: Royalty onerous contract and contract termination penalties — — — (48) — — (48) — 48 — Adjusted net other operating income — — (40) — — — (40) — 48 8 Adjusted EBITDA 322 262 494 133 137 (85) 1,263 Equity income from associate 9 Finance lease income 25 Depreciation and amortization (529) Asset impairment (648) Net interest expense (6) (245) Foreign exchange gain 16 Gain on sale of assets and other 54 Loss before income taxes (380) (1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. (2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal. (4) As of the first quarter of 2021, carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes. (5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. (6) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings. Year ended Dec. 31, 2020 Hydro Wind & Solar (1) Gas (2) Energy Transition (3) 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 (gain) loss — 2 33 (14) 21 — 42 — (42) — Decrease in finance lease receivable — — 17 — — — 17 — (17) — Finance lease income — — 7 — — — 7 — (7) — Unrealized foreign exchange loss on commodity — — 4 — — — 4 — (4) — Adjusted revenues 152 334 848 690 143 7 2,174 (3) (70) 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 8 25 221 352 — 12 618 — 187 805 Carbon compliance (4) — — 120 48 — (5) 163 — — 163 Gross margin 144 309 507 290 143 — 1,393 (3) (257) 1,133 OM&A 37 53 166 106 30 80 472 — — 472 Taxes, other than income taxes 2 8 13 9 — 1 33 — — 33 Net other operating expense (income) — — (11) — — — (11) — — (11) Reclassifications and adjustments: Impact of Sheerness going off-coal — — (28) — — — (28) — 28 — Adjusted net other operating income (39) — — — (39) — 28 (11) Adjusted EBITDA (5) 105 248 367 175 113 (81) 927 Equity income from associate 1 Finance lease income 7 Depreciation and amortization (654) Asset impairment (84) Net interest expense( 6) (238) Foreign exchange loss 17 Gain on sale of assets and other 9 Loss before income taxes (303) (1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. (2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal. (4) As of the first quarter of 2021, carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes. (5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. (6) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings. Year ended Dec. 31, 2019 Hydro Wind & Solar Gas (1) Energy Transition (2) Energy Corporate Total Reclass adjustments IFRS financials Revenues 156 312 851 905 129 (6) 2,347 — 2,347 Reclassifications and adjustments: Unrealized mark-to-market (gain) loss — (17) 6 (12) (10) — (33) 33 — Decrease in finance lease receivable — — 24 — — — 24 (24) — Finance lease income — — 6 — — — 6 (6) — Adjusted revenues 156 295 887 893 119 (6) 2,344 3 2,347 Fuel and purchased power 7 16 315 539 — 4 881 — 881 Reclassifications and adjustments: Australian interest income — — (4) — — — (4) 4 — Mine depreciation — — (81) (40) — — (121) 121 — Adjusted fuel and purchased power 7 16 230 499 — 4 756 125 881 Carbon compliance — — 138 77 — (10) 205 — 205 Gross margin 149 279 519 317 119 — 1,383 (122) 1,261 OM&A 36 50 162 124 30 73 475 — 475 Taxes, other than income taxes 3 8 9 8 — 1 29 — 29 Net other operating expense (income) — (10) (41) — — 2 (49) — (49) Termination of Sundance B and C PPAs — — (14) (42) — — (56) — (56) Adjusted EBITDA (3) 110 231 403 227 89 (76) 984 Finance lease income 6 Depreciation and amortization (590) Asset impairment (25) Gain on termination of Keephills 3 coal rights contract 88 Net interest expense (4) (179) Foreign exchange loss (15) Gain on sale of assets and other 46 Earnings before income taxes 193 (1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal. (3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. (4) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings. II. Selected Consolidated Statements of Financial Position Information As at Dec. 31, 2021 Hydro Wind Gas (1) Energy Transition (2) 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 As at Dec. 31, 2020 Hydro Wind Gas (1) Energy Transition (2) Energy Corporate Total PP&E 467 2,005 2,102 1,232 — 16 5,822 Right-of-use assets 6 55 5 53 — 22 141 Intangible assets 4 159 66 36 7 41 313 Goodwill 258 175 — — 30 — 463 (1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal. III. Selected Consolidated Statements of Cash Flows Information Additions to non-current assets are as follows: Year ended Dec. 31, 2021 Hydro Wind Gas (1) Energy Transition (2) 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 (1) Energy Transition (2) Energy Corporate Total Additions to non-current assets: PP&E 22 174 199 78 — 13 486 Intangible assets — — — 1 — 13 14 Year ended Dec. 31, 2019 Hydro Wind Gas (1) Energy Transition (2) Energy Corporate Total Additions to non-current assets: PP&E 23 229 74 90 — 1 417 Intangible assets — — — 2 — 12 14 (1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal. 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 2021 2020 2019 Depreciation and amortization expense on the Consolidated Statements of 529 654 590 Depreciation included in fuel, carbon compliance and purchased power (Note 6) 190 144 119 Depreciation and amortization on the Consolidated Statements of Cash Flows 719 798 709 C. Geographic Information I. Revenues Year ended Dec. 31 2021 2020 2019 Canada 1,854 1,227 1,460 US 731 716 727 Australia 136 158 160 Total revenue 2,721 2,101 2,347 II. Non-Current Assets Property, plant and Right-of-use assets Intangible assets Other assets As at Dec. 31 2021 2020 2021 2020 2021 2020 2021 2020 Canada 4,051 4,661 52 107 141 185 15 74 US 860 737 39 30 85 94 61 61 Australia 409 424 4 4 30 34 66 71 Total 5,320 5,822 95 141 256 313 142 206 D. Significant Customer During the year ended Dec. 31, 2021, sales to the AESO represent 35 per cent of the Company’s total revenue (2020 — sales to the AESO represented 15 per cent of the Company’s total revenue). There were no other companies greater than 10 per cent of the Company's total revenue.

Material Accounting Policies (P

Material Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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. 23, 2022.
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	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. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the good or services is 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 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, 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 (i.e., 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 (i.e., 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 (i.e., 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 Canadian and US coal operations, and the sale of coal to third parties. Obligations 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) are comprised of 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 ("PPA"). Contracts for differences is a financial contract whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh. A virtual PPA is where 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 (“FVOCI”). 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 FVOCI 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. 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 earnings ("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 earnings ("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 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 are comprised of cash and highly liquid investments with original maturities of three months or less.
Inventory	Inventory I. Fuel The Company’s inventory balance is comprised 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 internally produced coal inventory is determined using absorption costing, which is defined as the sum of all applicable expenditures and charges directly incurred in bringing inventory to its existing condition and location. Available coal inventory tends to increase during the second and third quarters as a result of favourable weather conditions and lower electricity production as maintenance is performed. Due to the limited number of processing steps incurred in mining coal and preparing it for consumption and its relatively low value on a per-unit basis, management does not distinguish between work in process and coal available for consumption. 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, 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 assets 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. Capital 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. Other 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 2-51 years Wind generation 2-30 years Gas generation 2-36 years Energy Transition 2-16 years Capital spares and other 2-51 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 and fuel and purchased power in the Consolidated Statements of Earnings (Loss). Amortization commences when th e intangible asset is available for use and is computed on a straight-line basis over the intangible asset’s estimated useful life. Est imated 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 2-7 years Power sale contracts 1-19 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 pro-rated 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. Decommissioning and restoration obligations for coal mines are incurred over time as new areas are mined, and a portion of the provision is settled over time as areas are reclaimed prior to final pit reclamation. Reclamation costs for mining assets are recognized on a unit-of-production basis. 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. 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. Lessor 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 earnings 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 30 to 60 years. In developing these assumptions, management uses estimates of contracted and future market prices based on expected market supply and demand in the region in which the plant operates, anticipated production levels, planned and unplanned outages, changes to regulations and transmission capacity or constraints for the remaining life of the facilities. 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 regards 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 2019 to 2021 is found in Notes 7, 18 and 21. 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. See Note 12 for further details on the impacts of the Company’s tax policies. 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 15. 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 fulfiled. 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, in determining the amount to be capitalized. 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) and Note 23. 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 2021 in respect of decommissioning and restoration provisions can be found in Notes 7 and 23. 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 18. 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. See Note 31 for disclosures on employee future benefits. 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 9 and 23 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. 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, which 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 as 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 of directors, 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, 2021, there were changes in estimates relating to defined benefit obligations and decommissioning and other provisions. Refer to Note 23 and 26 for further details. During the year ended Dec. 31, 2020, there were changes in estimates relating to the useful life of PP&E. Refer to Note 18 for further details.

Material Accounting Policies (T

Material Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
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 2-51 years Wind generation 2-30 years Gas generation 2-36 years Energy Transition 2-16 years Capital spares and other 2-51 years 2021 2020 2019 PP&E Impairments: Energy Transition facilities and projects (reversals) 345 79 (151) Energy Transition - Centralia mine decommissioning and restoration provision — 3 141 Changes in decommissioning and restoration provisions for retired assets (1) 32 — 2 Highvale mine 195 — — Kaybob Cogeneration Project 27 — — Wind 12 — — Hydro 5 2 — Gas 5 — — Intangible asset impairment - coal rights (2) 17 — — Assets held for sale (3) — — 15 Project development costs (4) 10 — 18 Asset impairment 648 84 25 (1) Changes related to changes in discount rates on retired assets. (2) Impaired to nil as no future coal will be extracted from this area of the mine. (3) 2019 amounts relate to trucks and associated inventory to be sold within the Energy Transition segment and accordingly, these items were impaired to net realizable value. (4) During 2021, the Company recorded an impairment 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. During 2020, the Company wrote off nil (2019 — $18 million) in project development costs related to projects that are no longer proceeding within the Corporate segment. A reconciliation of the changes in the carrying amount of PP&E is as follows: Land Renewable Gas generation (1) Energy Transition (1) Assets under Capital spares and other (2) Total Cost As at Dec. 31, 2019, as previously reported 91 3,574 1,671 7,342 228 489 13,395 Adjustments due to re-segmentation — — 2,402 (2,402) — — — As at Dec 31, 2019, adjusted 91 3,574 4,073 4,940 228 489 13,395 Additions — — — — 478 8 486 Acquisitions (Note 4) — — 1 — — — 1 Disposals (2) — — (1) — (2) (5) Impairment (Note 7) (9) (2) — (69) — (1) (81) Revisions and additions to decommissioning and restoration costs (Note 23) — 8 1 85 — — 94 Retirement of assets — (7) (47) (3) — (1) (58) Change in foreign exchange rates (1) (14) 45 (39) — 6 (3) Transfers 17 33 (138) (12) (211) (120) (431) As at Dec. 31, 2020, adjusted 96 3,592 3,935 4,901 495 379 13,398 Additions — — — — 478 2 480 Acquisitions (Note 4) — 146 — — — — 146 Disposals (1) — (2) (74) (2) — (79) Impairment (Note 7) — (15) (2) (468) (91) (13) (589) Revisions and additions to decommissioning and restoration costs (Note 23) — 129 6 — — — 135 Retirement of assets — (15) (57) (49) — — (121) Change in foreign exchange rates — 3 (25) 2 — (6) (26) Transfers 1 303 232 201 (696) 4 45 As at Dec. 31, 2021 96 4,143 4,087 4,513 184 366 13,389 Accumulated depreciation As at Dec. 31, 2019, as previously reported — 1,284 900 4,836 — 168 7,188 Adjustments due to re-segmentation — — 1,137 (1,137) — — — As at Dec 31, 2019, adjusted — 1,284 2,037 3,699 — 168 7,188 Depreciation — 141 258 304 — 14 717 Retirement of assets — (5) (43) (3) — — (51) Disposals — — — (1) — (1) (2) Change in foreign exchange rates — (4) 18 (37) — 2 (21) Transfers — — (212) (29) — (14) (255) As at Dec. 31, 2020, adjusted — 1,416 2,058 3,933 — 169 7,576 Depreciation — 154 184 264 — 12 614 Retirement of assets — (9) (55) (48) — — (112) Disposals — — (1) (72) — — (73) Change in foreign exchange rates — — (8) 2 — (1) (7) Transfers — — — 71 — — 71 As at Dec. 31, 2021 — 1,561 2,178 4,150 — 180 8,069 Carrying amount As at Dec. 31, 2019, adjusted 91 2,290 2,036 1,241 228 321 6,207 As at Dec. 31, 2020, adjusted 96 2,176 1,877 968 495 210 5,822 As at Dec. 31, 2021 96 2,582 1,909 363 184 186 5,320 (1) The gas generation and energy transition includes the previously disclosed coal generation and mining property and equipment categories. (2) Includes major spare parts and stand-by equipment available, but not in service and spare parts used for routine, preventive or planned maintenance.
Disclosure of detailed information about intangible assets	Estimated remaining useful lives of intangible assets are as follows: Software 2-7 years Power sale contracts 1-19 years

Business Acquisitions and Div_2

Business Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2021
Business Combinations [Abstract]
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 (A) Ada facility (B) Assets Cash and cash equivalents 4 1 Accounts receivable 4 3 Property, plant and equipment 146 1 Intangible assets (1) — 37 Right of use assets 13 — Inventory — 1 Prepaid expenses — 1 Liabilities Accounts payable and accrued liabilities (4) — Lease liabilities (13) — Tax equity liability (20) — Deferred taxes (3) — Risk management liabilities (current and long-term) — (5) Decommissioning provisions (4) (1) Net assets acquired 123 38 Cash consideration 120 32 Working capital consideration 3 6 Total purchase consideration transferred 123 38 1) This relates to the power sales contract acquired and is being amortized over six years.

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2021
Disclosure of revenue from contracts with customers [Abstract]
Disaggregation Of Revenue	The majority of the Company's revenues are derived from the sale of physical 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, 2021 Hydro Wind and Gas (1) Energy Transition (2) Energy Corporate and Other Total Revenues from contracts with customers Power and other (3) 28 207 395 24 — — 654 Environmental attributes — 28 — — — — 28 Revenue from contracts with customers 28 235 395 24 — — 682 Revenue from leases (4) — — 19 — — — 19 Revenue from derivatives and other — (25) (118) 138 211 4 210 Merchant revenue and other (3)(5) 355 95 813 547 — — 1,810 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) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details. (2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details. (3) The Alberta PPAs for certain facilities included in the Hydro, Gas and Energy Transition segments with the Balancing Pool expired at Dec. 31, 2020. These facilities began operating on a merchant basis in the Alberta market on Jan. 1, 2021. (4) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. (5) Includes merchant revenue, government incentives and other miscellaneous. Year ended Dec. 31, 2020 Hydro Wind and Gas (1) Energy Transition (2) Energy Corporate and Other Total Revenues from contracts with customers Power and other 141 238 465 156 — — 1,000 Environmental attributes — 23 — — — — 23 Revenue from contracts with customers 141 261 465 156 — — 1,023 Revenue from leases (3) — — 123 — — — 123 Revenue from derivatives and — (2) (8) 283 122 12 407 Merchant revenue and other (4) 11 70 207 265 — (5) 548 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) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details. (2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details. (3) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. (4) Includes merchant revenue, government incentives and other miscellaneous. Year ended Dec. 31, 2019 Hydro Wind and Gas (1) Energy Transition (2) Energy Corporate and Other Total Revenues from contracts with customers Power and other 142 221 497 185 — — 1,045 Environmental attributes — 23 — — — — 23 Revenue from contracts with customers 142 244 497 185 — — 1,068 Revenue from leases (3) — — 130 — — — 130 Revenue from derivatives and — 18 (15) 160 129 4 296 Merchant revenue and other (4) 14 50 239 560 — (10) 853 Total revenue 156 312 851 905 129 (6) 2,347 Revenues from contracts with customers Timing of revenue recognition At a point in time — 27 5 46 — — 78 Over time 142 217 492 139 — — 990 Total revenue from contracts with customers 142 244 497 185 — — 1,068 (1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details. (2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details. (3) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. (4) Includes merchant revenue, government incentives and other miscellaneous.
Changes In Contract Liabilities	The Company has recognized the following revenue-related contract liabilities: Contract liabilities 2021 2020 Balance, beginning of the year 15 15 Amounts transferred to revenue included in opening balance (1) (1) Consideration received 8 1 Increases due to amounts billed to customers — 2 Changes in transaction price 11 — Performance obligations satisfied (1) (2) Balance, end of year 32 15 Current portion 19 1 Long-term portion 13 14

Expenses by Nature (Tables)

Expenses by Nature (Tables)	12 Months Ended
	Dec. 31, 2021
Analysis of income and expense [abstract]
Expenses classified by nature	Fuel and purchased power and operations, maintenance and administrative ("OM&A") expenses classified by nature are as follows: Year ended Dec. 31 2021 2020 2019 Fuel and OM&A Fuel and OM&A Fuel and OM&A Gas fuel costs (1) 306 — 159 — 133 — Coal fuel costs (1)(2) 164 — 269 — 310 — Royalty, land lease, other direct costs 19 — 20 — 21 — Purchased power 339 — 163 — 246 — Mine depreciation (3) 190 — 144 — 119 — Salaries and benefits 36 234 50 235 52 228 Other operating expenses (4) — 277 — 237 — 247 Total 1,054 511 805 472 881 475 (1) During 2021, fuel costs have been split to show natural gas and coal fuel costs separately within the above table and carbon compliance costs have been reclassified from fuel and purchased power to a separate line called carbon compliance costs on the Consolidated Statements of Earnings (Loss). Prior periods have been adjusted to reflect these reclassifications. (2) Included in coal fuel costs for 2021 was $17 million related to the impairment of coal inventory recorded during 2021 (2020 — $15 million). Refer to Note 17 for further details. (3) Included in mine depreciation for 2021 was $48 million related to the mine depreciation that was initially recorded in the standard cost of coal inventory and then subsequently impaired during 2021 (2020 — $22 million) . Refer to Note 17 for further details.

Asset Impairment (Tables)

Asset Impairment (Tables)	12 Months Ended
	Dec. 31, 2021
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 2-51 years Wind generation 2-30 years Gas generation 2-36 years Energy Transition 2-16 years Capital spares and other 2-51 years 2021 2020 2019 PP&E Impairments: Energy Transition facilities and projects (reversals) 345 79 (151) Energy Transition - Centralia mine decommissioning and restoration provision — 3 141 Changes in decommissioning and restoration provisions for retired assets (1) 32 — 2 Highvale mine 195 — — Kaybob Cogeneration Project 27 — — Wind 12 — — Hydro 5 2 — Gas 5 — — Intangible asset impairment - coal rights (2) 17 — — Assets held for sale (3) — — 15 Project development costs (4) 10 — 18 Asset impairment 648 84 25 (1) Changes related to changes in discount rates on retired assets. (2) Impaired to nil as no future coal will be extracted from this area of the mine. (3) 2019 amounts relate to trucks and associated inventory to be sold within the Energy Transition segment and accordingly, these items were impaired to net realizable value. (4) During 2021, the Company recorded an impairment 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. During 2020, the Company wrote off nil (2019 — $18 million) in project development costs related to projects that are no longer proceeding within the Corporate segment. A reconciliation of the changes in the carrying amount of PP&E is as follows: Land Renewable Gas generation (1) Energy Transition (1) Assets under Capital spares and other (2) Total Cost As at Dec. 31, 2019, as previously reported 91 3,574 1,671 7,342 228 489 13,395 Adjustments due to re-segmentation — — 2,402 (2,402) — — — As at Dec 31, 2019, adjusted 91 3,574 4,073 4,940 228 489 13,395 Additions — — — — 478 8 486 Acquisitions (Note 4) — — 1 — — — 1 Disposals (2) — — (1) — (2) (5) Impairment (Note 7) (9) (2) — (69) — (1) (81) Revisions and additions to decommissioning and restoration costs (Note 23) — 8 1 85 — — 94 Retirement of assets — (7) (47) (3) — (1) (58) Change in foreign exchange rates (1) (14) 45 (39) — 6 (3) Transfers 17 33 (138) (12) (211) (120) (431) As at Dec. 31, 2020, adjusted 96 3,592 3,935 4,901 495 379 13,398 Additions — — — — 478 2 480 Acquisitions (Note 4) — 146 — — — — 146 Disposals (1) — (2) (74) (2) — (79) Impairment (Note 7) — (15) (2) (468) (91) (13) (589) Revisions and additions to decommissioning and restoration costs (Note 23) — 129 6 — — — 135 Retirement of assets — (15) (57) (49) — — (121) Change in foreign exchange rates — 3 (25) 2 — (6) (26) Transfers 1 303 232 201 (696) 4 45 As at Dec. 31, 2021 96 4,143 4,087 4,513 184 366 13,389 Accumulated depreciation As at Dec. 31, 2019, as previously reported — 1,284 900 4,836 — 168 7,188 Adjustments due to re-segmentation — — 1,137 (1,137) — — — As at Dec 31, 2019, adjusted — 1,284 2,037 3,699 — 168 7,188 Depreciation — 141 258 304 — 14 717 Retirement of assets — (5) (43) (3) — — (51) Disposals — — — (1) — (1) (2) Change in foreign exchange rates — (4) 18 (37) — 2 (21) Transfers — — (212) (29) — (14) (255) As at Dec. 31, 2020, adjusted — 1,416 2,058 3,933 — 169 7,576 Depreciation — 154 184 264 — 12 614 Retirement of assets — (9) (55) (48) — — (112) Disposals — — (1) (72) — — (73) Change in foreign exchange rates — — (8) 2 — (1) (7) Transfers — — — 71 — — 71 As at Dec. 31, 2021 — 1,561 2,178 4,150 — 180 8,069 Carrying amount As at Dec. 31, 2019, adjusted 91 2,290 2,036 1,241 228 321 6,207 As at Dec. 31, 2020, adjusted 96 2,176 1,877 968 495 210 5,822 As at Dec. 31, 2021 96 2,582 1,909 363 184 186 5,320 (1) The gas generation and energy transition includes the previously disclosed coal generation and mining property and equipment categories. (2) Includes major spare parts and stand-by equipment available, but not in service and spare parts used for routine, preventive or planned maintenance.

Finance Lease Receivables (Tabl

Finance Lease Receivables (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 Minimum Present value of Minimum Present value of Within one year 58 54 63 56 Second to fifth years inclusive 127 105 169 126 More than five years 80 66 100 82 265 225 332 264 Less: unearned finance lease income 40 — 68 — Total finance lease receivables 225 225 264 264 Included in the Consolidated Statements of Financial Position as: Current portion of finance lease receivables (Note 14) 40 36 Long-term portion of finance lease receivables 185 228 Total finance lease receivables 225 264

Net Other Operating Expense (_2

Net Other Operating Expense (Income) (Tables)	12 Months Ended
	Dec. 31, 2021
Analysis of income and expense [abstract]
Disclosure of components of net other operating (income) losses	Net other operating income includes the following: Year ended Dec. 31 2021 2020 2019 Alberta Off-Coal Agreement (40) (40) (40) Supplier settlements 34 — — Onerous contract provisions 14 29 — Insurance recoveries and other (1) — — (9) Net other operating expense (income) 8 (11) (49) (1) There were no insurance recoveries in 2021 or 2020. In

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2021
Interests In Other Entities [Abstract]
Investments in joint ventures and associates	The change in investments is as follows: Skookumchuck EMG Total Balance, Dec. 31, 2019 — — — Contributions 86 16 102 Equity income 1 — 1 Change in foreign exchange rates (2) (1) (3) Balance, Dec. 31, 2020 85 15 100 Equity income 12 (3) 9 Distributions received (4) — (4) Balance, Dec. 31, 2021 93 12 105 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 2021 2020 Results of operations Revenues 19 3 Expenses (10) (2) Proportionate share of net earnings 9 1

Net Interest Expense (Tables)

Net Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2021
Analysis of income and expense [abstract]
Components of net interest expense	Year ended Dec. 31 2021 2020 2019 Interest on debt 163 158 161 Interest on exchangeable debentures (Note 25) 29 29 20 Interest on exchangeable preferred shares (Note 25) 28 5 — Interest income (11) (10) (13) Capitalized interest (Note 18) (14) (8) (6) Interest on lease liabilities 7 8 4 Credit facility fees, bank charges and other interest 18 18 15 Tax shield on tax equity financing (Note 24) (1) (9) 1 (35) Interest on line loss rule proceeding (Note 36(H)(I)) — 5 — Other (2) 2 2 10 Accretion of provisions (Note 23) 32 30 23 Net interest expense 245 238 179 (1) Credit in 2021 primarily relates to the tax benefit associated with investment tax credits claimed in 2021 on the North Carolina Solar projects that was assigned to the tax equity investor. Credit in 2019 primarily relates to the tax benefit associated with bonus tax depreciation claimed in 2019 on the Big Level and Antrim projects 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. (2) In 2021, other interest expense included approximately nil (2020 — nil , 2019 — $5 million) for the significant financing component required under IFRS 15.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Taxes [Abstract]
Rate reconciliations	Rate Reconciliations Year ended Dec. 31 2021 2020 2019 Earnings (loss) before income taxes (380) (303) 193 Net earnings (loss) attributable to non-controlling interests not subject to tax (33) 2 (26) Adjusted earnings (loss) before income taxes (413) (301) 167 Statutory Canadian federal and provincial income tax rate (%) 23.6 % 24.5 % 26.5 % Expected income tax expense (recovery) (98) (74) 44 Increase (decrease) in income taxes resulting from: Differences in effective foreign tax rates 4 3 5 Deferred income tax expense related to temporary difference on investment in — 9 — Write-down (reversal of write-down) of unrecognized deferred income tax assets 134 8 (9) Statutory and other rate differences 4 (7) (31) Other 1 11 8 Income tax expense (recovery) 45 (50) 17 Effective tax rate (%) (11 %) 17 % 10 %
Components of income tax expense	The components of income tax expense are as follows: Year ended Dec. 31 2021 2020 2019 Current income tax expense 56 35 35 Deferred income tax expense (recovery) related to the origination and reversal of temporary differences (145) (95) 22 Deferred income tax expense related to temporary difference on investment in subsidiary — 9 — Deferred income tax recovery resulting from changes in tax rates or laws — (7) (31) Deferred income tax expense (recovery) arising from the unrecognized deferred income tax assets (1) 134 8 (9) Income tax expense (recovery) 45 (50) 17 Year ended Dec. 31 2021 2020 2019 Current income tax expense 56 35 35 Deferred income tax recovery (11) (85) (18) Income tax expense (recovery) 45 (50) 17
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 2021 2020 2019 Income tax expense (recovery) related to: Net impact related to cash flow hedges (57) (23) 6 Net actuarial gains (losses) 11 (3) (7) Income tax recovery reported in equity (46) (26) (1)
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 2021 2020 Net operating loss carryforwards (1) 530 469 Future decommissioning and restoration costs 183 140 Property, plant and equipment (651) (717) Risk management assets and liabilities, net (53) (107) Employee future benefits and compensation plans 53 62 Interest deductible in future periods 17 22 Foreign exchange differences on US-denominated debt 16 31 Other deductible temporary differences (5) 2 Net deferred income tax liability, before write-down of deferred income tax assets 90 (98) Unrecognized deferred income tax assets (380) (247) Net deferred income tax liability, after write-down of deferred income tax assets (290) (345) (1) Net operating losses expire between 2031 and 2040. The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows: As at Dec. 31 2021 2020 Deferred income tax assets (1) 64 51 Deferred income tax liabilities (354) (396) Net deferred income tax liability (290) (345) (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, 2021
Interests In Other Entities [Abstract]
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, 2021 TransAlta Cogeneration L.P. 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 the 167 MW Kent Hills wind facility located in New Brunswick. Year ended Dec. 31 2021 2020 2019 Revenues 470 436 446 Net earnings 139 97 183 Total comprehensive earnings 66 223 138 Amounts attributable to the non-controlling interests: Net earnings 50 40 73 Total comprehensive earnings 21 90 56 Distributions paid to non-controlling interests 100 80 69 As at Dec. 31 2021 2020 Current assets 430 743 Long-term assets 3,319 2,913 Current liabilities (593) (364) Long-term liabilities (1,033) (987) Total equity (2,123) (2,305) Equity attributable to non-controlling interests (869) (948) Non-controlling interests’ share (per cent) 39.9 39.9 In 2020, the Company's ownership per cent decreased from 60.4 per cent in 2019 to 60.1 per cent due to TransAlta Renewables issuing approximately 1 million common shares under their Dividend Reinvestment Plan ("DRIP"). The Company did not participate in this plan. In the fourth quarter of 2020, TransAlta Renewables suspended the DRIP in respect of any future declared dividends. B. TA Cogen Year ended Dec. 31 2021 2020 2019 Results of operations Revenues 265 146 181 Net earnings (loss) 103 (13) 43 Total comprehensive earnings (loss) 103 (13) 43 Amounts attributable to the non-controlling interest: Net earnings (loss) 62 (6) 21 Total comprehensive earnings (loss) 62 (6) 21 Distributions paid to Canadian Power Holdings Inc. 56 17 37 As at Dec. 31 2021 2020 Current assets 66 69 Long-term assets 312 323 Current liabilities (52) (78) Long-term liabilities (36) (37) Total equity (290) (277) Equity attributable to Canadian Power Holdings Inc. (142) (136) Non-controlling interest share (per cent) 49.99 49.99 Details of the Company’s principal operating subsidiaries at Dec. 31, 2021, 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, 2021
Subclassifications of assets, liabilities and equities [abstract]
Trade and Other Receivables	As at Dec. 31 2021 2020 Trade accounts receivable 499 488 Collateral paid (Note 16) 55 49 Current portion of finance lease receivables (Note 8) 40 36 Loan receivable (Note 22) 55 — Income taxes receivable 2 10 Trade and other receivables 651 583

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
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, 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 receivable — — 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 (Note 25) — — 735 735 (1) Includes cash equivalents of nil. (2) Includes current portion. Carrying value as at Dec. 31, 2020 Derivatives Derivatives Amortized cost Total Financial assets Cash and cash equivalents (1) — — 703 703 Restricted cash — — 71 71 Trade and other receivables — — 583 583 Long-term portion of finance lease receivables — — 228 228 Risk management assets Current 102 69 — 171 Long-term 471 50 — 521 Other assets (Note 22) — — 52 52 Financial liabilities Accounts payable and accrued liabilities — — 599 599 Dividends payable — — 59 59 Risk management liabilities Current 10 84 — 94 Long-term — 68 — 68 Credit facilities, long-term debt and lease liabilities (2) — — 3,361 3,361 Exchangeable securities (Note 25) — — 730 730 (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, 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 receivable — — 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 (Note 25) — — 735 735 (1) Includes cash equivalents of nil. (2) Includes current portion. Carrying value as at Dec. 31, 2020 Derivatives Derivatives Amortized cost Total Financial assets Cash and cash equivalents (1) — — 703 703 Restricted cash — — 71 71 Trade and other receivables — — 583 583 Long-term portion of finance lease receivables — — 228 228 Risk management assets Current 102 69 — 171 Long-term 471 50 — 521 Other assets (Note 22) — — 52 52 Financial liabilities Accounts payable and accrued liabilities — — 599 599 Dividends payable — — 59 59 Risk management liabilities Current 10 84 — 94 Long-term — 68 — 68 Credit facilities, long-term debt and lease liabilities (2) — — 3,361 3,361 Exchangeable securities (Note 25) — — 730 730 (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 tables summarize 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, 2021 and 2020, respectively: Year ended Dec. 31, 2021 Year ended Dec. 31, 2020 Hedge Non-hedge Total Hedge Non-hedge Total Opening balance 573 9 582 678 8 686 Changes attributable to: Market price changes on existing contracts (181) 4 (177) (18) 3 (15) Market price changes on new contracts — (134) (134) — 7 7 Contracts settled (107) (5) (112) (71) (10) (81) Change in foreign exchange rates — — — (16) 1 (15) Net risk management assets (liabilities) at end of period 285 (126) 159 573 9 582 Additional Level III information: Losses recognized in other comprehensive earnings (181) — (181) (34) — (34) Total gains (losses) included in earnings before income 107 (130) (23) 71 11 82 Unrealized gains (losses) included in earnings before — (135) (135) — 1 1
Disclosure for sensitivity ranges for the base fair value	As at Dec. 31, 2021 Description Sensitivity Valuation technique Unobservable input Reasonable possible change Long-term power sale – US +22 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$3 or price increase of US$20 -145 Coal +3 Numerical derivative valuation Illiquid future power prices (per MWh) Price decrease of US$3 or price increase of US$20 Volatility 80% to 120% -18 Rail rate escalation zero to 4% Full requirements +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 of 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 As at Dec. 31, 2020 Description Sensitivity Valuation technique Unobservable input Reasonable possible change Long-term power +35 Long-term price forecast Illiquid future power prices (per MWh) Price decrease of US$3 or a price increase of US$5 -59 Coal +3 Numerical derivative valuation Illiquid future power prices (per MWh) Price decrease of US$3 or a price increase of US$5 Volatility 80% to 120% -5 Rail rate escalation zero to 4% Full +3 Historical bootstrap Volume 95% to 105% -3 Cost of supply (+/-) US$1 per MWh Long-term wind +22 Long-term price forecast Illiquid future power prices (per MWh) Price increase or decrease of US$6 -22 Illiquid future REC prices (per unit) Price increase or decrease of US$1 Others +5 -5
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, 2021 — 770 — 770 735 Long-term debt — Dec. 31, 2021 — 3,272 — 3,272 3,167 Exchangeable securities — Dec. 31, 2020 — 769 — 769 730 Long-term debt — Dec. 31, 2020 — 3,480 — 3,480 3,227 (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, and a reconciliation of changes is as follows: As at Dec. 31 2021 2020 2019 Unamortized net gain (loss) at beginning of year (33) 9 49 New inception gain (loss) (1) (50) (13) 3 Amortization recorded in net earnings during the year (19) (29) (43) Unamortized net gain (loss) at end of year (2) (102) (33) 9 (1) During 2021, the Company entered into PPAs for the White Rock Wind Projects 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 power agreement contract period. 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. (2) During 2020, the net inception gain on the long-term fixed price power sale contract in the US changed to a loss position based on the day one forward price curve at inception of the contract.

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2021
Financial Instruments [Abstract]
Derivative Financial Instruments	Net Risk Management Assets and Liabilities Aggregate net risk management assets (liabilities) are as follows: 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 As at Dec. 31, 2020 Cash flow Not Total Commodity risk management Current 101 (11) 90 Long-term 471 (19) 452 Net commodity risk management assets (liabilities) 572 (30) 542 Other Current (9) (4) (13) Long-term — 1 1 Net other risk management liabilities (9) (3) (12) Total net risk management assets (liabilities) 563 (33) 530 The Company’s outstanding commodity derivative instruments designated as hedging instruments are as follows: As at Dec. 31 2021 2020 Type Notional Notional Notional Notional Electricity (MWh) (1) — — 95 — (1) Excludes the long-term power sale - US contract. For further details on this contract, refer to Note 15(B)(I)(c)(i). The Company’s outstanding commodity derivative instruments not designated as hedging instruments are as follows: As at Dec. 31 2021 2020 Type Notional Notional Notional Notional Electricity (MWh) 46,139 14,951 12,944 8,258 Natural gas (GJ) 7,501 173,898 23,035 177,448 Transmission (MWh) 37 1,097 — 1,578 Emissions (MWh) 445 2,030 1,831 2,112 Emissions (tonnes) 350 350 2,160 2,365 Coal (tonnes) — 9,352 — 9,078 As at Dec. 31 2021 2020 Notional Notional Fair value Maturity Notional Notional Fair value liability Maturity Foreign exchange forward contracts - foreign-denominated receipts/expenditures CAD10 USD8 — 2022 CAD71 USD54 (2) 2021 AUD19 USD14 — 2022 — — — — As at Dec. 31 2021 2020 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign exchange forward contracts – foreign-denominated receipts/expenditures AUD28 CAD26 (5) 2022-2025 AUD197 CAD181 (14) 2021 - 2024 USD271 CAD357 8 2022-2025 USD47 CAD72 9 2021 - 2024 AUD4 USD3 — 2021 CAD1 EUR1 — 2021 Foreign exchange forward contracts – foreign-denominated debt CAD191 USD150 1 2022 CAD191 USD150 2 2022
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 2021 2020 Current Long-term Current Long-term Current Long-term Current Long-term Gross amounts recognized 394 330 (306) (122) 120 69 (132) (104) Gross amounts set-off (137) (53) 138 54 (69) (10) 69 10 Net amounts as included in the 257 277 (168) (68) 51 59 (63) (94)
Effect of Hedges	The impact of hedged items designated in hedging relationships on OCI and net earnings is: 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 on — 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) loss reclassified Pre-tax Location of (gain) loss Pre-tax Commodity contracts 41 Revenue (137) Revenue — Foreign exchange forwards on (1) Property, plant — Foreign exchange — Forward starting interest rate (12) Interest expense (4) Interest expense — OCI impact 28 OCI impact (141) Net earnings impact — Year ended Dec. 31, 2019 Effective portion Ineffective portion Derivatives in cash flow Pre-tax Location of (gain) Pre-tax Location of (gain) loss Pre-tax Commodity contracts 77 Revenue (59) Revenue — Forward starting interest rate — Interest expense 6 Interest expense — OCI impact 77 OCI impact (53) Net earnings impact —
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 cent (2020 — three cent, 2019 — three cent) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter. Year ended Dec. 31 2021 2020 2019 Currency Net earnings increase (decrease) (1) OCI gain (1)(2) Net earnings decrease (1) OCI gain (1)(2) Net earnings decrease (1) OCI gain (1)(2) USD (13) 1 (8) 1 (18) 2 AUD 1 — (4) — (6) — Total (12) 1 (12) 1 (24) 2 (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.
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, 2021: Investment grade (Per cent) Non-investment grade (Per cent) Total (Per cent) Total Trade and other receivables (1,2) 89 11 100 651 Long-term finance lease receivable 100 — 100 185 Risk management assets (1) 86 14 100 707 Total 1,543 (1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.
Maturity Analysis of Financial Liabilities	A maturity analysis of the Company's financial liabilities is as follows: 2022 2023 2024 2025 2026 2027 and thereafter Total Accounts payable and accrued liabilities 689 — — — — — 689 Long-term debt (1) Debentures — — — — — 251 251 Senior Notes 511 — — — — 383 894 Non-recourse — Hydro — 45 — — — — 45 Non-recourse — Wind & Solar 263 49 52 54 51 283 752 Non-recourse — Gas 44 45 47 59 61 855 1,111 Tax equity financing 15 15 14 14 15 68 141 Other 3 1 — — — — 4 Exchangeable securities (2) — — — 750 — — 750 Commodity risk management (assets) (45) (35) (117) (95) 1 (2) (293) Other risk management (assets) liabilities (2) (3) (3) 1 — (1) (8) Lease liabilities (3) (6) 4 3 3 3 93 100 Interest on long-term debt and lease liabilities (4) 149 120 115 109 104 787 1,384 Interest on exchangeable securities (2, 4) 53 53 62 — — — 168 Dividends payable 62 — — — — — 62 Total 1,736 294 173 895 235 2,717 6,050 (1) Excludes impact of hedge accounting and derivatives. (2) Assumes the exchangeable securities will be exchanged on Jan. 1, 2025. Refer to Note 25 for further details. (3) Lease liabilities include a lease incentiv e of $13 million expec ted to be received in 2022. The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount, timing and uncertainty of future cash flows: Maturity 2022 2023 2024 2025 2026 2027 and thereafter Cash flow hedges Foreign currency forward contracts Notional amount ($ millions) CAD/USD 8 — — — — — AUD/USD 14 — — — — — Average Exchange Rate CAD/USD 0.7893 — — — — — AUD/USD 0.7352 — — — — — Commodity derivative instruments Electricity Notional amount (thousands MWh) 3,329 3,329 3,338 2,628 — — Average price ($ per MWh) 71.95 73.76 75.6 77.49 — —
Hedging Instruments	The impact of the hedging instruments on the statement of financial position is as follows: 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 13 MMWh 285 Risk management assets (181) Interest rate risk Cash flow hedges Interest rate swap USD300 3 Risk management assets 3 Foreign currency risk Cash flow hedges Foreign-denominated expenditures USD8 — Risk management assets — Foreign-denominated expenditures USD14 — Risk management assets — Net investment hedges Foreign-denominated debt USD370 CAD473 Credit facilities, long-term debt and lease liabilities — As at Dec. 31, 2020 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 16 MMWh 573 Risk management assets (33) Interest rate risk Cash flow hedges Interest rate swap USD150 (3) Risk management liabilities 3 Interest rate swap CAD75 (4) Risk management liabilities 4 Foreign currency risk Net investment hedges Foreign-denominated debt USD370 CAD472 Credit facilities, long-term debt and lease liabilities 11 The impact of the hedged items on the statement of financial position is as follows: As at Dec. 31 2021 2020 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 – (181) 226 (33) 417 Interest rate risk Cash flow hedges Interest expense on long-term 3 2 7 19 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 — (35) 11 (21) (1) Included in AOCI.

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2021
Disclosure of inventories [Abstract]
Disclosure Of The Components Of Inventories	The components of inventory are as follows: As at Dec. 31 2021 2020 Parts and materials 82 107 Coal 27 83 Deferred stripping costs — 8 Natural gas 3 2 Purchased emission credits (1) 55 38 Total 167 238 (1) Purchased emissions credits increased due to trading and compliance credits purchased, including those for Alberta compliance under the Technology Innovation and Emissions Reduction program.
Disclosure Of The Change In Inventory	The change in inventory is as follows: 2021 2020 Balance, Jan. 1 238 251 Net additions (use) 22 26 Write-downs, coal (65) (37) Write-downs, parts and materials (28) — Change in foreign exchange rates — (2) Balance, Dec. 31 167 238

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2021
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 2-51 years Wind generation 2-30 years Gas generation 2-36 years Energy Transition 2-16 years Capital spares and other 2-51 years 2021 2020 2019 PP&E Impairments: Energy Transition facilities and projects (reversals) 345 79 (151) Energy Transition - Centralia mine decommissioning and restoration provision — 3 141 Changes in decommissioning and restoration provisions for retired assets (1) 32 — 2 Highvale mine 195 — — Kaybob Cogeneration Project 27 — — Wind 12 — — Hydro 5 2 — Gas 5 — — Intangible asset impairment - coal rights (2) 17 — — Assets held for sale (3) — — 15 Project development costs (4) 10 — 18 Asset impairment 648 84 25 (1) Changes related to changes in discount rates on retired assets. (2) Impaired to nil as no future coal will be extracted from this area of the mine. (3) 2019 amounts relate to trucks and associated inventory to be sold within the Energy Transition segment and accordingly, these items were impaired to net realizable value. (4) During 2021, the Company recorded an impairment 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. During 2020, the Company wrote off nil (2019 — $18 million) in project development costs related to projects that are no longer proceeding within the Corporate segment. A reconciliation of the changes in the carrying amount of PP&E is as follows: Land Renewable Gas generation (1) Energy Transition (1) Assets under Capital spares and other (2) Total Cost As at Dec. 31, 2019, as previously reported 91 3,574 1,671 7,342 228 489 13,395 Adjustments due to re-segmentation — — 2,402 (2,402) — — — As at Dec 31, 2019, adjusted 91 3,574 4,073 4,940 228 489 13,395 Additions — — — — 478 8 486 Acquisitions (Note 4) — — 1 — — — 1 Disposals (2) — — (1) — (2) (5) Impairment (Note 7) (9) (2) — (69) — (1) (81) Revisions and additions to decommissioning and restoration costs (Note 23) — 8 1 85 — — 94 Retirement of assets — (7) (47) (3) — (1) (58) Change in foreign exchange rates (1) (14) 45 (39) — 6 (3) Transfers 17 33 (138) (12) (211) (120) (431) As at Dec. 31, 2020, adjusted 96 3,592 3,935 4,901 495 379 13,398 Additions — — — — 478 2 480 Acquisitions (Note 4) — 146 — — — — 146 Disposals (1) — (2) (74) (2) — (79) Impairment (Note 7) — (15) (2) (468) (91) (13) (589) Revisions and additions to decommissioning and restoration costs (Note 23) — 129 6 — — — 135 Retirement of assets — (15) (57) (49) — — (121) Change in foreign exchange rates — 3 (25) 2 — (6) (26) Transfers 1 303 232 201 (696) 4 45 As at Dec. 31, 2021 96 4,143 4,087 4,513 184 366 13,389 Accumulated depreciation As at Dec. 31, 2019, as previously reported — 1,284 900 4,836 — 168 7,188 Adjustments due to re-segmentation — — 1,137 (1,137) — — — As at Dec 31, 2019, adjusted — 1,284 2,037 3,699 — 168 7,188 Depreciation — 141 258 304 — 14 717 Retirement of assets — (5) (43) (3) — — (51) Disposals — — — (1) — (1) (2) Change in foreign exchange rates — (4) 18 (37) — 2 (21) Transfers — — (212) (29) — (14) (255) As at Dec. 31, 2020, adjusted — 1,416 2,058 3,933 — 169 7,576 Depreciation — 154 184 264 — 12 614 Retirement of assets — (9) (55) (48) — — (112) Disposals — — (1) (72) — — (73) Change in foreign exchange rates — — (8) 2 — (1) (7) Transfers — — — 71 — — 71 As at Dec. 31, 2021 — 1,561 2,178 4,150 — 180 8,069 Carrying amount As at Dec. 31, 2019, adjusted 91 2,290 2,036 1,241 228 321 6,207 As at Dec. 31, 2020, adjusted 96 2,176 1,877 968 495 210 5,822 As at Dec. 31, 2021 96 2,582 1,909 363 184 186 5,320 (1) The gas generation and energy transition includes the previously disclosed coal generation and mining property and equipment categories. (2) Includes major spare parts and stand-by equipment available, but not in service and spare parts used for routine, preventive or planned maintenance.

Right of Use Assets (Tables)

Right of Use Assets (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2019 58 16 2 25 45 146 Additions 3 13 — — — 16 Depreciation (3) (5) (1) (9) (3) (21) 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 (Note 4) — — — — (41) (41) Transfers — — — (8) — (8) As at Dec. 31, 2021 68 20 1 6 — 95

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2019 250 378 11 149 788 Additions — — 14 — 14 Acquisition (Note 4) 37 — — — 37 Disposals — (1) — — (1) Change in foreign exchange rates (2) — — — (2) Transfers (16) 35 (22) — (3) As at Dec. 31, 2020 269 412 3 149 833 Additions — — 9 — 9 Impairment (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 Accumulated amortization As at Dec. 31, 2019 107 246 — 117 470 Amortization 15 28 — 8 51 Disposals — (1) — — (1) Transfers 1 (1) — — — As at Dec. 31, 2020 123 272 — 125 520 Amortization 17 27 — 7 51 As at Dec. 31, 2021 140 299 — 132 571 Carrying amount As at Dec. 31, 2019 143 132 11 32 318 As at Dec. 31, 2020 146 140 3 24 313 As at Dec. 31, 2021 129 123 4 — 256 Goodwill acquired through business combinations has been allocated to CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments are as follows: As at Dec. 31 2021 2020 Hydro 258 258 Wind and Solar 175 175 Energy Marketing 30 30 Total goodwill 463 463

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2019 250 378 11 149 788 Additions — — 14 — 14 Acquisition (Note 4) 37 — — — 37 Disposals — (1) — — (1) Change in foreign exchange rates (2) — — — (2) Transfers (16) 35 (22) — (3) As at Dec. 31, 2020 269 412 3 149 833 Additions — — 9 — 9 Impairment (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 Accumulated amortization As at Dec. 31, 2019 107 246 — 117 470 Amortization 15 28 — 8 51 Disposals — (1) — — (1) Transfers 1 (1) — — — As at Dec. 31, 2020 123 272 — 125 520 Amortization 17 27 — 7 51 As at Dec. 31, 2021 140 299 — 132 571 Carrying amount As at Dec. 31, 2019 143 132 11 32 318 As at Dec. 31, 2020 146 140 3 24 313 As at Dec. 31, 2021 129 123 4 — 256 Goodwill acquired through business combinations has been allocated to CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments are as follows: As at Dec. 31 2021 2020 Hydro 258 258 Wind and Solar 175 175 Energy Marketing 30 30 Total goodwill 463 463

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2021
Disclosure of financial assets [abstract]
Disclosure of components in other assets	The components of other assets are as follows: As at Dec. 31 2021 2020 South Hedland prepaid transmission access and distribution costs 65 70 Project development costs 29 25 Long-term prepaids and other assets 48 59 Loan receivable 55 52 Total other assets 197 206 Included in the Consolidated Statements of Financial Position as: Total current other assets (Note 14) 55 — Total long-term other assets 142 206 Total other assets 197 206

Decommissioning and Other Pro_2

Decommissioning and Other Provisions (Tables)	12 Months Ended
	Dec. 31, 2021
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]
Change in decommissioning and other provision balances	The change in decommissioning and other provision balances is as follows: Decommissioning and restoration Other provisions Total Balance, Dec. 31, 2019 501 45 546 Liabilities incurred 1 34 35 Liabilities settled (18) (19) (37) Accretion 30 — 30 Acquisition of liabilities 1 — 1 Revisions in estimated cash flows 61 11 72 Revisions in discount rates (1) 36 — 36 Reversals — (6) (6) Change in foreign exchange rates (4) — (4) Balance, Dec. 31, 2020 608 65 673 Liabilities incurred 8 22 30 Liabilities settled (Note 36) (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 (1) Discount rates at Dec. 31, 2020, are generally lower than those at Dec. 31, 2019, due to decreases in the underlying risk-free US and Canadian benchmark yields and changes in credit spreads due to volatility within the market as a result of COVID-19. On average, these rates decreased by approximately 0.3 to 0.9 per cent. Decommissioning and Other Total Balance, Dec. 31, 2020 608 65 673 Current portion 21 38 59 Non-current portion 587 27 614 Balance, Dec. 31, 2021 793 34 827 Current portion 35 13 48 Non-current portion 758 21 779

Credit Facilities, Long-Term _2

Credit Facilities, Long-Term Debt and Lease Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of borrowings outstanding	The amounts outstanding are as follows: As at Dec. 31 2021 2020 Segment Maturity Currency Carrying Face Interest (1) Carrying Face Interest Credit facilities Committed syndicated bank facility (2) Corporate 2025 CAD — — — % 114 114 2.7 % Debentures 7.3% Medium term notes Corporate 2029 CAD 110 110 7.3 % 109 110 7.3 % 6.9% Medium term notes Corporate 2030 CAD 141 141 6.9 % 140 141 6.9 % Senior notes (3) 6.5% Senior notes Corporate 2040 USD 378 383 6.5 % 380 383 6.5 % 4.5% Senior notes Corporate 2022 USD 510 511 4.5 % 506 511 4.5 % Non-recourse Melancthon Wolfe Wind LP Wind & Solar 2028 CAD 235 237 3.8 % 268 270 3.8 % New Richmond Wind LP Wind & Solar 2032 CAD 120 121 4.0 % 127 128 4.0 % Kent Hills Wind LP bond (4) Wind & Solar 2033 CAD 221 221 4.5 % 230 233 4.5 % Windrise Wind LP bond Wind & Solar 2041 CAD 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 102 104 4.4 % 111 113 4.5 % TEC Hedland PTY Ltd bond (5) Gas 2042 AUD 732 742 4.1 % 772 782 4.1 % TransAlta OCP LP bond Gas 2030 CAD 263 265 4.5 % 284 287 4.5 % Tax equity financing Big Level & Antrim (6) Wind & Solar 2029 USD 106 112 6.6 % 112 119 6.6 % Lakeswind (7) Wind & Solar 2029 USD 18 18 10.5 % 22 22 10.5 % North Carolina Solar (8) Wind & Solar 2028 USD 11 11 7.3 % — — — Other Corporate 2023 CAD 4 4 5.9 % 7 6 5.9 % Total long-term debt 3,167 3,198 3,227 3,264 Lease liabilities 100 134 3,267 3,361 Less: current portion of long-term debt (837) (97) Less: current portion of lease liabilities (7) (8) Total current long-term debt and lease liabilities (844) (105) Total credit facilities, long-term debt and lease liabilities 2,423 3,256 ( 1) Interest 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, 2021 — US$700 million (Dec. 31, 2020 — US$700 million). (4) Kent Hills Wind LP bond is classified as a current liability. Refer to section B - Restrictions Related to Non-Recourse Debt and Other Debt, for more information. (5) AU face value at Dec. 31, 2021 — AU$800 million related to the TEC offering (2020 — AU$800 million). (6) US face value at Dec. 31, 2021 — US$88 million (2020 — US$94 million). (7) US face value at Dec. 31, 2021 — US$14 million (2020 — US$16 million). (8) US face value at Dec. 31, 2021 — US$9 million (2020 — nil). The Company's credit facilities are summarized in the table below: As at Dec. 31, 2021 Facility Utilized Available Maturity Outstanding letters of credit (1) Actual drawings TransAlta Corporation Committed syndicated bank facility (2) 1,250 618 — 632 Q2 2025 Canadian committed bilateral credit facilities 240 186 — 54 Q2 2023 TransAlta Renewables Committed credit facility (2) 700 98 — 602 Q2 2025 Total 2,190 902 — 1,288 (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. At Dec. 31, 2021, TransAlta provided cash collateral of $55 million. (2) Includes letters of credit issued under the demand facilities for TransAlta and TransAlta Renewables.
Disclosure of principal repayments	2022 (1) 2023 2024 2025 2026 2027 and thereafter Total Principal repayments (2) 836 155 113 127 127 1,840 3,198 Lease liabilities (3) (6) 4 3 3 3 93 100 (1) Includes the Kent Hills Wind LP non-recourse bonds. The successful receipt of waivers and amendments would extend principal repayments beyond 2022. (2) Excludes impact of hedge accounting and derivatives. (3) Lease liabilities include a lease incentive of $13 million, expected to be received in 2022.

Exchangeable Securities (Tables

Exchangeable Securities (Tables)	12 Months Ended
	Dec. 31, 2021
Exchangeable Securities [Abstract]
Disclosure of borrowing costs	750 million Exchangeable Securities As at Dec. 31, 2021 Dec. 31, 2020 Carrying value Face value Interest Carrying value Face value Interest Exchangeable debentures – due May 1, 2039 335 350 7 % 330 350 7 % Exchangeable preferred shares (1) 400 400 7 % 400 400 7 % Total long-term debt 735 750 730 750 (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, 2021 Dec. 31, 2020 Description Base fair value Sensitivity Base fair value Sensitivity Option to exchange – embedded derivative — +nil -32 — +nil -33

Defined Benefit Obligation an_2

Defined Benefit Obligation and Other Long-Term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Subclassifications of assets, liabilities and equities [abstract]
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 2021 2020 Defined benefit obligation (Note 31) 228 282 Long-term incentive accruals (Note 30) 4 4 Other 21 12 Total 253 298

Common Shares (Tables)

Common Shares (Tables)	12 Months Ended
	Dec. 31, 2021
Share Capital, Reserves And Other Equity Interest [Abstract]
Issued and outstanding	TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value. As at Dec. 31 2021 2020 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 269.8 2,896 277.0 2,978 Purchased and cancelled under the NCIB — — (7.3) (79) Effects of share-based payment plans — (3) — (3) Stock options exercised 1.2 8 0.1 — Issued and outstanding, end of year 271.0 2,901 269.8 2,896 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 2021 2020 Total shares purchased (1) — 7,352,600 Average purchase price per share — $8.33 Total cost — 61 Weighted average book value of shares cancelled — 79 Amount recorded in deficit — 18 (1) As at Dec. 31, 2021, includes nil (2020 — 456,200) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. 2021 On May 25, 2021, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement an NCIB for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2021 and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election. No common shares have been repurchased under the current and previous NCIB in 2021. 2020 On May 26, 2020, 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, the Company was permitted to purchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its issued and common shares as at May 25, 2020. All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares. As at Dec. 31 2021 2020 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 10.2 248 Series B 2.4 58 1.8 45 Series C 11.0 269 11.0 269 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
Earnings per share	Year ended Dec. 31 2021 2020 2019 Net earnings (loss) attributable to common shareholders (576) (336) 52 Basic and diluted weighted average number of common shares outstanding (millions) 271 275 283 Net earnings (loss) per share attributable to common shareholders, basic and diluted (2.13) (1.22) 0.18

Preferred Shares (Tables)

Preferred Shares (Tables)	12 Months Ended
	Dec. 31, 2021
Share Capital, Reserves And Other Equity Interest [Abstract]
Issued and outstanding	TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value. As at Dec. 31 2021 2020 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 269.8 2,896 277.0 2,978 Purchased and cancelled under the NCIB — — (7.3) (79) Effects of share-based payment plans — (3) — (3) Stock options exercised 1.2 8 0.1 — Issued and outstanding, end of year 271.0 2,901 269.8 2,896 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 2021 2020 Total shares purchased (1) — 7,352,600 Average purchase price per share — $8.33 Total cost — 61 Weighted average book value of shares cancelled — 79 Amount recorded in deficit — 18 (1) As at Dec. 31, 2021, includes nil (2020 — 456,200) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. 2021 On May 25, 2021, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement an NCIB for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2021 and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election. No common shares have been repurchased under the current and previous NCIB in 2021. 2020 On May 26, 2020, 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, the Company was permitted to purchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its issued and common shares as at May 25, 2020. All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares. As at Dec. 31 2021 2020 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 10.2 248 Series B 2.4 58 1.8 45 Series C 11.0 269 11.0 269 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
Characteristics specific to preferred share series	Characteristics specific to each first preferred share series as at Dec. 31, 2021, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over benchmark (per cent) Convertible to A Fixed 0.71924 March 31, 2026 2.03 B B Floating 0.53866 March 31, 2026 2.03 A C Fixed 1.00676 June 30, 2022 3.10 D D Floating — — 3.10 C E Fixed 1.29852 Sept. 30, 2022 3.65 F F Floating — — 3.65 E G Fixed 1.24700 Sept. 30, 2024 3.80 H H Floating — — 3.80 G
Disclosure Of Dividends Declared On Preference Shares [Table Text Block]	The following table summarizes the value of the preferred share dividends declared in 2021 and 2020: Total dividends declared Series 2021 (1) 2020 A 7 9 B (2) 1 1 C 11 14 E 12 15 G 8 10 Total for the year 39 49 (1) No dividends were declared in the first quarter of 2021 as the quarterly dividend related to the period covering the first quarter of 2021 was declared in December 2020.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Earnings (Tables)	12 Months Ended
	Dec. 31, 2021
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 earnings are as follows: 2021 2020 Currency translation adjustment Opening balance, Jan. 1 (21) (21) Losses on translating net assets of foreign operations, net of reclassifications to net earnings, (14) (11) Gains on financial instruments designated as hedges of foreign operations, net of reclassifications to net earnings, net of tax — 11 Balance, Dec. 31 (35) (21) Cash flow hedges Opening balance, Jan. 1 436 527 Losses on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax (1) (208) (91) Balance, Dec. 31 228 436 Employee future benefits Opening balance, Jan. 1 (66) (55) Net actuarial gains (losses) on defined benefit plans, net of tax (2) 37 (11) Balance, Dec. 31 (29) (66) Other Opening balance, Jan. 1 (47) 3 Intercompany investments at FVOCI 29 (50) Balance, Dec. 31 (18) (47) Accumulated other comprehensive earnings 146 302 (1) Net of income tax of $57 million for the year ended Dec. 31, 2021 (2020 — $23 million). (2) Net of income tax of $11 million for the year ended Dec. 31, 2021 (2020 — $3 million).

Share-Based Payment Plans (Tabl

Share-Based Payment Plans (Tables)	12 Months Ended
	Dec. 31, 2021
Share-based payment arrangements [Abstract]
Disclosure of range of exercise prices of outstanding share options	The total options outstanding and exercisable under these stock option plans at Dec. 31, 2021, 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 - 9.00 3.2 4.2 7.54
Disclosure of number and weighted average remaining contractual life of outstanding share options	The total options outstanding and exercisable under these stock option plans at Dec. 31, 2021, 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 - 9.00 3.2 4.2 7.54 (1) Options currently exercisable as at Dec. 31, 2021.

Employee Future Benefits (Table

Employee Future Benefits (Tables)	12 Months Ended
	Dec. 31, 2021
Employee Benefits [Abstract]
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, 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 Year ended Dec. 31, 2019 Registered Supplemental Other Total Current service cost 7 2 1 10 Administration expenses 2 — — 2 Interest cost on defined benefit obligation 19 3 1 23 Interest on plan assets (12) (1) — (13) Curtailment and amendment gain (3) — — (3) Defined benefit expense 13 4 2 19 Defined contribution expense 9 — — 9 Net expense 22 4 2 28 The expected employer contributions for 2022 for the defined benefit pension and other post-employment benefit plans are as follows: Registered Supplemental Other Total Expected employer contributions 5 6 2 13
Defined Benefit Obligation	The status of the defined benefit pension and other post-employment benefit plans is as follows: 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) Year ended Dec. 31, 2020 Registered Supplemental Other Total Fair value of plan assets 367 14 — 381 Present value of defined benefit obligation (542) (109) (24) (675) Funded status – plan deficit (175) (95) (24) (294) Amount recognized in the consolidated financial statements: Accrued current liabilities (5) (5) (2) (12) Other long-term liabilities (170) (90) (22) (282) Total amount recognized (175) (95) (24) (294) 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, 2019 543 99 22 664 Current service cost 5 2 1 8 Interest cost 16 3 1 20 Benefits paid (45) (5) (1) (51) Curtailment (2) — — (2) Actuarial loss arising from financial assumptions 43 10 2 55 Actuarial gain arising from experience adjustments (17) — — (17) Effect of translation on US plans (1) — (1) (2) 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
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, 2019 373 13 — 386 Interest on plan assets 11 1 — 12 Net return on plan assets 25 (1) — 24 Contributions 6 6 1 13 Benefits paid (45) (5) (1) (51) Administration expenses (1) — — (1) Effect of translation on US plans (2) — — (2) As at Dec. 31, 2020 367 14 — 381 Interest on plan assets 8 — — 8 Net return 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 The fair value of the Company’s defined benefit plan assets by major category is as follows: Year ended 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 Year ended Dec. 31, 2020 Level I Level II Level III Total Equity securities Canadian — 64 — 64 US — 30 — 30 International — 103 — 103 Private — — 1 1 Bonds AAA — 36 — 36 AA — 67 — 67 A — 34 — 34 BBB 1 22 — 23 Below BBB — 4 — 4 Money market and cash and cash equivalents — 19 — 19 Total 1 379 1 381
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: As at Dec. 31, 2021 As at Dec. 31, 2020 (per cent) Registered Supplemental Other Registered Supplemental Other Accrued benefit obligation 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 (1)(3) — — 6.8 — — 6.8 Dental-care cost escalation — — 4.0 — — 4.0 Benefit cost for the year Discount rate 2.4 2.3 2.3 3.0 3.0 3.0 Rate of compensation increase 2.9 3.0 — 2.9 3.0 — Assumed health-care cost trend rate Health-care cost escalation (2)(4) — — 7.1 — — 7.1 Dental-care cost escalation — — 4.0 — — 4.0 (1) 2021 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2030 for Canada. (2) 2021 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2030 for Canada. (3) 2020 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2030 for Canada. (4) 2020 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2030 for Canada.
Schedule 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, 2021 Registered Supplemental Other Pension Other 1% decrease in the discount rate 61 15 2 3 1 1% increase in the salary scale 3 — — — — 1% increase in the health-care cost trend rate — — 2 — — 10% improvement in mortality rates 20 4 — 1 —

Joint Arrangements (Tables)

Joint Arrangements (Tables)	12 Months Ended
	Dec. 31, 2021
Disclosure of interests in other entities [Abstract]
Disclosure of interests in joint arrangements	Joint arrangements at Dec. 31, 2021, 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 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, 2021
Disclosure of cash flow statement [Abstract]
Disclosure of non-cash operating working capital	Year ended Dec. 31 2021 2020 2019 (Use) source: Accounts receivable (28) (79) 261 Prepaid expenses 9 2 — Income taxes receivable — (4) (6) Inventory 42 6 (13) Accounts payable, accrued liabilities and provisions 153 160 (130) Income taxes payable (2) 4 9 Change in non-cash operating working capital 174 89 121
Cash flows from (used in) operating activities	Balance Dec. 31, 2020 Cash issuances Repayments and dividends paid New leases Dividends declared Foreign exchange impact Other Balance Dec. 31, 2021 Long-term debt and lease 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 Balance Dec. 31, 2019 Cash issuances Repayments and dividends paid New leases Dividends declared Foreign exchange impact Other Balance Long-term debt and lease 3,212 753 (620) 16 — 5 (5) 3,361 Exchangeable securities 326 400 — — — — 4 730 Dividends payable (common and preferred) 37 — (86) — 107 — 1 59 Total liabilities from financing activities 3,575 1,153 (706) 16 107 5 — 4,150

Capital (Tables)

Capital (Tables)	12 Months Ended
	Dec. 31, 2021
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 2021 2020 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 269.8 2,896 277.0 2,978 Purchased and cancelled under the NCIB — — (7.3) (79) Effects of share-based payment plans — (3) — (3) Stock options exercised 1.2 8 0.1 — Issued and outstanding, end of year 271.0 2,901 269.8 2,896 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 2021 2020 Total shares purchased (1) — 7,352,600 Average purchase price per share — $8.33 Total cost — 61 Weighted average book value of shares cancelled — 79 Amount recorded in deficit — 18 (1) As at Dec. 31, 2021, includes nil (2020 — 456,200) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. 2021 On May 25, 2021, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement an NCIB for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2021 and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election. No common shares have been repurchased under the current and previous NCIB in 2021. 2020 On May 26, 2020, 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, the Company was permitted to purchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its issued and common shares as at May 25, 2020. C. Shareholder Rights Plan The Company initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 26, 2019, to reflect current market practice and to reflect changes to the take-over bid regime. 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 26, 2019, and will need to be approved at the annual meeting of shareholders in 2022. 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 shareholder 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 2021 2020 2019 Net earnings (loss) attributable to common shareholders (576) (336) 52 Basic and diluted weighted average number of common shares outstanding (millions) 271 275 283 Net earnings (loss) per share attributable to common shareholders, basic and diluted (2.13) (1.22) 0.18 E. Dividends On Dec. 13, 2021, the Company declared a quarterly dividend of $0.05 per common share, payable on April 1, 2022. 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 2021 2020 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 9.6 235 10.2 248 Series B 2.4 58 1.8 45 Series C 11.0 269 11.0 269 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 I. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On March 18, 2021, the Company announced that 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") were tendered for conversion, on a one-for-one basis, into Series B Shares and Series A Shares, respectively after having taken into account all election notices. As a result of the conversion, the Company had 9.6 million Series A Shares and 2.4 million Series B Shares issued and outstanding at March 31, 2021. II. Preferred Share Series Information The holders are entitled to receive cumulative fixed quarterly cash dividends at a specified rate, 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 $25.00 per share, plus all declared and unpaid dividends at the time of redemption. ▪ Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Company and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2021, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over benchmark (per cent) Convertible to A Fixed 0.71924 March 31, 2026 2.03 B B Floating 0.53866 March 31, 2026 2.03 A C Fixed 1.00676 June 30, 2022 3.10 D D Floating — — 3.10 C E Fixed 1.29852 Sept. 30, 2022 3.65 F F Floating — — 3.65 E G Fixed 1.24700 Sept. 30, 2024 3.80 H H Floating — — 3.80 G B. Dividends The following table summarizes the value of the preferred share dividends declared in 2021 and 2020: Total dividends declared Series 2021 (1) 2020 A 7 9 B (2) 1 1 C 11 14 E 12 15 G 8 10 Total for the year 39 49 (1) No dividends were declared in the first quarter of 2021 as the quarterly dividend related to the period covering the first quarter of 2021 was declared in December 2020. (2) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.03 per cent. On Dec. 13, 2021, the Company declared a quarterly dividend of $0.1798 per share on the Series A preferred shares, $0.1331 per share on the Series B preferred shares, $0.2517 per share on the Series C preferred shares, $0.3246 per share on the Series E preferred shares, and $0.3118 per share on the Series G preferred shares, all payable on March 31, 2022. TransAlta’s capital is comprised of the following: As at Dec. 31 2021 2020 Increase/ Long-term debt (1) 3,267 3,361 (94) Exchangeable securities 735 730 5 Equity Common shares 2,901 2,896 5 Preferred shares 942 942 — Contributed surplus 46 38 8 Deficit (2,453) (1,826) (627) Accumulated other comprehensive earnings 146 302 (156) Non-controlling interests 1,011 1,084 (73) Less: available cash and cash equivalents (2) (947) (703) (244) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (17) (11) (6) Less: fair value asset of hedging instruments on long-term debt (4) (2) (2) — Total capital 5,629 6,811 (1,182) (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 because 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, 2021 and 2020, 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 is available to fund operations, pay dividends, distribute payments to subsidiaries' non-controlling interests and invest in PP&E. Year ended Dec. 31 2021 2020 Increase Cash flow from operating activities 1,001 702 299 Change in non-cash working capital (174) (89) (85) Cash flow from operations before changes in working capital 827 613 214 Dividends paid on common shares (48) (47) (1) Dividends paid on preferred shares (39) (39) — Distributions paid to subsidiaries’ non-controlling interests (156) (97) (59) Property, plant and equipment expenditures (480) (486) 6 Inflow (outflow) 104 (56) 160

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2021
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 the 167 MW Kent Hills wind facility located in New Brunswick. Year ended Dec. 31 2021 2020 2019 Revenues 470 436 446 Net earnings 139 97 183 Total comprehensive earnings 66 223 138 Amounts attributable to the non-controlling interests: Net earnings 50 40 73 Total comprehensive earnings 21 90 56 Distributions paid to non-controlling interests 100 80 69 As at Dec. 31 2021 2020 Current assets 430 743 Long-term assets 3,319 2,913 Current liabilities (593) (364) Long-term liabilities (1,033) (987) Total equity (2,123) (2,305) Equity attributable to non-controlling interests (869) (948) Non-controlling interests’ share (per cent) 39.9 39.9 In 2020, the Company's ownership per cent decreased from 60.4 per cent in 2019 to 60.1 per cent due to TransAlta Renewables issuing approximately 1 million common shares under their Dividend Reinvestment Plan ("DRIP"). The Company did not participate in this plan. In the fourth quarter of 2020, TransAlta Renewables suspended the DRIP in respect of any future declared dividends. B. TA Cogen Year ended Dec. 31 2021 2020 2019 Results of operations Revenues 265 146 181 Net earnings (loss) 103 (13) 43 Total comprehensive earnings (loss) 103 (13) 43 Amounts attributable to the non-controlling interest: Net earnings (loss) 62 (6) 21 Total comprehensive earnings (loss) 62 (6) 21 Distributions paid to Canadian Power Holdings Inc. 56 17 37 As at Dec. 31 2021 2020 Current assets 66 69 Long-term assets 312 323 Current liabilities (52) (78) Long-term liabilities (36) (37) Total equity (290) (277) Equity attributable to Canadian Power Holdings Inc. (142) (136) Non-controlling interest share (per cent) 49.99 49.99 Details of the Company’s principal operating subsidiaries at Dec. 31, 2021, 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	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 2021 2020 2019 Total compensation 30 27 30 Comprised of: Short-term employee benefits 14 12 13 Post-employment benefits 1 2 2 Termination benefits — — 2 Share-based payments 15 13 13

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
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: 2022 2023 2024 2025 2026 2027 and thereafter Total Natural gas, transportation and 47 54 45 44 45 508 743 Transmission 9 9 6 6 2 — 32 Coal supply and mining agreements 1 76 98 90 75 — — 339 Long-term service agreements 89 46 43 32 25 54 289 Operating leases 4 3 3 1 1 31 43 Growth 941 276 — — — — 1,217 TransAlta Energy Transition Bill 6 6 — — — — 12 Total 1,172 492 187 158 73 593 2,675 (1) Relates to coal supply and mining agreements for Centralia Unit 2.

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2021
Disclosure of operating segments [abstract]
Disclosure of operating segments	Year ended Dec. 31, 2021 Hydro Wind & Solar (1) Gas (2) Energy Transition (3) Energy Corporate Total Equity 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 (gain) loss — 25 (40) 19 (38) — (34) — 34 — Decrease in finance lease receivable — — 41 — — — 41 — (41) — Finance lease income — — 25 — — — 25 — (25) — Unrealized foreign exchange gain on commodity — — (3) — — — (3) — 3 — Adjusted revenues 383 348 1,132 728 173 4 2,768 (18) (29) 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 power 16 17 374 432 — 4 843 — 211 1,054 Carbon compliance (4) — — 118 60 — — 178 — — 178 Gross margin 367 331 640 236 173 — 1,747 (18) (240) 1,489 OM&A 42 59 175 117 36 84 513 (2) — 511 Reclassifications and adjustments: Parts and materials write-down — — (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 taxes 3 10 13 6 — 1 33 (1) — 32 Net other operating expense (income) — — (40) 48 — — 8 — — 8 Reclassifications and adjustments: Royalty onerous contract and contract termination penalties — — — (48) — — (48) — 48 — Adjusted net other operating income — — (40) — — — (40) — 48 8 Adjusted EBITDA 322 262 494 133 137 (85) 1,263 Equity income from associate 9 Finance lease income 25 Depreciation and amortization (529) Asset impairment (648) Net interest expense (6) (245) Foreign exchange gain 16 Gain on sale of assets and other 54 Loss before income taxes (380) (1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. (2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal. (4) As of the first quarter of 2021, carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes. (5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. (6) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings. Year ended Dec. 31, 2020 Hydro Wind & Solar (1) Gas (2) Energy Transition (3) 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 (gain) loss — 2 33 (14) 21 — 42 — (42) — Decrease in finance lease receivable — — 17 — — — 17 — (17) — Finance lease income — — 7 — — — 7 — (7) — Unrealized foreign exchange loss on commodity — — 4 — — — 4 — (4) — Adjusted revenues 152 334 848 690 143 7 2,174 (3) (70) 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 8 25 221 352 — 12 618 — 187 805 Carbon compliance (4) — — 120 48 — (5) 163 — — 163 Gross margin 144 309 507 290 143 — 1,393 (3) (257) 1,133 OM&A 37 53 166 106 30 80 472 — — 472 Taxes, other than income taxes 2 8 13 9 — 1 33 — — 33 Net other operating expense (income) — — (11) — — — (11) — — (11) Reclassifications and adjustments: Impact of Sheerness going off-coal — — (28) — — — (28) — 28 — Adjusted net other operating income (39) — — — (39) — 28 (11) Adjusted EBITDA (5) 105 248 367 175 113 (81) 927 Equity income from associate 1 Finance lease income 7 Depreciation and amortization (654) Asset impairment (84) Net interest expense( 6) (238) Foreign exchange loss 17 Gain on sale of assets and other 9 Loss before income taxes (303) (1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. (2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal. (4) As of the first quarter of 2021, carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes. (5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. (6) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings. Year ended Dec. 31, 2019 Hydro Wind & Solar Gas (1) Energy Transition (2) Energy Corporate Total Reclass adjustments IFRS financials Revenues 156 312 851 905 129 (6) 2,347 — 2,347 Reclassifications and adjustments: Unrealized mark-to-market (gain) loss — (17) 6 (12) (10) — (33) 33 — Decrease in finance lease receivable — — 24 — — — 24 (24) — Finance lease income — — 6 — — — 6 (6) — Adjusted revenues 156 295 887 893 119 (6) 2,344 3 2,347 Fuel and purchased power 7 16 315 539 — 4 881 — 881 Reclassifications and adjustments: Australian interest income — — (4) — — — (4) 4 — Mine depreciation — — (81) (40) — — (121) 121 — Adjusted fuel and purchased power 7 16 230 499 — 4 756 125 881 Carbon compliance — — 138 77 — (10) 205 — 205 Gross margin 149 279 519 317 119 — 1,383 (122) 1,261 OM&A 36 50 162 124 30 73 475 — 475 Taxes, other than income taxes 3 8 9 8 — 1 29 — 29 Net other operating expense (income) — (10) (41) — — 2 (49) — (49) Termination of Sundance B and C PPAs — — (14) (42) — — (56) — (56) Adjusted EBITDA (3) 110 231 403 227 89 (76) 984 Finance lease income 6 Depreciation and amortization (590) Asset impairment (25) Gain on termination of Keephills 3 coal rights contract 88 Net interest expense (4) (179) Foreign exchange loss (15) Gain on sale of assets and other 46 Earnings before income taxes 193 (1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal. (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, 2021 Hydro Wind Gas (1) Energy Transition (2) 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 As at Dec. 31, 2020 Hydro Wind Gas (1) Energy Transition (2) Energy Corporate Total PP&E 467 2,005 2,102 1,232 — 16 5,822 Right-of-use assets 6 55 5 53 — 22 141 Intangible assets 4 159 66 36 7 41 313 Goodwill 258 175 — — 30 — 463 (1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.
Disclosure of components in other non-current assets	Additions to non-current assets are as follows: Year ended Dec. 31, 2021 Hydro Wind Gas (1) Energy Transition (2) 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 (1) Energy Transition (2) Energy Corporate Total Additions to non-current assets: PP&E 22 174 199 78 — 13 486 Intangible assets — — — 1 — 13 14 Year ended Dec. 31, 2019 Hydro Wind Gas (1) Energy Transition (2) Energy Corporate Total Additions to non-current assets: PP&E 23 229 74 90 — 1 417 Intangible assets — — — 2 — 12 14 (1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. (2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.
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 2021 2020 2019 Depreciation and amortization expense on the Consolidated Statements of 529 654 590 Depreciation included in fuel, carbon compliance and purchased power (Note 6) 190 144 119 Depreciation and amortization on the Consolidated Statements of Cash Flows 719 798 709
Disclosure of geographical areas	Revenues Year ended Dec. 31 2021 2020 2019 Canada 1,854 1,227 1,460 US 731 716 727 Australia 136 158 160 Total revenue 2,721 2,101 2,347 II. Non-Current Assets Property, plant and Right-of-use assets Intangible assets Other assets As at Dec. 31 2021 2020 2021 2020 2021 2020 2021 2020 Canada 4,051 4,661 52 107 141 185 15 74 US 860 737 39 30 85 94 61 61 Australia 409 424 4 4 30 34 66 71 Total 5,320 5,822 95 141 256 313 142 206

Corporate Information (Details)

Corporate Information (Details) - segment	Dec. 31, 2021	Dec. 31, 2020
Disclosure of operating segments [line items]
Number of segments	6
Generation Segments
Disclosure of operating segments [line items]
Number of segments	4	6

Material Accounting Policies (D

Material Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2021
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	51 years
Wind 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 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	36 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	2 years
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	16 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	51 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	30 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	60 years
Software | Minimum
Disclosure of detailed information about intangible assets [line items]
Useful life measured as period of time, intangible assets other than goodwill	2 years
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	19 years

Accounting Changes - Narrative

Accounting Changes - Narrative (Details) - Interest rate swap - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure of changes in accounting estimates [line items]
Notional amount	$ 150
Interest rate risk
Disclosure of changes in accounting estimates [line items]
Notional amount	$ 150	$ 150

Business Acquisitions and Div_3

Business Acquisitions and Divestitures - Narrative (Details) $ in Millions, $ in Millions	Nov. 05, 2021CAD ($)MW	Nov. 05, 2021USD ($)	Jun. 30, 2021CAD ($)	Feb. 26, 2021CAD ($)	May 19, 2020USD ($)MW	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Investment [Line Items]
Revenue of combined entity as if combination occurred at beginning of period						$ 16
Profit (loss) of combined entity as if combination occurred at beginning of period						9
Cash flows used in obtaining control of subsidiaries or other businesses, classified as investing activities						120	$ 32	$ 117
Proceeds on sale of Pioneer Pipeline						128	0	0
Gain on sale of assets and other (Note 4 and 18)						$ 54	$ 9	$ 46
TransAlta Renewables Inc.
Investment [Line Items]
Consideration received				$ (213)
North Carolina Solar
Investment [Line Items]
Capacity of facility (in megawatts) | MW	122,000,000
Cash transferred	$ 99
Remaining amortisation period of intangible assets material to entity	12 years	12 years
Consideration received	$ 123
Percentage of voting equity interests acquired	100.00%
North Carolina Solar | Entities with joint control or significant influence over entity [member]
Investment [Line Items]
Consideration received		$ 102
Pipeline
Investment [Line Items]
Consideration received			$ 255
Proceeds on sale of Pioneer Pipeline			128
Non-current assets or disposal groups classified as held for sale			97
Gain on sale of assets and other (Note 4 and 18)			31
Decrease through derecognition, financial assets			41
Decrease through derecognition, financial liabilities			43
Gains (losses) on available-for-sale financial assets			$ 2
Percentage of voting equity interests acquired			50.00%
Contracted Cogeneration Asset in Michigan
Investment [Line Items]
Capacity of facility (in megawatts) | MW					29
Cash flows used in obtaining control of subsidiaries or other businesses, classified as investing activities					$ 27
Long-term PPA and steam sale agreement, term					6 years
North Carolina Solar | TransAlta Renewables Inc.
Investment [Line Items]
Percentage of voting equity interests acquired	100.00%

Business Acquisitions and Div_4

Business Acquisitions and Divestitures - Fair values of the identifiable assets and liabilities of the acquired entity in the business combination (Details) - CAD ($) $ in Millions	Nov. 05, 2021	May 19, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of detailed information about business combination [line items]
Right-of-use assets			$ 95	$ 141	$ 146
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
Aggregate value of business combination	120
Working capital consideration	3
Consideration received	$ 123
Ada Facility
Disclosure of detailed information about business combination [line items]
Cash and cash equivalents		$ 1
Accounts receivable		3
Property, plant and equipment		1
Intangible assets		37
Inventory recognised as of acquisition date		1
Prepaid Expense Recognised As Of Acquisition Date		1
Current Derivative Financial Liabilities Recognised As Of Acquisition Date		(5)
Decommissioning provisions		(1)
Net assets acquired		38
Aggregate value of business combination		32
Working capital consideration		6
Consideration received		$ 38

Revenue (Details)

Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of disaggregation of revenue from contracts with customers [line items]
Changes in transaction price	$ 11	$ 0
Performance obligations satisfied	1	$ 2
Canadian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	31
Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	2,500
Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	336
Hydro
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	46
Wind and Solar
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	9
Second to fifth years inclusive | Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	285
Minimum | Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	85
Minimum | 2024 | Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	5
Minimum | Annually thereafter | Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	40
Maximum | Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	145
Maximum | 2024 | Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	10
Maximum | Annually thereafter | Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	$ 45

Revenue Disaggregation of Reven

Revenue Disaggregation of Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	$ 2,721	$ 2,101	$ 2,347
At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	53	58	78
Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	629	965	990
Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	682	1,023	1,068
Contract With Customers, Power And Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	654	1,000	1,045
Contract With Customers, Environmental Credits
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	28	23	23
Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	19	123	130
Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	210	407	296
Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	1,810	548	853
Hydro | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	383	152	156
Hydro | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Hydro | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	28	141	142
Hydro | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	28	141	142
Hydro | Operating segments | Contract With Customers, Power And Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	28	141	142
Hydro | Operating segments | Contract With Customers, Environmental Credits
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Hydro | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Hydro | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Hydro | Operating segments | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	355	11	14
Wind and Solar | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	305	329	312
Wind and Solar | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	28	25	27
Wind and Solar | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	207	236	217
Wind and Solar | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	235	261	244
Wind and Solar | Operating segments | Contract With Customers, Power And Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	207	238	221
Wind and Solar | Operating segments | Contract With Customers, Environmental Credits
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	28	23	23
Wind and Solar | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Wind and Solar | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	(25)	(2)	18
Wind and Solar | Operating segments | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	95	70	50
Gas | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	1,109	787	851
Gas | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	2	7	5
Gas | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	393	458	492
Gas | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	395	465	497
Gas | Operating segments | Contract With Customers, Power And Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	395	465	497
Gas | Operating segments | Contract With Customers, Environmental Credits
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Gas | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	19	123	130
Gas | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	(118)	(8)	(15)
Gas | Operating segments | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	813	207	239
Energy Transition | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	709	704	905
Energy Transition | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	23	26	46
Energy Transition | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	1	130	139
Energy Transition | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	24	156	185
Energy Transition | Operating segments | Contract With Customers, Power And Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	24	156	185
Energy Transition | Operating segments | Contract With Customers, Environmental Credits
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Energy Transition | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Energy Transition | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	138	283	160
Energy Transition | Operating segments | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	547	265	560
Energy Marketing | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	211	122	129
Energy Marketing | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Energy Marketing | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Energy Marketing | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Energy Marketing | Operating segments | Contract With Customers, Power And Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Energy Marketing | Operating segments | Contract With Customers, Environmental Credits
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Energy Marketing | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Energy Marketing | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	211	122	129
Energy Marketing | Operating segments | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Corporate and Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	4	7	(6)
Corporate and Other | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Corporate and Other | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Corporate and Other | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Corporate and Other | Contract With Customers, Power And Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Corporate and Other | Contract With Customers, Environmental Credits
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Corporate and Other | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Corporate and Other | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	4	12	4
Corporate and Other | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	$ 0	$ (5)	$ (10)

Revenue Contract Balances (Deta

Revenue Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Changes in Contract Liabilities [Roll Forward]
Increases due to amounts billed to customers	$ 0	$ 2
Changes in transaction price	11	0
Performance obligations satisfied	(1)	(2)
Current contract liabilities	19	1
Non-current contract liabilities	13	14
IFRS 16
Changes in Contract Liabilities [Roll Forward]
Contract liabilities at beginning of period	15	15
Amounts transferred to revenue included in opening balance	(1)	(1)
Consideration received	8	1
Contract liabilities at end of period	$ 32	$ 15

Expenses by Nature - Expenses C

Expenses by Nature - Expenses Classified by Nature (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of products and services [line items]
Mine depreciation	$ 190	$ 144	$ 119
Salaries and benefits	14	24	28
Total	511	472
Adjustments for impairment loss (reversal of impairment loss) recognised in profit or loss, inventories	17	15
Write-downs	28	0
Coal
Disclosure of products and services [line items]
Write-downs	65	37
Fuel and purchased power
Disclosure of products and services [line items]
Gas fuel costs	306	159	133
Coal fuel costs	164	269	310
Royalty, land lease, other direct costs	19	20	21
Purchased power	339	163	246
Mine depreciation	190	144	119
Salaries and benefits	36	50	52
Other expenses	0	0	0
Total	1,054	805	881
Fuel and purchased power | Coal
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	234	235	228
Other expenses	277	237	247
Total	511	$ 472	$ 475
Write-downs	$ 28

Asset Impairment - Detailed inf

Asset Impairment - Detailed information about property, plant, and equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	$ 345	$ 79
Impairment reversal			$ (151)
Asset impairment charge	648	84	25
Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	0	0	15
Decommissioning and restoration
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	32	0	2
Wind
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	12	0	0
Hydro
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	5	2	0
Gas
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	5	0	0
Coal Rights
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	17	0	0
Project Development Costs
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	10	0	18
Write-downs (reversals of write-downs) of property, plant and equipment	1	0	18
Project Development Costs | Hydro generation
Disclosure of detailed information about property, plant and equipment [line items]
Write-downs (reversals of write-downs) of property, plant and equipment	9
Centralia Mine | Decommissioning and restoration
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	0	3	141
Highvale Mine | Mining assets
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	195	0	0
Kaybob Cogeneration Project
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	$ 27	$ 0	$ 0

Asset Impairment (Details)

Asset Impairment (Details) $ in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2021CAD ($)	Dec. 31, 2021CAD ($)MW	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Oct. 01, 2019MW
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charge		$ 648	$ 84		$ 25
Estimated salvage value		33
Impairment charges		345	79
Provision for decommissioning, restoration and rehabilitation costs	$ 120
Assets		9,226	9,747
Gross carrying amount
Disclosure of impairment loss recognised or reversed [line items]
Write-downs (reversals of write-downs) of property, plant and equipment		$ 589	$ 81
Discount rate, measurement input
Disclosure of impairment loss recognised or reversed [line items]
Significant unobservable input, assets		5,000,000	5,300,000
Assets Held for Sale
Disclosure of impairment loss recognised or reversed [line items]
Estimated salvage value		$ 25
Impairment charges		0	$ 0		15
Energy Transition
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charge		191
Keephills Unit 1 | Energy Transition
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charge		94
Sundance Unit 4 | Energy Transition
Disclosure of impairment loss recognised or reversed [line items]
Asset impairment charge		56
Centralia Thermal Facility
Disclosure of impairment loss recognised or reversed [line items]
Provision for decommissioning, restoration and rehabilitation costs					141
Reversal of impairment loss					151
Wind Facilities
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges	$ 10
Wind Facilities | Level III | Investment property [member] | Non-recurring fair value measurement [member]
Disclosure of impairment loss recognised or reversed [line items]
Assets		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
Property, plant and equipment | Sundance Unit 3
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss			70
Land
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss			9	$ 7
Land | Gross carrying amount
Disclosure of impairment loss recognised or reversed [line items]
Write-downs (reversals of write-downs) of property, plant and equipment		$ 0	9
Kaybob Cogeneration Project
Disclosure of impairment loss recognised or reversed [line items]
Capacity of facility (in megawatts) | MW						40
Mining assets | Highvale Mine
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges		$ 195	$ 0		$ 0

Finance Lease Receivables (Deta

Finance Lease Receivables (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure of recognised finance lease as assets by lessee [line items]
Undiscounted finance lease payments to be received	$ 265	$ 332
Undiscounted finance lease payments to be received, at present value	225	264
Less: unearned finance lease income	40	68
Less: unearned finance lease income, present value	0	0
Total finance lease receivables	225	264
Current finance lease receivables	40	36
Long-term portion of finance lease receivable	185	228
BHP Billiton Nickel West Pty Ltd. | Southern Cross Energy
Disclosure of recognised finance lease as assets by lessee [line items]
Total finance lease receivables		89
2022
Disclosure of recognised finance lease as assets by lessee [line items]
Undiscounted finance lease payments to be received	58	63
Undiscounted finance lease payments to be received, at present value	54	56
Second to fifth years inclusive
Disclosure of recognised finance lease as assets by lessee [line items]
Undiscounted finance lease payments to be received	127	169
Undiscounted finance lease payments to be received, at present value	105	126
More than five years
Disclosure of recognised finance lease as assets by lessee [line items]
Undiscounted finance lease payments to be received	80	100
Undiscounted finance lease payments to be received, at present value	$ 66	$ 82

Net Other Operating Expense (_3

Net Other Operating Expense (Income) - Disclosure of components of net other operating (income) losses (Details) - CAD ($) $ in Millions	Jul. 20, 2018	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Analysis of income and expense [abstract]
Alberta Off-Coal Agreement	$ (40)	$ (40)	$ (40)	$ (40)
Supplier settlements		34	0	0
Onerous contract provisions		14	29	0
Other trading income (expense)		0	0	(9)
Net other operating loss (income)		$ 8	$ (11)	(49)
Insurance recoveries				$ 10

Net Other Operating Expense (_4

Net Other Operating Expense (Income) (Details) $ in Millions, $ in Millions	Jul. 20, 2018CAD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2021USD ($)
Analysis of income and expenses [Line Items]
Alberta Off-Coal Agreement	$ (40)	$ (40)	$ (40)	$ (40)
Alberta off-coal agreement, annual cash payments, net		37
Other operating income (expense)		8	(11)	(49)
Onerous contract provisions		14	29	$ 0
Onerous contracts provision			$ 29
Sundance Unit 5
Analysis of income and expenses [Line Items]
Net deferred tax assets		$ 10			$ 8

Investments - Change in investm

Investments - Change in investments (Details) $ in Millions, $ in Millions	Nov. 30, 2020USD ($)	Nov. 25, 2020CAD ($)	Nov. 25, 2020USD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Change In Investments [Roll Forward]
Equity income				$ 9	$ 1	$ 0
Change in foreign exchange rates				16	17	(15)
Consolidated structured entities [member]
Change In Investments [Roll Forward]
Beginning balance				100	0
Contributions					102
Equity income				9	1
Dividends received from investments accounted for using equity method, classified as investing activities				(4)
Change in foreign exchange rates					(3)
Ending balance				105	100	0
Skookumchuck
Change In Investments [Roll Forward]
Contributions		$ 86	$ 66
EMG International, LLC
Change In Investments [Roll Forward]
Contributions	$ 12
SP Skookumchuck Investment, LLC
Change In Investments [Roll Forward]
Beginning balance				85	0
Contributions					86
Equity income				12	1
Dividends received from investments accounted for using equity method, classified as investing activities				(4)
Change in foreign exchange rates					(2)
Ending balance				93	85	0
EMG International, LLC
Change In Investments [Roll Forward]
Beginning balance				15	0
Contributions					16
Equity income				(3)	0
Dividends received from investments accounted for using equity method, classified as investing activities				0
Change in foreign exchange rates					(1)
Ending balance				$ 12	$ 15	$ 0

Investments - Narrative (Detail

Investments - Narrative (Details) $ in Millions, $ in Millions	Nov. 30, 2020USD ($)	Nov. 25, 2020CAD ($)MW	Nov. 25, 2020USD ($)MW	Dec. 31, 2020CAD ($)	Dec. 31, 2021CAD ($)	May 25, 2021	May 26, 2020
Investment [Line Items]
Percentage of public float of common shares making up stock purchase agreement, shares authorized						7.16%	7.02%
Finance lease receivables				$ (264)	$ (225)
BHP Billiton Nickel West Pty Ltd. | Southern Cross Energy
Investment [Line Items]
Gain (loss) of derecognised financial assets at date of transfer				77
Finance lease receivables				(89)
Gains (losses) on disposals of non-current assets				$ (12)
EMG International, LLC
Investment [Line Items]
Other cash payments to acquire interests in joint ventures, classified as investing activities	$ 12
Proportion of ownership interest in subsidiary	30.00%
Skookumchuck
Investment [Line Items]
Other cash payments to acquire interests in joint ventures, classified as investing activities		$ 86	$ 66
Capacity of facility (in megawatts) | MW		136.8	136.8
Proportion of ownership interest in subsidiary		49.00%	49.00%

Investments - Results of operat

Investments - Results of operations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of subsidiaries [line items]
Revenues	$ 2,721	$ 2,101	$ 2,347
Equity income (Note 10)	9	1	$ 0
Consolidated structured entities [member]
Disclosure of subsidiaries [line items]
Revenues	19	3
Operating expense	(10)	(2)
Equity income (Note 10)	$ 9	$ 1

Investments - Summarized financ

Investments - Summarized financial information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of subsidiaries [line items]
Revenues	$ 2,721	$ 2,101	$ 2,347
Depreciation and amortization	529	654	590
Net interest expense	(245)	(238)	(179)
Net earnings (loss)	(425)	(253)	176
Other comprehensive income	(185)	(102)	(45)
Total comprehensive earnings (loss)	(610)	(355)	131
Current liabilities	(1,931)	(935)
Assets	9,226	9,747
Cash and cash equivalents	$ 947	$ 703	$ 411	$ 89

Investments - Summarized Intere

Investments - Summarized Interest (Details) $ in Millions	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Nov. 25, 2020MW	Dec. 31, 2019CAD ($)
Disclosure of subsidiaries [line items]
Assets	$ 9,226	$ 9,747
Non-controlling interests	1,011	1,084
Skookumchuck
Disclosure of subsidiaries [line items]
Capacity of facility (in megawatts) | MW			136.8
SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Investments in associates accounted for using equity method	$ 93	$ 85		$ 0

Investments - Future payments u

Investments - Future payments under contractual commitments (Details) $ in Millions	Dec. 31, 2021CAD ($)
Disclosure of subsidiaries [line items]
Long-term service agreements	$ 289
2022
Disclosure of subsidiaries [line items]
Long-term service agreements	89
2023
Disclosure of subsidiaries [line items]
Long-term service agreements	46
2024
Disclosure of subsidiaries [line items]
Long-term service agreements	43
2025
Disclosure of subsidiaries [line items]
Long-term service agreements	32
2026
Disclosure of subsidiaries [line items]
Long-term service agreements	25
2027
Disclosure of subsidiaries [line items]
Long-term service agreements	$ 54

Net Interest Expense (Details)

Net Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Analysis of income and expenses [Line Items]
Interest on debt	$ 163	$ 158	$ 161
Interest on exchangeable securities	29	29	20
Interest on exchangeable preferred shares	28	5	0
Interest income	(11)	(10)	(13)
Capitalized interest	(14)	(8)	(6)
Interest expense on lease liabilities	7	8	4
Credit facility fees, bank charges and other interest	18	18	15
Tax shield on tax equity financing	(9)	1	(35)
Interest on Line Loss Rule Proceeding	0	5	0
Other	2	2	10
Accretion of provisions	32	30	23
Net interest expense	245	238	179
IFRS 15
Analysis of income and expenses [Line Items]
Net interest expense	$ 0	$ 0	$ (5)

Income Taxes - Rate Reconciliat

Income Taxes - Rate Reconciliations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Abstract]
Earnings (loss) before income taxes	$ (380)	$ (303)	$ 193
Net earnings (loss) attributable to non-controlling interests not subject to tax	(33)	2	(26)
Adjusted earnings (loss) before income taxes	$ (413)	$ (301)	$ 167
Statutory Canadian federal and provincial income tax rate	23.60%	24.50%	26.50%
Expected income tax expense (recovery)	$ (98)	$ (74)	$ 44
Increase (decrease) in income taxes resulting from:
Differences in effective foreign tax rates	4	3	5
Deferred income tax expense related to temporary difference on investment in subsidiaries	0	9	0
Write-down (reversal of write-down) of unrecognized deferred income tax assets	134	8	(9)
Statutory and other rate differences	4	(7)	(31)
Other	1	11	8
Income tax expense (recovery)	$ 45	$ (50)	$ 17
Effective tax rate	(11.00%)	17.00%	10.00%

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disposal Groups, Including Discontinued Operations [Line Items]
Current income tax expense	$ 56	$ 35	$ 35
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences	(145)	(95)	22
Deferred income tax expense related to temporary difference on investment in subsidiary	0	9	0
Deferred income tax expense resulting from changes in tax rates or laws expense (recovery)	0	(7)	(31)
Write-down (reversal of write-down) of unrecognized deferred income tax assets	134	8	(9)
Current income tax expense	56	35	35
Deferred income tax recovery	(11)	(85)	(18)
Income tax expense (recovery)	$ 45	$ (50)	$ 17

Income Taxes - Aggregate Curren

Income Taxes - Aggregate Current and Deferred Income Tax Charged to Equity (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Abstract]
Net impact related to cash flow hedges	$ (57)	$ (23)	$ 6
Net actuarial gains (losses)	11	(3)	(7)
Income tax recovery reported in equity	$ (46)	$ (26)	$ (1)

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Income Tax Assets (Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Unrecognized deferred income tax assets	$ (64)	$ (51)
Net deferred tax liabilities	(290)	(345)
Gross carrying amount | Net operating loss carryforwards
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	530	469
Gross carrying amount | Future decommissioning and restoration costs
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	183	140
Gross carrying amount | Property, plant and equipment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	(651)	(717)
Gross carrying amount | Risk management assets and liabilities, net
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	(53)	(107)
Gross carrying amount | Employee future benefits and compensation plans
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	53	62
Gross carrying amount | Interest deductible in future periods
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	17	22
Gross carrying amount | Foreign exchange differences on US-denominated debt
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	16	31
Gross carrying amount | Other deductible temporary differences
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	(5)	2
Accumulated impairment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	90	(98)
Unrecognized deferred income tax assets	$ (380)	$ (247)

Income Taxes - Deferred Income

Income Taxes - Deferred Income Tax Liability Presentation (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Abstract]
Deferred income tax assets	$ 64	$ 51
Deferred tax liabilities	(354)	(396)
Net deferred tax liabilities	$ (290)	$ (345)

Income Taxes - Contingencies (D

Income Taxes - Contingencies (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Maximum
Disclosure of contingent liabilities [line items]
Tax expense, reassessed tax liability	$ 57
Minimum
Disclosure of contingent liabilities [line items]
Tax expense, reassessed tax liability	0
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) shares in Millions	12 Months Ended
	Dec. 31, 2021MWshares	Dec. 31, 2020	Dec. 31, 2019
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	49.99%	49.99%
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	39.90%	39.90%
Proportion of ownership interest in subsidiary	60.10%		60.40%
Number of shares issued | shares	1
Kent Hills wind farm | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	17.00%
Capacity of facility (in megawatts) | MW	167

Non-Controlling Interests - Sha

Non-Controlling Interests - Share of Ownership and Equity Participation in TransAlta Renewables (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	49.99%	49.99%
TransAlta Cogeneration, L.P. | TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	49.99%
Kent Hills wind farm | TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	17.00%
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	39.90%	39.90%

Non-Controlling Interests - Ear

Non-Controlling Interests - Earnings of Subsidiaries with Non-Controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of subsidiaries [line items]
Revenues	$ 2,721	$ 2,101	$ 2,347
Net earnings (loss)	(425)	(253)	176
Total comprehensive earnings (loss)	(610)	(355)	131
Amounts attributable to the non-controlling interests:
Net earnings (loss)	112	34	94
Total comprehensive earnings (loss)	83	84	77
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Revenues	470	436	446
Net earnings (loss)	139	97	183
Total comprehensive earnings (loss)	66	223	138
Amounts attributable to the non-controlling interests:
Net earnings (loss)	50	40	73
Total comprehensive earnings (loss)	21	90	56
Distributions paid to Canadian Power Holdings Inc.	100	80	69
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Revenues	265	146	181
Net earnings (loss)	103	(13)	43
Total comprehensive earnings (loss)	103	(13)	43
Amounts attributable to the non-controlling interests:
Net earnings (loss)	62	(6)	21
Total comprehensive earnings (loss)	62	(6)	21
Distributions paid to Canadian Power Holdings Inc.	$ 56	$ 17	$ 37

Non-Controlling Interests - Fin

Non-Controlling Interests - Financial Position of Non-Controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of subsidiaries [line items]
Current assets	$ 2,197	$ 1,902
Current liabilities	(1,931)	(935)
Total equity	2,593	3,436	$ 4,062
Non-controlling interests	1,011	1,084
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Current assets	430	743
Long-term assets	3,319	2,913
Current liabilities	(593)	(364)
Long-term liabilities	(1,033)	(987)
Total equity	(2,123)	(2,305)
Non-controlling interests	$ (869)	$ (948)
Ownership and voting rights percentage	39.90%	39.90%
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Current assets	$ 66	$ 69
Long-term assets	312	323
Current liabilities	(52)	(78)
Long-term liabilities	(36)	(37)
Total equity	(290)	(277)
Non-controlling interests	$ (142)	$ (136)
Ownership and voting rights percentage	49.99%	49.99%
TransAlta Cogeneration, L.P. | TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Ownership and voting rights percentage	49.99%

Non-Controlling Interests - Nar

Non-Controlling Interests - Narrative (Details)	12 Months Ended
	Dec. 31, 2021
Coal facility | TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Proportion of ownership interests held by non-controlling interests	50.00%

Trade and Other Receivables (De

Trade and Other Receivables (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Subclassifications of assets, liabilities and equities [abstract]
Trade accounts receivable	$ 499	$ 488
Current non-cash assets pledged as collateral for which transferee has right by contract or custom to sell or repledge collateral	55	49
Current portion of finance lease receivables	40	36
Current portion of loan receivable (Note 20)	55	0
Income taxes receivable	2	10
Trade and other receivables	$ 651	$ 583

Financial Instruments - Carryin

Financial Instruments - Carrying amounts and classifications of financial assets and liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about financial instruments [line items]
Cash equivalents	$ 0	$ 0
Financial liabilities	3,267	3,361
Accounts payable and accrued liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	689	599
Accounts payable and accrued liabilities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	689	599
Dividends payable
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	62	59
Dividends payable | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	62	59
Credit facilities, long-term debt and lease liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,267	3,361
Credit facilities, long-term debt and lease liabilities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,267	3,361
Exchangeable securities (Note 25)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	735	730
Exchangeable securities (Note 25) | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	735	730
Within one year | Risk management liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	261	94
Within one year | Derivatives | Risk management liabilities | Hedging Liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	0	10
Within one year | Derivatives | Risk management liabilities | Trading securities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	261	84
Later than one year | Risk management liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	145	68
Later than one year | Derivatives | Risk management liabilities | Hedging Liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	0	0
Later than one year | Derivatives | Risk management liabilities | Trading securities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	145	68
Cash and cash equivalents
Disclosure of detailed information about financial instruments [line items]
Financial assets	947	703
Cash and cash equivalents | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	947	703
Restricted cash
Disclosure of detailed information about financial instruments [line items]
Financial assets	70	71
Restricted cash | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	70	71
Trade and other receivables
Disclosure of detailed information about financial instruments [line items]
Financial assets	651	583
Trade and other receivables | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	651	583
Long-term portion of finance lease receivable
Disclosure of detailed information about financial instruments [line items]
Financial assets	185	228
Long-term portion of finance lease receivable | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	185	228
Risk management assets | Within one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	308	171
Risk management assets | Later than one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	399	521
Risk management assets | Hedging Asset | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	36	102
Risk management assets | Hedging Asset | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	252	471
Risk management assets | Trading securities | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	272	69
Risk management assets | Trading securities | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	$ 147	50
Other assets
Disclosure of detailed information about financial instruments [line items]
Financial assets		52
Other assets | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets		$ 52

Financial Instruments - Sensiti

Financial Instruments - Sensitivity ranges for the base fair values (Details)	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)
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		$ 1
Fixed-price contracts | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh				1
Forward contract | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh				6
Increase (decrease) in derivative future power prices, reasonable possible		(6)
Minimum | Long-term power sale – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ (5,000,000)
Minimum | Long-term power sale – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	145,000,000		$ 59,000,000
Increase (decrease) in derivative future power prices, reasonable possible		(3)		$ 3
Minimum | Coal transportation – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 18,000,000
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		$ (3)
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 | Historical volatility for shares, measurement input [member]
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	0.80	0.80
Minimum | Full requirements – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 9,000,000
Minimum | Full requirements – Eastern US | US | Volume Rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	0.95	0.95		0.95
Minimum | Long-term wind energy sale – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 16,000,000
Minimum | Long-term wind energy sale – Eastern US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments			22,000,000
Minimum | Long-term wind energy sale – Canada
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 11,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	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	$ 0.24
Minimum | Long-term wind energy sale - Central US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 15,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	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 ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 6,000,000		$ 5,000,000
Minimum | Coal transportation – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity analysis in derivative, basis relationship, percent			80.00%	80.00%
Sensitivity analysis in derivative, non-standard shape factors, percent			0.00%	0.00%
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
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments			$ 3,000,000
Maximum | Long-term power sale – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	22,000,000		35,000,000
Increase (decrease) in derivative future power prices, reasonable possible		20		$ 5
Maximum | Coal transportation – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 3,000,000
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		$ 20
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	0.04	0.04
Maximum | Coal transportation – US | Long-term contracts | US | Historical volatility for shares, measurement input [member]
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	1.20	1.20
Maximum | Full requirements – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 9,000,000		3,000,000
Maximum | Full requirements – Eastern US | US | Volume Rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in significant unobservable inputs, derivative asset	1.05	1.05		1.05
Maximum | Long-term wind energy sale – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 17,000,000
Maximum | Long-term wind energy sale – Eastern US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments			22,000,000
Maximum | Long-term wind energy sale – Canada
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 21,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	5.00%	5.00%
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	$ (0.05)
Maximum | Long-term wind energy sale - Central US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 27,000,000
Increase (decrease) in monthly wind discounts expressed as a percentage	3.00%	3.00%
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		$ (3)
Maximum | Others
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption increase (decrease), financial instruments	$ 6,000,000		$ 5,000,000
Maximum | Coal transportation – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity analysis in derivative, basis relationship, percent			120.00%	120.00%
Sensitivity analysis in derivative, non-standard shape factors, percent			4.00%	4.00%
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 (Details)

Financial Instruments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2021CAD ($)MW	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)
Disclosure of detailed information about financial instruments [line items]
Risk management assets		$ 171	$ 308
Financial liabilities		$ 3,361	$ 3,267
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
Long-term wind energy sale – Canada
Disclosure of detailed information about financial instruments [line items]
Percentage of voting equity interests acquired			49.00%
Long-term wind energy sale – Canada | Pembina
Disclosure of detailed information about financial instruments [line items]
Percentage of voting equity interests acquired			37.70%
Long-term wind energy sale - Central US
Disclosure of detailed information about financial instruments [line items]
Percentage of voting equity interests acquired			100.00%
Fixed-price contracts | Minimum
Disclosure of detailed information about financial instruments [line items]
Long-term fixed price power sale contract, delivery volume | MW			300
Fixed-price contracts | Maximum
Disclosure of detailed information about financial instruments [line items]
Long-term fixed price power sale contract, delivery volume | MW			380
Coal transportation – US | Minimum
Disclosure of detailed information about financial instruments [line items]
Sensitivity analysis in derivative, basis relationship, percent		80.00%
Sensitivity analysis in derivative, non-standard shape factors, percent		0.00%
Coal transportation – US | Maximum
Disclosure of detailed information about financial instruments [line items]
Sensitivity analysis in derivative, basis relationship, percent		120.00%
Sensitivity analysis in derivative, non-standard shape factors, percent		4.00%
Level III | Long-term contracts | Fixed-price contracts
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh				$ 1
Level III | Long-term contracts | Fixed-price contracts | Minimum
Disclosure of detailed information about financial instruments [line items]
Increase (decrease) in derivative forward power prices, reasonable possible	$ 3
Level III | Long-term contracts | Fixed-price contracts | Maximum
Disclosure of detailed information about financial instruments [line items]
Increase (decrease) in derivative forward power prices, reasonable possible	(2)
Level III | Long-term contracts | Forward contract
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh				$ 6
Increase (decrease) in derivative forward power prices, reasonable possible	$ (6)
Recurring fair value measurement | Level I
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		$ (13)	$ 12
Recurring fair value measurement | Level III
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		582	159		$ 686
Recurring fair value measurement | Level III | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of detailed information about financial instruments [line items]
Financial liabilities		33	146
Recurring fair value measurement | Level III | Financial assets at fair value through profit or loss, category [member]
Disclosure of detailed information about financial instruments [line items]
Financial assets		$ 615	$ 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of risk management strategy related to hedge accounting [line items]
Change in foreign exchange rates	$ 16	$ 17	$ (15)
Losses recognized in other comprehensive earnings	(8)	(141)	(53)
Gains (losses) on cash flow hedges, before tax	(255)	28	77
Other
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic		(12)
Commodity risk management
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic		542
Recurring fair value measurement | Level I
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	12	(13)
Recurring fair value measurement | Level II
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	122	(27)
Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	159	582	686
Market price changes	(112)	(81)
Change in foreign exchange rates	0	(15)
Recurring fair value measurement | Level III | Other
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	8	(12)
Non-recurring fair value measurement [member] | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Losses recognized in other comprehensive earnings	(181)	(34)
Gains (losses) on cash flow hedges, before tax	(23)	82
Unrealized gains included in earnings before income taxes relating to met assets held	(135)	1
Fair value hedges [member] | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	285	573	678
Market price changes	(107)	(71)
Change in foreign exchange rates	0	(16)
Fair value hedges [member] | Non-recurring fair value measurement [member] | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Losses recognized in other comprehensive earnings	(181)	(34)
Gains (losses) on cash flow hedges, before tax	107	71
Unrealized gains included in earnings before income taxes relating to met assets held	0	0
Non-Hedges | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	(126)	9	$ 8
Market price changes	(5)	(10)
Change in foreign exchange rates	0	1
Non-Hedges | Non-recurring fair value measurement [member] | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Losses recognized in other comprehensive earnings	0	0
Gains (losses) on cash flow hedges, before tax	(130)	11
Unrealized gains included in earnings before income taxes relating to met assets held	(135)	1
Derivative Instruments, Existing Contracts [Member] | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(177)	(15)
Derivative Instruments, Existing Contracts [Member] | Fair value hedges [member] | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(181)	(18)
Derivative Instruments, Existing Contracts [Member] | Non-Hedges | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	4	3
Derivative Instruments, New Contracts [Member] | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	(134)	7
Derivative Instruments, New Contracts [Member] | Fair value hedges [member] | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	0	0
Derivative Instruments, New Contracts [Member] | Non-Hedges | Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Market price changes	$ (134)	$ 7

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, 2021	Dec. 31, 2020
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	$ 3,267	$ 3,361
Long-term debt
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,167	3,227
Exchangeable securities (Note 25)
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	735	730
Recurring fair value measurement | Long-term debt | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,272	3,480
Recurring fair value measurement | Exchangeable securities (Note 25) | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	770	769
Recurring fair value measurement | Level I | Long-term debt | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	0	0
Recurring fair value measurement | Level I | Exchangeable securities (Note 25) | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	0	0
Recurring fair value measurement | Level II | Long-term debt | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,272	3,480
Recurring fair value measurement | Level II | Exchangeable securities (Note 25) | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	770	769
Recurring fair value measurement | Level III | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	146	33
Recurring fair value measurement | Level III | Long-term debt | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	0	0
Recurring fair value measurement | Level III | Exchangeable securities (Note 25) | Financial liabilities at fair value through profit or loss, category [member]
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, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ (33)	$ 9	$ 49
New inception gains (losses)	(50)	(13)	3
Amortization recorded in net earnings during the year	(19)	(29)	(43)
Unamortized net gain (loss) at end of year	$ (102)	$ (33)	$ 9

Risk Management Activities - Ad

Risk Management Activities - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Disclosure of nature and extent of risks arising from financial instruments [line items]
Current non-cash assets pledged as collateral for which transferee has right by contract or custom to sell or repledge collateral	$ 55,000,000	$ 49,000,000
Financial assets pledged as collateral for liabilities or contingent liabilities	18,000,000	0
Derivative, contingent feature, additional collateral requirement	120,000,000	$ 85,000,000
Asset-backed debt instruments held	515,000,000
Debt instruments held	$ 1,000,000,000
Borrowings subject to floating interest rates	3.00%	7.00%		3.00%	7.00%
Sensitivity analysis used by management for the foreign exchange differences from functional currency	$ 0.03	$ 0.03	$ 0.03
Borrowings	$ 3,267,000,000	3,361,000,000
Target percentage of hedged forecasted foreign operating cash flows over four year period	60.00%
Target percentage of hedged forecasted foreign operating cash flows, current period	90.00%
Target percentage of hedged forecasted foreign operating cash flows, next year	70.00%
Target percentage of hedged forecasted foreign operating cash flows, third year	50.00%
Target percentage of hedged forecasted foreign operating cash flows, fourth year	30.00%
Maximum exposure to credit risk	$ 37,000,000	22,000,000
Other comprehensive income that will be reclassified to profit or loss, net of tax	(222,000,000)	(90,000,000)	(19,000,000)
Gains (losses) on change in fair value of derivatives	97,000,000	43,000,000	33,000,000
Gains on change in fair value of derivatives	6,000,000	11,000,000	24,000,000
Unrealised loss on change in fair value of derivatives		2,000,000
Unrealised gains on change in fair value of derivatives	4,000,000		6,000,000
Net realized gains on change in fair value of derivatives	2,000,000	13,000,000	18,000,000
Unrealized pre-tax gains (losses)	(1,000,000)	1,000,000	1,000,000
Within one year
Disclosure of nature and extent of risks arising from financial instruments [line items]
Other comprehensive income that will be reclassified to profit or loss, net of tax	$ 25,000,000
Long-term debt | Net investment hedges
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount				$ 370	$ 370
Forward contract
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount		$ 150,000,000		400
Bond, forward yield		1.20%
Interest rate swap
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount				150
Bond Lock Agreement [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount		$ 75,000,000		150
Bond, interest rate	1.375%	5.75%
Commodity Price Risk - Proprietary Trading [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	$ 2,000,000	$ 1,000,000	1,000,000
Commodity Price Risk - Generation [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	33,000,000	12,000,000	25,000,000
Commodity Price Risk - Generation - Mark To Market Value [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	$ 51,000,000	$ 15,000,000	$ 8,000,000
Interest rate risk | Interest rate swap
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount				150	$ 150
Borrowings				$ 400
Interest rate risk | Interest rate swap | Fixed interest rate [member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Derivate, fixed interest rate	0.94%	0.94%
Letter of credit
Disclosure of nature and extent of risks arising from financial instruments [line items]
Collateral posted on derivative liabilities	$ 356,000,000	$ 163,000,000

Risk Management Activities - Ne

Risk Management Activities - Net Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		$ 542
Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(12)
Current | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	$ 45	90
Current | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	2	(13)
Long-term | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	248	452
Long-term | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	6	1
Financial Assets
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	301	530
Financial Assets | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	293
Financial Assets | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	8
Designated as a hedge | Cash flow hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		572
Designated as a hedge | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(9)
Designated as a hedge | Current | Cash flow hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	33	101
Designated as a hedge | Current | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	3	(9)
Designated as a hedge | Long-term | Cash flow hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	252	471
Designated as a hedge | Long-term | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	0	0
Designated as a hedge | Financial Assets | Cash flow hedges
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	288	563
Designated as a hedge | Financial Assets | Cash flow hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	285
Designated as a hedge | Financial Assets | Cash flow hedges | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	3
Not designated as a hedge | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	13
Not designated as a hedge | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(30)
Not designated as a hedge | Commodity risk management | Long-term
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	(4)	(19)
Not designated as a hedge | Commodity risk management | Current
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	12
Not designated as a hedge | Commodity risk management | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	8
Not designated as a hedge | Other | Long-term
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		1
Not designated as a hedge | Other | Current
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(4)
Not designated as a hedge | Other | Financial Liabilities
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(3)
Not designated as a hedge | Current | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(11)
Not designated as a hedge | Current | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	(1)
Not designated as a hedge | Long-term | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	6
Not designated as a hedge | Financial Assets
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		$ (33)
Not designated as a hedge | Financial Assets | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	$ 5

Risk Management Activities - _2

Risk Management Activities - Netting Arrangements (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current
Disclosure of offsetting of financial assets [line items]
Gross financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	$ (306)	$ (132)
Gross financial assets set off against financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	138	69
Net financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	(168)	(63)
Long-term
Disclosure of offsetting of financial assets [line items]
Gross financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	(122)	(104)
Gross financial assets set off against financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	54	10
Net financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	(68)	(94)
Current
Disclosure of offsetting of financial assets [line items]
Gross financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	394	120
Gross financial liabilities set off against financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	(137)	(69)
Net financial assets subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	257	51
Long-term
Disclosure of offsetting of financial assets [line items]
Gross financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	330	69
Gross financial liabilities set off against financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	(53)	(10)
Net financial assets subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	$ 277	$ 59

Risk Management Activities - Ou

Risk Management Activities - Outstanding commodity derivative instruments designated as hedging instruments (Details) - Commodity risk management	Dec. 31, 2021MWht	Dec. 31, 2020MWht
Electricity | Cash flow hedges
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	0	95,000
Notional amount purchased	0	0
Electricity | Non-Hedges
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	46,139,000	12,944,000
Notional amount purchased	14,951,000	8,258,000
Emissions | Non-Hedges
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	445,000	1,831,000
Notional amount purchased	2,030,000	2,112,000
Notional amount purchased | t	350,000	2,365,000
Notional amount sold | t	350,000	2,160,000
Coal | Non-Hedges
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount purchased | t	9,352,000	9,078,000
Notional amount sold | t	0	0

Risk Management Activities - Co

Risk Management Activities - Commodity derivative instruments not designated as hedging instruments (Details) - Non-Hedges - Commodity risk management	Dec. 31, 2021MWhJt	Dec. 31, 2020MWhJt
Electricity
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	46,139,000	12,944,000
Notional amount purchased	14,951,000	8,258,000
Natural gas
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold | J	7,501,000	23,035,000
Notional amount purchased | J	173,898,000	177,448,000
Transmission
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	37,000	0
Notional amount purchased	1,097,000	1,578,000
Emissions
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	445,000	1,831,000
Notional amount purchased	2,030,000	2,112,000
Notional amount sold | t	350,000	2,160,000
Notional amount purchased | t	350,000	2,365,000

Risk Management Activities - Ca

Risk Management Activities - Cash Flow Hedges (Details) - Foreign exchange forward contracts – foreign-denominated receipts/expenditures - Cash flow hedges - Currency risk $ in Millions, $ in Millions, $ in Millions	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2021AUD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold				$ 71
Derivative, notional amount purchased					$ 54
Financial assets, at fair value				$ (2)
Within one year
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	$ 10		$ 19
Financial liabilities, at fair value	$ 0
Within one year | Minimum
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Derivative, notional amount purchased		$ 8
Within one year | Maximum
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Derivative, notional amount purchased		$ 14

Risk Management Activities - No

Risk Management Activities - Non-Hedges (Details) € in Millions, $ in Millions, $ in Millions, $ in Millions	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2021AUD ($)	Dec. 31, 2021EUR (€)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2020AUD ($)	Dec. 31, 2020EUR (€)
Disclosure of detailed information about hedges [line items]
Hedging instrument, assets	$ 2				$ 2
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]
Hedging instrument, liabilities	(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]
Hedging instrument, assets	8
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022, Contract One
Disclosure of detailed information about hedges [line items]
Hedging instrument, assets
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022, Contract Two
Disclosure of detailed information about hedges [line items]
Hedging instrument, assets
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021-2024, Contract One
Disclosure of detailed information about hedges [line items]
Hedging instrument, liabilities					(14)
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021-2024, Contract Two
Disclosure of detailed information about hedges [line items]
Hedging instrument, assets					9
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021, Contract One
Disclosure of detailed information about hedges [line items]
Hedging instrument, assets					0
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021, Contract Two
Disclosure of detailed information about hedges [line items]
Hedging instrument, assets					0
Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2022
Disclosure of detailed information about hedges [line items]
Hedging instrument, assets	1				2
Australia, 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 sold			$ 28
Australia, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount sold
Australia, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021-2024, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount sold							$ 197
Australia, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount sold							$ 4
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]
Derivative, 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]
Derivative, notional amount purchased	357
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount sold
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021-2024, Contract One
Disclosure of detailed information about hedges [line items]
Derivative, notional amount purchased					181
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021-2024, Contract Two
Disclosure of detailed information about hedges [line items]
Derivative, notional amount purchased					72
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount sold					1
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	$ 191				$ 191
U.S. 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 sold		$ 271
U.S. Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022, Contract One
Disclosure of detailed information about hedges [line items]
Derivative, notional amount purchased
U.S. Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021-2024, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount sold						$ 47
U.S. Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021, Contract One
Disclosure of detailed information about hedges [line items]
Derivative, notional amount purchased						3
U.S. Dollars | Foreign exchange forward contracts – foreign-denominated debt | Discontinued Hedge Positions | Currency risk | Maturity, 2022
Disclosure of detailed information about hedges [line items]
Derivative, notional amount purchased		$ 150				$ 150
Euro Member Countries, Euro | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2022, Contract Two
Disclosure of detailed information about hedges [line items]
Derivative, notional amount purchased | €
Euro Member Countries, Euro | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2021, Contract Two
Disclosure of detailed information about hedges [line items]
Derivative, notional amount purchased | €								€ 1

Risk Management Activities - Im

Risk Management Activities - Impacts of currency rate risk (Details) - Currency risk - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of credit risk exposure [line items]
Sensitivity analysis, Net earnings increase (decrease)	$ (12)	$ (12)	$ (24)
Sensitivity analysis, OCI gain	1	1	2
U.S. Dollars
Disclosure of credit risk exposure [line items]
Sensitivity analysis, Net earnings increase (decrease)	(13)	(8)	(18)
Sensitivity analysis, OCI gain	1	1	2
Australia, Dollars
Disclosure of credit risk exposure [line items]
Sensitivity analysis, Net earnings increase (decrease)	1	(4)	(6)
Sensitivity analysis, OCI gain	$ 0	$ 0	$ 0

Risk Management Activities - Ma

Risk Management Activities - Maximum exposure to credit risk (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure of credit risk exposure [line items]
Maximum exposure to credit risk	$ 37	$ 22
Credit risk
Disclosure of credit risk exposure [line items]
Maximum exposure to credit risk	1,543
Credit risk | Trade and other receivables
Disclosure of credit risk exposure [line items]
Maximum exposure to credit risk	$ 651
Trade and other receivables | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Trade and other receivables | Investment Grade | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	89.00%
Trade and other receivables | Non-Investment Grade | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	11.00%
Long-term portion of finance lease receivable | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Maximum exposure to credit risk	$ 185
Long-term portion of finance lease receivable | Investment Grade | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Long-term portion of finance lease receivable | Non-Investment Grade | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	0.00%
Risk management assets | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Maximum exposure to credit risk	$ 707
Risk management assets | Investment Grade | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	86.00%
Risk management assets | Non-Investment Grade | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	14.00%

Risk Management Activities - _3

Risk Management Activities - Maturity Analysis of Financial Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	$ 689	$ 599
Borrowings	3,267	3,361
Exchangeable securities	735	730
Dividends payable	62	59
Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	4	$ 7
2022
Disclosure of maturity analysis for derivative financial liabilities [line items]
Lease commitments for short-term leases for which recognition exemption has been used	13
Gross carrying amount
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	689
Borrowings	3,198
Exchangeable securities	750
Derivative financial assets	8
Lease liabilities	100
Interest expense on borrowings	1,384
Dividends payable	62
Liabilities	6,050
Gross carrying amount | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	251
Gross carrying amount | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	894
Gross carrying amount | Non-Recourse - Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	45
Gross carrying amount | Non-Recourse - Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	752
Gross carrying amount | Non-Recourse - Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	1,111
Gross carrying amount | Tax Equity Financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	141
Gross carrying amount | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	4
Gross carrying amount | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	168
Gross carrying amount | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	(293)
Gross carrying amount | 2022
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	689
Borrowings	836
Exchangeable securities	0
Derivative financial assets	2
Lease liabilities	(6)
Interest expense on borrowings	149
Dividends payable	62
Liabilities	1,736
Gross carrying amount | 2022 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2022 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	511
Gross carrying amount | 2022 | Non-Recourse - Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2022 | Non-Recourse - Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	263
Gross carrying amount | 2022 | Non-Recourse - Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	44
Gross carrying amount | 2022 | Tax Equity Financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	15
Gross carrying amount | 2022 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	3
Gross carrying amount | 2022 | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	53
Gross carrying amount | 2022 | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	(45)
Gross carrying amount | 2023
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	155
Exchangeable securities	0
Derivative financial assets	3
Lease liabilities	4
Interest expense on borrowings	120
Dividends payable	0
Liabilities	294
Gross carrying amount | 2023 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2023 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2023 | Non-Recourse - Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	45
Gross carrying amount | 2023 | Non-Recourse - Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	49
Gross carrying amount | 2023 | Non-Recourse - Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	45
Gross carrying amount | 2023 | Tax Equity Financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	15
Gross carrying amount | 2023 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	1
Gross carrying amount | 2023 | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	53
Gross carrying amount | 2023 | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	(35)
Gross carrying amount | 2024
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	113
Exchangeable securities	0
Derivative financial assets	3
Lease liabilities	3
Interest expense on borrowings	115
Dividends payable	0
Liabilities	173
Gross carrying amount | 2024 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2024 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2024 | Non-Recourse - Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2024 | Non-Recourse - Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	52
Gross carrying amount | 2024 | Non-Recourse - Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	47
Gross carrying amount | 2024 | Tax Equity Financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	14
Gross carrying amount | 2024 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2024 | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	62
Gross carrying amount | 2024 | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	(117)
Gross carrying amount | 2025
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	127
Exchangeable securities	750
Derivative financial liabilities	1
Lease liabilities	3
Interest expense on borrowings	109
Dividends payable	0
Liabilities	895
Gross carrying amount | 2025 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2025 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2025 | Non-Recourse - Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2025 | Non-Recourse - Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	54
Gross carrying amount | 2025 | Non-Recourse - Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	59
Gross carrying amount | 2025 | Tax Equity Financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	14
Gross carrying amount | 2025 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2025 | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	0
Gross carrying amount | 2025 | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	(95)
Gross carrying amount | 2026
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	127
Exchangeable securities	0
Derivative financial assets	0
Lease liabilities	3
Interest expense on borrowings	104
Dividends payable	0
Liabilities	235
Gross carrying amount | 2026 | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2026 | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2026 | Non-Recourse - Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2026 | Non-Recourse - Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	51
Gross carrying amount | 2026 | Non-Recourse - Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	61
Gross carrying amount | 2026 | Tax Equity Financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	15
Gross carrying amount | 2026 | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | 2026 | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	0
Gross carrying amount | 2026 | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial assets	(1)
Gross carrying amount | More than five years
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	1,840
Exchangeable securities	0
Derivative financial assets	1
Lease liabilities	93
Interest expense on borrowings	787
Dividends payable	0
Liabilities	2,717
Gross carrying amount | More than five years | Debentures
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	251
Gross carrying amount | More than five years | Senior notes
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	383
Gross carrying amount | More than five years | Non-Recourse - Hydro
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | More than five years | Non-Recourse - Wind & Solar
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	283
Gross carrying amount | More than five years | Non-Recourse - Gas
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	855
Gross carrying amount | More than five years | Tax Equity Financing
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	68
Gross carrying amount | More than five years | Other
Disclosure of maturity analysis for derivative financial liabilities [line items]
Borrowings	0
Gross carrying amount | More than five years | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of maturity analysis for derivative financial liabilities [line items]
Interest expense on borrowings	0
Gross carrying amount | More than five years | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	$ (2)

Risk Management Activities - _4

Risk Management Activities - Maturity of Non-Hedges (Details) - 12 months ended Dec. 31, 2021 - Non-Hedges - Commodity risk management	CAD ($)$ / $	CAD ($)$ / $	AUD ($)	cADPerMegawattHour
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | 2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 8,000,000	$ 8,000,000	$ 14,000,000
Average foreign exchange rate	0.7893	0.7352
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | 2023
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 0	$ 0	0
Average foreign exchange rate	0	0
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | 2024
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 0	$ 0	0
Average foreign exchange rate	0	0
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | 2025
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 0	$ 0	0
Average foreign exchange rate	0	0
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | 2026
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 0	$ 0	0
Average foreign exchange rate	0	0
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | More than five years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 0	$ 0	$ 0
Average foreign exchange rate	0	0
Electricity | 2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 3,329,000	$ 3,329,000
Average power prices | cADPerMegawattHour				cADPerMegawattHour 71.95
Electricity | 2023
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	3,329,000	3,329,000
Average power prices | cADPerMegawattHour				73.76
Electricity | 2024
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	3,338,000	3,338,000
Average power prices | cADPerMegawattHour				75.6
Electricity | 2025
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	2,628,000	2,628,000
Average power prices | cADPerMegawattHour				77.49
Electricity | 2026
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	0	0
Average power prices | cADPerMegawattHour				0
Electricity | More than five years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount | $	$ 0	$ 0
Average power prices | cADPerMegawattHour				cADPerMegawattHour 0

Risk Management Activities - Ef

Risk Management Activities - Effect of Hedges (Details) MWh in Millions, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2021USD ($)MWh	Dec. 31, 2021CAD ($)MWh	Dec. 31, 2020USD ($)MWh	Dec. 31, 2020CAD ($)MWh
Disclosure of detailed information about hedging instruments [line items]
Hedging instrument, assets				$ 2		$ 2
Physical power sales | Cash flow hedges | Commodity risk management
Disclosure of detailed information about hedging instruments [line items]
Notional amount purchased | MWh			13	13	16	16
Hedging instrument, assets				$ 285		$ 573
Gain (loss) on hedge ineffectiveness	$ (181)	$ (33)
Interest rate swap | Cash flow hedges | Interest rate risk | U.S. Dollars
Disclosure of detailed information about hedging instruments [line items]
Notional amount			$ 300		$ 150
Gain (loss) on hedge ineffectiveness	3	3
Hedging instrument, liabilities				3		(3)
Interest rate swap | Cash flow hedges | Interest rate risk | Canada, Dollars
Disclosure of detailed information about hedging instruments [line items]
Notional amount						75
Gain (loss) on hedge ineffectiveness		4
Hedging instrument, liabilities						(4)
Foreign-denominated debt | Net Investment Hedge | Currency risk
Disclosure of detailed information about hedging instruments [line items]
Hedging instrument, assets				$ 473		$ 472
Gain (loss) on hedge ineffectiveness	$ 0	$ 11
Foreign-denominated debt | Net Investment Hedge | Currency risk | U.S. Dollars
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) MWh in Millions, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2021USD ($)MWh	Dec. 31, 2021CAD ($)MWh	Dec. 31, 2020USD ($)MWh	Dec. 31, 2020CAD ($)MWh
Disclosure of detailed information about hedging instruments [line items]
Hedging instrument, assets				$ 2		$ 2
Physical power sales | Cash flow hedges | Commodity risk management
Disclosure of detailed information about hedging instruments [line items]
Notional amount purchased | MWh			13	13	16	16
Hedging instrument, assets				$ 285		$ 573
Gain (loss) on hedge ineffectiveness	$ (181)	$ (33)
Reserve of cash flow hedges				226		417
Interest Expense On Long-Term Debt | Cash flow hedges | Interest rate risk
Disclosure of detailed information about hedging instruments [line items]
Gain (loss) on hedge ineffectiveness	3	7
Reserve of cash flow hedges				2		19
Foreign-denominated debt | Net Investment Hedge | Currency risk
Disclosure of detailed information about hedging instruments [line items]
Hedging instrument, assets				473		472
Gain (loss) on hedge ineffectiveness	0	11
Foreign-denominated debt | Net Investment Hedge | Currency risk | U.S. Dollars
Disclosure of detailed information about hedging instruments [line items]
Notional amount			$ 370		$ 370
Interest rate swap | Cash flow hedges | Interest rate risk | U.S. Dollars
Disclosure of detailed information about hedging instruments [line items]
Notional amount			300		$ 150
Hedging instrument, liabilities				3		(3)
Gain (loss) on hedge ineffectiveness	3	3
Interest rate swap | Cash flow hedges | Interest rate risk | Canada, Dollars
Disclosure of detailed information about hedging instruments [line items]
Notional amount						75
Hedging instrument, liabilities						$ (4)
Gain (loss) on hedge ineffectiveness		$ 4
Foreign-Denominated Expenditures | Cash flow hedges | Interest rate risk | U.S. Dollars | Minimum
Disclosure of detailed information about hedging instruments [line items]
Notional amount			8
Hedging instrument, liabilities				0
Gain (loss) on hedge ineffectiveness	0
Foreign-Denominated Expenditures | Cash flow hedges | Interest rate risk | U.S. Dollars | Maximum
Disclosure of detailed information about hedging instruments [line items]
Notional amount			$ 14
Hedging instrument, liabilities				$ 0
Gain (loss) on hedge ineffectiveness	$ 0

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) on cash flow hedges, before tax	$ (255)	$ 28	$ 77
Losses recognized in other comprehensive earnings	(8)	(141)	(53)
Gain (loss) on hedge ineffectiveness recognised in profit or loss	0	0	0
Commodity contracts
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) on cash flow hedges, before tax	(268)	41	77
Commodity contracts | Revenue
Disclosure of detailed information about hedging instruments [line items]
Losses recognized in other comprehensive earnings	(13)	(137)	(59)
Gain (loss) on hedge ineffectiveness recognised in profit or loss	0	0	0
Foreign exchange forwards on project hedges
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) on cash flow hedges, before tax	0	(1)
Foreign exchange forwards on project hedges | Property, plant and equipment
Disclosure of detailed information about hedging instruments [line items]
Losses recognized in other comprehensive earnings	1	0
Gain (loss) on hedge ineffectiveness recognised in profit or loss	0	0
Forward starting interest rate swaps
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) on cash flow hedges, before tax	13	(12)	0
Forward starting interest rate swaps | Interest expense
Disclosure of detailed information about hedging instruments [line items]
Losses recognized in other comprehensive earnings	4	(4)	6
Gain (loss) on hedge ineffectiveness recognised in profit or loss	$ 0	$ 0	$ 0

Inventory Components of Invento

Inventory Components of Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of inventories [Abstract]
Parts and materials	$ 82	$ 107
Coal	27	83
Deferred stripping costs	0	8
Natural gas	3	2
Purchased emission credits	55	38
Inventories	$ 167	$ 238	$ 251

Inventory Change in Inventory (

Inventory Change in Inventory (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Inventories at the beginning of the period	$ 238	$ 251
Net additions (use)	22	26
Write-downs	28	0
Change in foreign exchange rates	0	(2)
Inventories at the end of the period	167	238
Coal
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Write-downs	$ 65	$ 37

Inventory (Details)

Inventory (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)emissionCredit	Dec. 31, 2020CAD ($)emissionCredit
Analysis of income and expenses [Line Items]
Additions to emission credits | emissionCredit	2,033,752	1,434,761
Purchased emission credits	$ 55	$ 38
Inventory, emission credits | emissionCredit	1,922,973	1,211,230
Inventory write-down	$ 65	$ 37
Increased depreciation from the accelerated closure	48
Write-downs	28	$ 0
OM&A
Analysis of income and expenses [Line Items]
Write-downs	$ 28

Property, Plant, and Equipmen_2

Property, Plant, and Equipment (Details) $ in Millions	Aug. 01, 2020CAD ($)	Jun. 30, 2020CAD ($)	Dec. 31, 2021CAD ($)MW	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Sep. 30, 2021MW
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges			$ 345	$ 79
Property, plant and equipment expenditures			480	486	$ 417
Mine depreciation			190	144	119
Interest costs capitalised			$ 14	$ 8	6
Capitalisation rate of borrowing costs eligible for capitalisation			6.00%	6.00%
Assets			$ 9,226	$ 9,747
Net gain on sale of assets			(54)	(9)	(45)
PP&E			5,320	5,822	6,207
Assets Held for Sale
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges			0	0	15
Energy Transition
Disclosure of detailed information about property, plant and equipment [line items]
Net gain on sale of assets			23
Windrise Wind Facility
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures			96	156
WindCharger Battery Storage Project
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures				6
Consideration received	$ 12
Kaybob Cogeneration Facility
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures			14	31
Centralia Coal Mine
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures				17
Genesee Unit 3
Disclosure of detailed information about property, plant and equipment [line items]
Consideration received					77
Kent Hills Wind L.P.
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges			2
Mine depreciation			$ 12
Capacity of facility (in megawatts) | MW			167
SunHills and Centralia
Disclosure of detailed information about property, plant and equipment [line items]
PP&E			$ 100
White Rock Wind Project
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures			32	0
Garden Plain Wind Project
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures			38	0
Gas generation
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through transfers, property, plant and equipment			200
PP&E			1,909	1,877	2,036
Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
PP&E			184	495	228
Assets under construction | Windrise Wind Facility
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through transfers, property, plant and equipment			255
Assets under construction | Mount Keith Solar Farm
Disclosure of detailed information about property, plant and equipment [line items]
Capacity of facility (in megawatts) | MW						27
Assets under construction | Leinster Solar Farm
Disclosure of detailed information about property, plant and equipment [line items]
Capacity of facility (in megawatts) | MW						11
Assets under construction | Leinster battery energy storage system
Disclosure of detailed information about property, plant and equipment [line items]
Capacity of facility (in megawatts) | MW						10
Assets under construction | Southern Cross Energy North
Disclosure of detailed information about property, plant and equipment [line items]
Capacity of facility (in megawatts) | MW						169
Assets under construction | Kent Hills Wind Rehabilitation Project
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through transfers, property, plant and equipment			7
Assets under construction | Keephills Unit 1
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through transfers, property, plant and equipment			20
Assets under construction | Sundance Unit 5
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through transfers, property, plant and equipment			78
Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions			480	486
Increase (decrease) through transfers, property, plant and equipment			45	(431)
PP&E			13,389	13,398	13,395
Gross carrying amount | Centralia
Disclosure of detailed information about property, plant and equipment [line items]
PP&E			25
Gross carrying amount | Gas generation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures			91	93
Additions			0	0
Increase (decrease) through transfers, property, plant and equipment			232	(138)
PP&E			4,087	3,935	4,073
Gross carrying amount | Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
Additions			478	478
Increase (decrease) through transfers, property, plant and equipment			(696)	(211)
PP&E			184	495	228
Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Mine depreciation		$ 15
Increase (decrease) through transfers, property, plant and equipment			71	(255)
PP&E			(8,069)	(7,576)	(7,188)
Accumulated depreciation | Gas generation
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through transfers, property, plant and equipment			0	(212)
PP&E			(2,178)	(2,058)	(2,037)
Accumulated depreciation | Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through transfers, property, plant and equipment			0	0
PP&E			$ 0	$ 0	$ 0

Property, Plant, and Equipmen_3

Property, Plant, and Equipment - Reconciliation of the changes in the carrying amount of PP&E (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	$ 5,822	$ 6,207
Property, plant and equipment, end of the period	5,320	5,822
Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	13,398	13,395
Additions	480	486
Acquisitions	146	1
Disposals, property, plant and equipment	(79)	(5)
(Impairment) reversals (Note 7)	(589)	(81)
Retirements, property, plant and equipment	(121)	(58)
Increase (decrease) through net exchange differences, property, plant and equipment	(26)	(3)
Increase (decrease) through transfers, property, plant and equipment	45	(431)
Property, plant and equipment, end of the period	13,389	13,398
Gross carrying amount | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		13,395
Property, plant and equipment, end of the period
Gross carrying amount | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(7,576)	(7,188)
Disposals, property, plant and equipment	73	2
Retirements, property, plant and equipment	112	51
Increase (decrease) through net exchange differences, property, plant and equipment	(7)	(21)
Increase (decrease) through transfers, property, plant and equipment	71	(255)
Depreciation, property, plant and equipment	(614)	(717)
Property, plant and equipment, end of the period	(8,069)	(7,576)
Accumulated depreciation | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(7,188)
Property, plant and equipment, end of the period
Accumulated depreciation | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Land
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	96	91
Property, plant and equipment, end of the period	96	96
Land | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	96	91
Additions	0	0
Acquisitions	0	0
Disposals, property, plant and equipment	(1)	(2)
(Impairment) reversals (Note 7)	0	(9)
Retirements, property, plant and equipment	0	0
Increase (decrease) through net exchange differences, property, plant and equipment	0	(1)
Increase (decrease) through transfers, property, plant and equipment	1	17
Property, plant and equipment, end of the period	96	96
Land | Gross carrying amount | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		91
Property, plant and equipment, end of the period
Land | Gross carrying amount | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Land | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	0	0
Disposals, property, plant and equipment	0	0
Retirements, property, plant and equipment	0	0
Increase (decrease) through net exchange differences, property, plant and equipment	0	0
Increase (decrease) through transfers, property, plant and equipment	0	0
Depreciation, property, plant and equipment	0	0
Property, plant and equipment, end of the period	0	0
Land | Accumulated depreciation | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Land | Accumulated depreciation | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Renewable generation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	2,176	2,290
Property, plant and equipment, end of the period	2,582	2,176
Renewable generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	3,592	3,574
Additions	0	0
Acquisitions	146	0
Disposals, property, plant and equipment	0	0
(Impairment) reversals (Note 7)	(15)	(2)
Retirements, property, plant and equipment	(15)	(7)
Increase (decrease) through net exchange differences, property, plant and equipment	3	(14)
Increase (decrease) through transfers, property, plant and equipment	303	33
Property, plant and equipment, end of the period	4,143	3,592
Renewable generation | Gross carrying amount | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		3,574
Property, plant and equipment, end of the period
Renewable generation | Gross carrying amount | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Renewable generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(1,416)	(1,284)
Disposals, property, plant and equipment	0	0
Retirements, property, plant and equipment	9	5
Increase (decrease) through net exchange differences, property, plant and equipment	0	(4)
Increase (decrease) through transfers, property, plant and equipment	0	0
Depreciation, property, plant and equipment	(154)	(141)
Property, plant and equipment, end of the period	(1,561)	(1,416)
Renewable generation | Accumulated depreciation | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(1,284)
Property, plant and equipment, end of the period
Renewable generation | Accumulated depreciation | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Gas generation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	1,877	2,036
Increase (decrease) through transfers, property, plant and equipment	200
Property, plant and equipment, end of the period	1,909	1,877
Gas generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	3,935	4,073
Additions	0	0
Acquisitions	0	1
Disposals, property, plant and equipment	(2)	0
(Impairment) reversals (Note 7)	(2)	0
Retirements, property, plant and equipment	(57)	(47)
Increase (decrease) through net exchange differences, property, plant and equipment	(25)	45
Increase (decrease) through transfers, property, plant and equipment	232	(138)
Property, plant and equipment, end of the period	4,087	3,935
Gas generation | Gross carrying amount | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		1,671
Property, plant and equipment, end of the period
Gas generation | Gross carrying amount | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		2,402
Property, plant and equipment, end of the period
Gas generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(2,058)	(2,037)
Disposals, property, plant and equipment	1	0
Retirements, property, plant and equipment	55	43
Increase (decrease) through net exchange differences, property, plant and equipment	(8)	18
Increase (decrease) through transfers, property, plant and equipment	0	(212)
Depreciation, property, plant and equipment	(184)	(258)
Property, plant and equipment, end of the period	(2,178)	(2,058)
Gas generation | Accumulated depreciation | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(900)
Property, plant and equipment, end of the period
Gas generation | Accumulated depreciation | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		1,137
Property, plant and equipment, end of the period
Energy Transition
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	968	1,241
Property, plant and equipment, end of the period	363	968
Energy Transition | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	4,901	4,940
Additions	0	0
Acquisitions	0	0
Disposals, property, plant and equipment	(74)	(1)
(Impairment) reversals (Note 7)	(468)	(69)
Retirements, property, plant and equipment	(49)	(3)
Increase (decrease) through net exchange differences, property, plant and equipment	2	(39)
Increase (decrease) through transfers, property, plant and equipment	201	(12)
Property, plant and equipment, end of the period	4,513	4,901
Energy Transition | Gross carrying amount | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		7,342
Property, plant and equipment, end of the period
Energy Transition | Gross carrying amount | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(2,402)
Property, plant and equipment, end of the period
Energy Transition | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(3,933)	(3,699)
Disposals, property, plant and equipment	72	1
Retirements, property, plant and equipment	48	3
Increase (decrease) through net exchange differences, property, plant and equipment	2	(37)
Increase (decrease) through transfers, property, plant and equipment	71	(29)
Depreciation, property, plant and equipment	(264)	(304)
Property, plant and equipment, end of the period	(4,150)	(3,933)
Energy Transition | Accumulated depreciation | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(4,836)
Property, plant and equipment, end of the period
Energy Transition | Accumulated depreciation | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(1,137)
Property, plant and equipment, end of the period
Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	495	228
Property, plant and equipment, end of the period	184	495
Assets under construction | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	495	228
Additions	478	478
Acquisitions	0	0
Disposals, property, plant and equipment	(2)	0
(Impairment) reversals (Note 7)	(91)	0
Retirements, property, plant and equipment	0	0
Increase (decrease) through net exchange differences, property, plant and equipment	0	0
Increase (decrease) through transfers, property, plant and equipment	(696)	(211)
Property, plant and equipment, end of the period	184	495
Assets under construction | Gross carrying amount | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		228
Property, plant and equipment, end of the period
Assets under construction | Gross carrying amount | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Assets under construction | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	0	0
Disposals, property, plant and equipment	0	0
Retirements, property, plant and equipment	0	0
Increase (decrease) through net exchange differences, property, plant and equipment	0	0
Increase (decrease) through transfers, property, plant and equipment	0	0
Depreciation, property, plant and equipment	0	0
Property, plant and equipment, end of the period	0	0
Assets under construction | Accumulated depreciation | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Assets under construction | Accumulated depreciation | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Capital spares and other
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	210	321
Property, plant and equipment, end of the period	186	210
Capital spares and other | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	379	489
Additions	2	8
Acquisitions	0	0
Disposals, property, plant and equipment	0	(2)
(Impairment) reversals (Note 7)	(13)	(1)
Retirements, property, plant and equipment	0	(1)
Increase (decrease) through net exchange differences, property, plant and equipment	(6)	6
Increase (decrease) through transfers, property, plant and equipment	4	(120)
Property, plant and equipment, end of the period	366	379
Capital spares and other | Gross carrying amount | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		489
Property, plant and equipment, end of the period
Capital spares and other | Gross carrying amount | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Capital spares and other | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(169)	(168)
Disposals, property, plant and equipment	0	1
Retirements, property, plant and equipment	0	0
Increase (decrease) through net exchange differences, property, plant and equipment	(1)	2
Increase (decrease) through transfers, property, plant and equipment	0	(14)
Depreciation, property, plant and equipment	(12)	(14)
Property, plant and equipment, end of the period	(180)	(169)
Capital spares and other | Accumulated depreciation | Previously Reported
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(168)
Property, plant and equipment, end of the period
Capital spares and other | Accumulated depreciation | Revision of Prior Period, Reclassification, Adjustment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		0
Property, plant and equipment, end of the period
Decommissioning and restoration | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through other changes, property, plant and equipment	135	94
Decommissioning and restoration | Land | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through other changes, property, plant and equipment	0	0
Decommissioning and restoration | Renewable generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through other changes, property, plant and equipment	129	8
Decommissioning and restoration | Gas generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through other changes, property, plant and equipment	6	1
Decommissioning and restoration | Energy Transition | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through other changes, property, plant and equipment	0	85
Decommissioning and restoration | Assets under construction | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through other changes, property, plant and equipment	0	0
Decommissioning and restoration | Capital spares and other | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) through other changes, property, plant and equipment	$ 0	$ 0

Right of Use Assets - Reconcili

Right of Use Assets - Reconciliation of changes of the right of use assets (Details) - CAD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2021	Dec. 31, 2020
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		$ 141	$ 146
Additions to right-of-use assets		1	16
Depreciation, right-of-use assets		(11)	(21)
Acquisitions (Note 4)		13
Disposal of assets (Note 4)		(41)
Transfers		(8)
Right-of-use assets, ending balance		95	141
Land
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		58	58
Additions to right-of-use assets		0	3
Depreciation, right-of-use assets		(3)	(3)
Acquisitions (Note 4)		13
Disposal of assets (Note 4)		0
Transfers		0
Right-of-use assets, ending balance		68	58
Buildings
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		24	16
Additions to right-of-use assets		1	13
Depreciation, right-of-use assets		(5)	(5)
Acquisitions (Note 4)		0
Disposal of assets (Note 4)		0
Transfers		0
Right-of-use assets, ending balance		20	24
Vehicles
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		1	2
Additions to right-of-use assets		0	0
Depreciation, right-of-use assets		0	(1)
Acquisitions (Note 4)		0
Disposal of assets (Note 4)		0
Transfers		0
Right-of-use assets, ending balance		1	1
Equipment
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		16	25
Additions to right-of-use assets		0	0
Depreciation, right-of-use assets		(2)	(9)
Acquisitions (Note 4)		0
Disposal of assets (Note 4)		0
Transfers		(8)
Right-of-use assets, ending balance		6	16
Pipeline
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		42	45
Additions to right-of-use assets		0	0
Depreciation, right-of-use assets		(1)	(3)
Acquisitions (Note 4)		0
Decrease through derecognition, financial assets	$ 41
Transfers		0
Right-of-use assets, ending balance		$ 0	$ 42

Right of Use Assets - Narrative

Right of Use Assets - Narrative (Details) - CAD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of quantitative information about right-of-use assets [line items]
Payments of lease liabilities, classified as financing activities		$ 15	$ 33
Interest expense on lease liabilities		7	8	$ 4
Repayments of principal on lease liabilities		8	25
Expense relating to variable lease payments not included in measurement of lease liabilities		$ 6	$ 7
Pipeline
Disclosure of quantitative information about right-of-use assets [line items]
Decrease through derecognition, financial assets	$ 41
Decrease through derecognition, financial liabilities	43
Gains (losses) on available-for-sale financial assets	$ 2

Intangible Assets (Details)

Intangible Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	$ 313	$ 318
Ending balance	256	313
Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	833	788
Additions	9	14
Acquisition (Note 4)		37
Disposals		(1)
Impairment (Note 7)	(17)
Change in foreign exchange rates	(2)	(2)
Transfers	4	(3)
Ending balance	827	833
Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(520)	(470)
Disposals		1
Transfers		0
Amortization	51	51
Ending balance	(571)	(520)
Power sale contracts
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	146	143
Ending balance	129	146
Power sale contracts | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	269	250
Additions	0	0
Acquisition (Note 4)		37
Disposals		0
Impairment (Note 7)	0
Change in foreign exchange rates	0	(2)
Transfers	0	(16)
Ending balance	269	269
Power sale contracts | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(123)	(107)
Disposals		0
Transfers		(1)
Amortization	17	15
Ending balance	(140)	(123)
Software and other
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	140	132
Ending balance	123	140
Software and other | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	412	378
Additions	0	0
Acquisition (Note 4)		0
Disposals		(1)
Impairment (Note 7)	0
Change in foreign exchange rates	(2)	0
Transfers	12	35
Ending balance	422	412
Software and other | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(272)	(246)
Disposals		1
Transfers		(1)
Amortization	27	28
Ending balance	(299)	(272)
Intangibles under development
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	3	11
Ending balance	4	3
Intangibles under development | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	3	11
Additions	9	14
Acquisition (Note 4)		0
Disposals		0
Impairment (Note 7)	0
Change in foreign exchange rates	0	0
Transfers	8	(22)
Ending balance	4	3
Intangibles under development | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	0	0
Disposals		0
Transfers		0
Amortization	0	0
Ending balance	0	0
Coal rights
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	24	32
Ending balance	0	24
Coal rights | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	149	149
Additions	0	0
Acquisition (Note 4)		0
Disposals		0
Impairment (Note 7)	(17)
Change in foreign exchange rates	0	0
Transfers	0	0
Ending balance	132	149
Coal rights | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance	(125)	(117)
Disposals		0
Transfers		0
Amortization	7	8
Ending balance	$ (132)	$ (125)

Goodwill (Details)

Goodwill (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)cADPerMegawattHour	Dec. 31, 2020CAD ($)cADPerMegawattHour
Disclosure of detailed information about intangible assets [line items]
Goodwill	$ 463	$ 463
Hydro generation
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	175	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]
Electricity prices | cADPerMegawattHour	17	6
Discount rate used to calculate goodwill impairment	5.00%	4.80%
Maximum
Disclosure of detailed information about intangible assets [line items]
Electricity prices | cADPerMegawattHour	136	160
Discount rate used to calculate goodwill impairment	6.40%	6.30%

Other Assets (Details)

Other Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure of financial assets [abstract]
South Hedland prepaid transmission access and distribution costs	$ 65	$ 70
Project development costs	29	25
Long-term prepaids and other assets	48	59
Loan receivable	55	52
Other current assets	55	0
Other assets	142	206
Other assets	$ 197	$ 206

Other Assets Narrative (Details

Other Assets Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of joint operations [line items]
Loan receivable	$ 55	$ 52
Kent Hills Wind L.P.
Disclosure of joint operations [line items]
Loan receivable	$ 55	$ 52
Proportion of ownership interests held by non-controlling interests	17.00%
Interest rate	4.55%

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, 2021	Dec. 31, 2020
Reconciliation of changes in other provisions [abstract]
Balance	$ 673	$ 546
Liabilities incurred	30	35
Liabilities settled	(80)	(37)
Accretion	(32)	30
Acquisition of liabilities	2	1
Revisions in estimated cash flows	179	72
Revisions in discount rates	(6)	36
Reversals	(3)	(6)
Change in foreign exchange rates		(4)
Balance	$ 827	673
Minimum
Reconciliation of changes in other provisions [abstract]
Increase (decrease) in discount rates, other provisions	(0.30%)
Maximum
Reconciliation of changes in other provisions [abstract]
Increase (decrease) in discount rates, other provisions	(0.90%)
Decommissioning and restoration
Reconciliation of changes in other provisions [abstract]
Balance	$ 608	501
Liabilities incurred	8	1
Liabilities settled	(18)	(18)
Accretion	(32)	30
Acquisition of liabilities	2	1
Revisions in estimated cash flows	167	61
Revisions in discount rates	(6)	36
Reversals	0	0
Change in foreign exchange rates		(4)
Balance	793	608
Other provisions
Reconciliation of changes in other provisions [abstract]
Balance	65	45
Liabilities incurred	22	34
Liabilities settled	(62)	(19)
Accretion	0	0
Acquisition of liabilities	0	0
Revisions in estimated cash flows	12	11
Revisions in discount rates	0	0
Reversals	(3)	(6)
Change in foreign exchange rates		0
Balance	$ 34	$ 65

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of other provisions [line items]
Balance	$ 827	$ 673	$ 546
Current portion	48	59
Non-current portion	779	614
Decommissioning and restoration
Disclosure of other provisions [line items]
Balance	793	608	501
Current portion	35	21
Non-current portion	758	587
Other provisions
Disclosure of other provisions [line items]
Balance	34	65	$ 45
Current portion	13	38
Non-current portion	$ 21	$ 27

Decommissioning and Other Pro_5

Decommissioning and Other Provisions - Decommissioning and Restoration (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2021USD ($)	Sep. 30, 2021CAD ($)	Dec. 31, 2020USD ($)	Sep. 30, 2020CAD ($)
Disclosure of detailed information about borrowings [line items]
Undiscounted cash flows required for future removal of facilities	$ 1,600
Provision for decommissioning, restoration and rehabilitation costs					$ 120
Onerous contracts provision		$ 29
Onerous contract provisions	(14)	(29)	$ 0
Gas And Energy Transition
Disclosure of detailed information about borrowings [line items]
Provision for decommissioning, restoration and rehabilitation costs	47
Centralia Coal Mine
Disclosure of detailed information about borrowings [line items]
Onerous contract provisions	(14)
Centralia Coal Mine | Surety Bonds
Disclosure of detailed information about borrowings [line items]
Bonds issued				$ 147		$ 147
Alberta Mine | Decommissioning and restoration
Disclosure of detailed information about borrowings [line items]
Provision for decommissioning, restoration and rehabilitation costs							$ 75
Alberta Mine | Letters Of Credit
Disclosure of detailed information about borrowings [line items]
Bonds issued	$ 188	131
Sarnia | Decommissioning and restoration
Disclosure of detailed information about borrowings [line items]
Provision for decommissioning, restoration and rehabilitation costs		$ 15

Credit Facilities, Long-Term _3

Credit Facilities, Long-Term Debt and Lease Liabilities - Amounts Outstanding (Details) $ in Millions, $ in Millions, $ in Millions	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2021AUD ($)	Dec. 06, 2021	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2020AUD ($)
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 3,267				$ 3,361
Less: current portion of long-term debt	(837)				(97)
Less: current portion of lease liabilities	(7)				(8)
Total current long-term debt and lease liabilities	(844)				(105)
Credit facilities, long-term debt, and finance lease obligations	2,423				3,256
All Borrowings Except Finance Lease Obligations
Disclosure of detailed information about borrowings [line items]
Carrying value	3,167				3,227
Notional amount	3,198				3,264
Credit facilities
Disclosure of detailed information about borrowings [line items]
Carrying value	0				114
Notional amount					114
7.3% Medium term notes
Disclosure of detailed information about borrowings [line items]
Carrying value	110				109
Notional amount	110				110
6.9% Medium term notes
Disclosure of detailed information about borrowings [line items]
Carrying value	141				140
Notional amount	141				141
Senior notes | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 700				$ 700
6.5% Senior notes | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Carrying value	378				380
Notional amount	383				383
0.045 | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Carrying value	510				506
Notional amount	511				511
Melancthon Wolfe Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	235				268
Notional amount	237				270
New Richmond Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	120				127
Notional amount	121				128
Kent Hills Wind LP bond(4)
Disclosure of detailed information about borrowings [line items]
Carrying value	221				230
Notional amount	221				233
Windrise Wind LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	171				0
Notional amount	173				0
Interest rate				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	102				111
Notional amount	104				113
TEC Hedland PTY Ltd bond | Australia, Dollars
Disclosure of detailed information about borrowings [line items]
Carrying value	732				772
Notional amount	742				782
South Hedland Bond | Australia, Dollars
Disclosure of detailed information about borrowings [line items]
Carrying value			$ 800				$ 800
TransAlta OCP LP bond
Disclosure of detailed information about borrowings [line items]
Carrying value	263				284
Notional amount	265				287
Big Level & Antrim | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Carrying value	106				112
Notional amount	112	88			119	94
Lakeswind | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Carrying value	18				22
Notional amount	18	14			22	16
North Carolina Solar | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Carrying value	11				0
Notional amount	11	$ 9			0	$ 0
Other
Disclosure of detailed information about borrowings [line items]
Carrying value	4				7
Notional amount	4				6
Finance lease obligation
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 100				$ 134
Weighted average | Credit facilities
Disclosure of detailed information about borrowings [line items]
Interest rate					2.70%	2.70%	2.70%
Weighted average | 7.3% Medium term notes
Disclosure of detailed information about borrowings [line items]
Interest rate	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 rate	6.90%	6.90%	6.90%		6.90%	6.90%	6.90%
Weighted average | 6.5% Senior notes | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Interest rate	6.50%	6.50%	6.50%		6.50%	6.50%	6.50%
Weighted average | 0.045 | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Interest rate	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 rate	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 rate	4.00%	4.00%	4.00%		4.00%	4.00%	4.00%
Weighted average | Kent Hills Wind LP bond(4)
Disclosure of detailed information about borrowings [line items]
Interest rate	4.50%	4.50%	4.50%		4.50%	4.50%	4.50%
Weighted average | Windrise Wind LP bond
Disclosure of detailed information about borrowings [line items]
Interest rate	3.40%	3.40%	3.40%		0.00%	0.00%	0.00%
Weighted average | Pingston bond
Disclosure of detailed information about borrowings [line items]
Interest rate	3.00%	3.00%	3.00%		3.00%	3.00%	3.00%
Weighted average | TAPC Holdings LP bond (Poplar Creek)
Disclosure of detailed information about borrowings [line items]
Interest rate	4.40%	4.40%	4.40%		4.50%	4.50%	4.50%
Weighted average | TEC Hedland PTY Ltd bond | Australia, Dollars
Disclosure of detailed information about borrowings [line items]
Interest rate	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 rate	4.50%	4.50%	4.50%		4.50%	4.50%	4.50%
Weighted average | Big Level & Antrim | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Interest rate	6.60%	6.60%	6.60%		6.60%	6.60%	6.60%
Weighted average | Lakeswind | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Interest rate	10.50%	10.50%	10.50%		10.50%	10.50%	10.50%
Weighted average | North Carolina Solar | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Interest rate	7.30%	7.30%	7.30%		0.00%	0.00%	0.00%
Weighted average | Other
Disclosure of detailed information about borrowings [line items]
Interest rate	5.90%	5.90%	5.90%		5.90%	5.90%	5.90%

Credit Facilities, Long-Term _4

Credit Facilities, Long-Term Debt and Lease Liabilities - Credit facilities summarized (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about borrowings [line items]
Facility size	$ 2,190
Outstanding letters of credit	902
Borrowings	3,267	$ 3,361
Available capacity	1,288	1,500
Financial assets pledged as collateral for liabilities or contingent liabilities	18	0
TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Financial assets pledged as collateral for liabilities or contingent liabilities	55
Revolving committed syndicated bank facility
Disclosure of detailed information about borrowings [line items]
Facility size	1,250
Outstanding letters of credit	618
Borrowings	0
Available capacity	632
Canadian committed bilateral credit facilities
Disclosure of detailed information about borrowings [line items]
Facility size	240
Outstanding letters of credit	186
Borrowings	0
Available capacity	54
Committed Credit Facility | TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Facility size	700
Outstanding letters of credit	98
Borrowings	0
Available capacity	602
Credit facilities
Disclosure of detailed information about borrowings [line items]
Borrowings	$ 0	$ 114

Credit Facilities, Long-Term _5

Credit Facilities, Long-Term Debt and Lease Liabilities - Credit Facilities (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	$ 902
Available capacity	1,288	$ 1,500
Cash and cash equivalents	947	703	$ 411	$ 89
Canadian committed bilateral credit facilities
Disclosure of detailed information about borrowings [line items]
Outstanding letters of credit	186
Available capacity	54
Sustainability Linked Loan
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	1,300
Letter of credit
Disclosure of detailed information about borrowings [line items]
Debt instruments issued	157
Credit facilities | Committed credit facilities
Disclosure of detailed information about borrowings [line items]
Undrawn borrowing capacity under line of credit	1,300	1,500
Corporation and TransAlta Renewables | Syndicated Bank Credit Facility
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	2,000	2,000
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)	17	$ 17
Restricted cash and cash equivalents, principal amount	$ 17

Credit Facilities, Long-Term _6

Credit Facilities, Long-Term Debt and Lease Liabilities - Debentures (Details) - Medium Term Notes $ in Millions	Nov. 25, 2020CAD ($)
Disclosure of detailed information about borrowings [line items]
Borrowings, Redemption	$ 400
Interest rate	5.00%

Credit Facilities, Long-Term _7

Credit Facilities, Long-Term Debt and Lease Liabilities - Senior Notes (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Long-term debt | Net investment hedges
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 370	$ 370

Credit Facilities, Long-Term _8

Credit Facilities, Long-Term Debt and Lease Liabilities - Non-Recourse Debt (Details) $ in Millions, $ in Millions	Dec. 31, 2021CAD ($)	Dec. 06, 2021	Dec. 31, 2020CAD ($)	Oct. 22, 2020AUD ($)
Disclosure of detailed information about borrowings [line items]
Borrowings	$ 3,267		$ 3,361
Senior Secured Note Maturing June 2042
Disclosure of detailed information about borrowings [line items]
Borrowings				$ 800
Interest rate	4.07%
Windrise Wind LP bond
Disclosure of detailed information about borrowings [line items]
Borrowings	$ 171		$ 0
Interest rate		3.41%

Credit Facilities, Long-Term _9

Credit Facilities, Long-Term Debt and Lease Liabilities - Other (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)
Disclosure of detailed information about borrowings [line items]
Weighted average duration of defined benefit obligation	13 years 7 months 6 days
Letter of credit
Disclosure of detailed information about borrowings [line items]
Debt instruments issued	$ 157
Other | 5.9% Unsecured Commercial Loan Obligation due 2023
Disclosure of detailed information about borrowings [line items]
Interest rate	5.90%

Credit Facilities, Long-Term_10

Credit Facilities, Long-Term Debt and Lease Liabilities - Restrictions on Non-Recourse Debt and Security (Details) $ in Millions, $ in Millions	Jul. 20, 2018CAD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2021AUD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Disclosure of detailed information about borrowings [line items]
Other borrowings		$ 735		$ 730
Borrowings		3,267		3,361
PP&E		5,320		5,822	$ 6,207
Intangible assets		256		313	318
Alberta Off-Coal Agreement	$ 40	40		40	$ 40
Alberta off-coal agreement, annual cash payments, net		37
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)		17		17
Renewable generation facilities
Disclosure of detailed information about borrowings [line items]
PP&E		1,500		1,000
Intangible assets		78		88
Non-recourse debt
Disclosure of detailed information about borrowings [line items]
Other borrowings		1,900		1,800
Restricted cash (Note 22)		67		73
Borrowings		221
Borrowings, make-whole amount		39
Adjustments for undistributed profits of associates		6
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
Non-recourse debt | Secured by equity interests of the issuer
Disclosure of detailed information about borrowings [line items]
Notional amount		103		111
Restricted Use Debt
Disclosure of detailed information about borrowings [line items]
Proceeds from issue of bonds, notes and debentures		3	$ 4
Secured Debt | TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 263		$ 285

Credit Facilities, Long-Term_11

Credit Facilities, Long-Term Debt and Lease Liabilities - Principal Repayments (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about borrowings [line items]
Borrowings	$ 3,267	$ 3,361
2022
Disclosure of detailed information about borrowings [line items]
Lease commitments for short-term leases for which recognition exemption has been used	13
Gross carrying amount
Disclosure of detailed information about borrowings [line items]
Borrowings	3,198
Lease liabilities	100
Gross carrying amount | 2022
Disclosure of detailed information about borrowings [line items]
Borrowings	836
Lease liabilities	(6)
Gross carrying amount | 2023
Disclosure of detailed information about borrowings [line items]
Borrowings	155
Lease liabilities	4
Gross carrying amount | 2024
Disclosure of detailed information about borrowings [line items]
Borrowings	113
Lease liabilities	3
Gross carrying amount | 2025
Disclosure of detailed information about borrowings [line items]
Borrowings	127
Lease liabilities	3
Gross carrying amount | 2026
Disclosure of detailed information about borrowings [line items]
Borrowings	127
Lease liabilities	3
Gross carrying amount | 2027
Disclosure of detailed information about borrowings [line items]
Borrowings	1,840
Lease liabilities	$ 93

Credit Facilities, Long-Term_12

Credit Facilities, Long-Term Debt and Lease Liabilities - Restricted Cash and Letters of Credit (Details) - CAD ($)	Dec. 31, 2021	Dec. 31, 2020
US Wind Projects - Big Level
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)	$ 0	$ 9,000,000
Letter of credit
Disclosure of detailed information about borrowings [line items]
Exposure to credit risk on loan commitments and financial guarantee contracts	902,000,000	621,000,000
Amount exercised under letters of credit	0	0
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)	17,000,000	17,000,000
TEC
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)	53,000,000	$ 45,000,000
Uncommitted demand letter facility
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	150,000,000
Uncommitted demand letter facility | TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	150,000,000
Uncommitted Demand Letter Facility 2
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	100,000,000
Bilateral Committed Credit Facilities
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	$ 240,000,000

Exchangeable Securities (Detail

Exchangeable Securities (Details) - CAD ($) $ / shares in Units, $ in Millions	Dec. 31, 2021	Oct. 30, 2020	May 25, 2019	May 01, 2019	Mar. 22, 2019	Dec. 31, 2021	May 01, 2021	Dec. 31, 2020
Brookfield Renewable Partners
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interests held by non-controlling interests							9.00%
Number of shares in entity held by entity or by its subsidiaries or associates	35,425,696					35,425,696
Number of shares in entity held by entity or by its subsidiaries or associates, expressed as a percentage of issued and outstanding common shares	13.10%					13.10%
Investment Agreement
Disclosure of detailed information about borrowings [line items]
Consideration received					$ 7.5
Commitment fee					15
Investment Agreement | Discount rate, measurement input
Disclosure of detailed information about borrowings [line items]
Percentage of reasonably possible increase in unobservable input, liabilities	1.00%					1.00%
Investment Agreement | Brookfield Renewable Partners
Disclosure of detailed information about borrowings [line items]
Proceeds on sale of an organizational unit			$ 750		$ 750
Percentage of total investment that represents transaction cost					3.00%
Other cash receipts from sales of equity or debt instruments of other entities, classified as investing activities		$ 400		$ 350
Dividend payables	$ 7					$ 7
Expected dividend as percentage, share options granted	1.764%
Investment Agreement | Brookfield Renewable Partners | Minimum ownership interest threshold to increase ownership interest to 49%
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interests held by non-controlling interests						8.50%
Investment Agreement | Brookfield Renewable Partners | Hydro | Ownership interest, less than, threshold which triggers one time option to increase ownership interest
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary						49.00%
Investment Agreement | Brookfield Renewable Partners | 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 held by non-controlling interests allowed to be acquired						10.00%
Investment Agreement | Brookfield Renewable Partners | 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						49.00%
Investment Agreement | Brookfield Renewable Partners | Hydro | Ownership interest threshold if exceeded requires redemption price in cash
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary						49.00%
Investment Agreement | Brookfield Renewable Partners | Hydro | Minimum | 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]
Weighted average share price						$ 14
Investment Agreement | Brookfield Renewable Partners | Hydro | Maximum
Disclosure of detailed information about borrowings [line items]
Proportion of ownership interest in subsidiary						49.00%
Investment Agreement | Brookfield Renewable Partners | Hydro | Maximum | 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						$ 17
7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of detailed information about borrowings [line items]
Interest rate	7.00%			7.00%		7.00%		7.00%

Exchangeable Securities - Sched

Exchangeable Securities - Schedule of Exchangeable Securities (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	May 01, 2019
Disclosure of detailed information about borrowings [line items]
Credit facilities, long-term debt, and finance lease obligations	$ 2,423	$ 3,256
7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of detailed information about borrowings [line items]
Notes and debentures issued	$ 350	$ 350
Interest rate	7.00%	7.00%	7.00%
Exchangeable Preferred Shares	$ 400	$ 400
Credit facilities, long-term debt, and finance lease obligations	750	750
Gross carrying amount | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of detailed information about borrowings [line items]
Notes and debentures issued	335	330
Exchangeable Preferred Shares	400	400
Credit facilities, long-term debt, and finance lease obligations	$ 735	$ 730

Exchangeable Securities - Optio

Exchangeable Securities - Option To Exchange (Details) - Option to exchange - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of detailed information about borrowings [line items]
Fair value	$ 0	$ 0
Minimum
Disclosure of detailed information about borrowings [line items]
Sensitivity percentage	0	0
Maximum
Disclosure of detailed information about borrowings [line items]
Sensitivity percentage	$ (32)	$ (33)

Defined Benefit Obligation an_3

Defined Benefit Obligation and Other Long-Term Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Subclassifications of assets, liabilities and equities [abstract]
Defined benefit obligation	$ 228	$ 282
Long-term incentive accruals	4	4
Other	21	12
Total	253	$ 298
Increase (decrease) in net defined benefit liability (asset)	$ (54)

Common Shares - Issued and Outs

Common Shares - Issued and Outstanding (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of classes of share capital [line items]
Proceeds from exercise of options	$ 8	$ 0
Common shares
Dilutive effect of share options on number of ordinary shares	1.2	0.1
Common shares
Disclosure of classes of share capital [line items]
Issued and outstanding, end of year	$ 2,896	$ 2,978
Proceeds from issuing shares	0	(79)
Effects of share-based payment plans	(3)	(3)
Issued and outstanding, end of year	$ 2,901	$ 2,896
Common shares
Issued and outstanding, beginning of year	269.8	277
Shares issued	0	(7.3)
Issued and outstanding, end of year	271	269.8

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, 2021	Dec. 31, 2020	May 25, 2021	May 26, 2020	Dec. 31, 2019
Disclosure of classes of share capital [line items]
Deficit	$ (2,453)	$ (1,826)
Percentage of public float of common shares making up stock purchase agreement, shares authorized			7.16%	7.02%
Number of shares issued and fully paid that were not cancelled due to timing differences between the transaction date and settlement date	0	456,200
NCIB Program
Disclosure of classes of share capital [line items]
Number of shares issued and fully paid	0	7,352,600
Par value per share	$ 0	$ 8.33
Issued capital	$ 0	$ 61
Weighted average book value of shares cancelled	0	79
Deficit	0	18
Stock purchase agreement, number of shares authorized			14,000,000	14,000,000
Common shares
Disclosure of classes of share capital [line items]
Issued capital	$ 2,901	$ 2,896			$ 2,978

Common Shares - Shareholder Rig

Common Shares - Shareholder Rights Plan (Details)	12 Months Ended
	Dec. 31, 2021
Shareholder Rights Plan | Common shares | Minimum
Disclosure of classes of share capital [line items]
Percentage of outstanding common shares at which Shareholder Rights Plan may take effect	20.00%

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Share Capital, Reserves And Other Equity Interest [Abstract]
Net earnings (loss) attributable to common shareholders	$ (576)	$ (336)	$ 52
Weighted average number of ordinary shares used in calculating diluted earnings per share	271,000	275,000	283,000
Basic and diluted weighted average number of common shares outstanding (millions)	271,000	275,000	283,000
Net earnings (loss) per share attributable to common shareholders, basic (in CAD per share)	$ (2.13)	$ (1.22)	$ 0.18
Net earnings (loss) per share attributable to common shareholders, diluted (in CAD per share)	$ (2.13)	$ (1.22)	$ 0.18

Common Shares - Dividends (Deta

Common Shares - Dividends (Details)	Dec. 13, 2021$ / shares
Share Capital, Reserves And Other Equity Interest [Abstract]
Dividends declared per share	$ 0.05

Preferred Shares - Issued and O

Preferred Shares - Issued and Outstanding (Details) - CAD ($) shares in Millions, $ in Millions	Dec. 31, 2021	Mar. 31, 2021	Dec. 31, 2020
Preferred Shares
Disclosure of classes of share capital [line items]
Number of shares outstanding	38.6		38.6
Number of shares issued and outstanding	38.6		38.6
Issued capital (Note 25)	$ 942		$ 942
Series A
Disclosure of classes of share capital [line items]
Number of shares outstanding	9.6	9.6	10.2
Number of shares issued and outstanding	9.6	9.6	10.2
Issued capital (Note 25)	$ 235		$ 248
Series B
Disclosure of classes of share capital [line items]
Number of shares outstanding	2.4	2.4	1.8
Number of shares issued and outstanding	2.4	2.4	1.8
Issued capital (Note 25)	$ 58		$ 45
Series C
Disclosure of classes of share capital [line items]
Number of shares outstanding	11		11
Number of shares issued and outstanding	11		11
Issued capital (Note 25)	$ 269		$ 269
Series E
Disclosure of classes of share capital [line items]
Number of shares outstanding	9		9
Number of shares issued and outstanding	9		9
Issued capital (Note 25)	$ 219		$ 219
Series G
Disclosure of classes of share capital [line items]
Number of shares outstanding	6.6		6.6
Number of shares issued and outstanding	6.6		6.6
Issued capital (Note 25)	$ 161		$ 161

Preferred Shares - Series Cumul

Preferred Shares - Series Cumulative Redeemable Rate Reset Preferred Shares Conversion (Details) - $ / shares	Dec. 13, 2021	Dec. 31, 2021	Dec. 31, 2020	Mar. 31, 2021	Mar. 18, 2021
Disclosure of classes of share capital [line items]
Dividends declared per share	$ 0.05
Series G
Disclosure of classes of share capital [line items]
Number of shares outstanding		6,600,000	6,600,000
Dividends declared per share	0.3118
Number of shares issued		6,600,000	6,600,000
Series E
Disclosure of classes of share capital [line items]
Number of shares outstanding		9,000,000	9,000,000
Dividends declared per share	0.3246
Number of shares issued		9,000,000	9,000,000
Series C
Disclosure of classes of share capital [line items]
Number of shares outstanding		11,000,000	11,000,000
Dividends declared per share	0.2517
Number of shares issued		11,000,000	11,000,000
Series A
Disclosure of classes of share capital [line items]
Convertible preferred shares tendered for conversion					1,417,338
Number of shares outstanding		9,600,000	10,200,000	9,600,000
Dividends declared per share	0.1798
Number of shares issued		9,600,000	10,200,000	9,600,000
Series B
Disclosure of classes of share capital [line items]
Convertible preferred shares tendered for conversion					871,871
Dividend rate on preference shares, spread		2.03%	2.03%
Number of shares outstanding		2,400,000	1,800,000	2,400,000
Dividends declared per share	$ 0.1331
Number of shares issued		2,400,000	1,800,000	2,400,000

Preferred Shares - Preferred Sh

Preferred Shares - Preferred Share Series Information (Details) - Preferred Shares	12 Months Ended
	Dec. 31, 2021$ / shares
Disclosure of classes of share capital [line items]
Fixed rate reset term	5 years
Amount per share redeemable at reset date	$ 25

Preferred Shares - Characterist

Preferred Shares - Characteristics Specific to Series of Preferred Shares (Details)	12 Months Ended
	Dec. 31, 2021$ / shares
Series A
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 0.71924
Series A | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over Benchmark	2.03%
Series B
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 0.53866
Series B | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over Benchmark	2.03%
Series C
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 1.00676
Series C | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over Benchmark	3.10%
Series D
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 0
Series D | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over Benchmark	3.10%
Series E
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 1.29852
Series E | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over Benchmark	3.65%
Series F
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 0
Series F | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over Benchmark	3.65%
Series G
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 1.24700
Series G | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over Benchmark	3.80%
Series H
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 0
Series H | Benchmark
Disclosure of classes of share capital [line items]
Rate spread over Benchmark	3.80%

Preferred Shares - Preferred _2

Preferred Shares - Preferred Share Dividends Declared (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Series A
Disclosure of classes of share capital [line items]
Dividends declared	$ 7	$ 9
Series B
Disclosure of classes of share capital [line items]
Dividends declared	$ 1	$ 1
Dividend rate on preference shares, spread	2.03%	2.03%
Series C
Disclosure of classes of share capital [line items]
Dividends declared	$ 11	$ 14
Series E
Disclosure of classes of share capital [line items]
Dividends declared	12	15
Series G
Disclosure of classes of share capital [line items]
Dividends declared	8	10
Preferred Shares
Disclosure of classes of share capital [line items]
Dividends declared	$ 39	$ 49

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Earnings (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020	Dec. 31, 2019
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		$ 302
Currency translation adjustment
Losses on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		14
Gains on financial instruments designated as hedges of foreign operations, net of tax		0		$ 11	$ 21
Cash flow hedges
Gains (losses) on derivatives designated as cash flow hedges, net of tax	[1]	(200)		20	61
Other
Intercompany FVOCI investments		0		0
Accumulated other comprehensive income, end of the period		146		302
Net impact related to cash flow hedges		57		23	(6)
Income tax relating to net actuarial gains (losses)		(11)		3	7
Reserve of exchange differences on translation
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(21)		(21)
Currency translation adjustment
Losses on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		(14)		(11)
Gains on financial instruments designated as hedges of foreign operations, net of tax		0		11
Other
Accumulated other comprehensive income, end of the period		(35)		(21)	(21)
Reserve of cash flow hedges
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		436		527
Cash flow hedges
Gains (losses) on derivatives designated as cash flow hedges, net of tax		(208)		(91)
Other
Accumulated other comprehensive income, end of the period		228		436	527
Net impact related to cash flow hedges		(57)		(23)
Reserve of remeasurements of defined benefit plans
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(66)		(55)
Employee future benefits
Net actuarial gains (losses) on defined benefit plans, net of tax		37		(11)
Other
Accumulated other comprehensive income, end of the period		(29)		(66)	(55)
Income tax relating to net actuarial gains (losses)		11		(3)
Other reserves
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(47)		3
Other
Intercompany FVOCI investments		29	[2]	(50)
Accumulated other comprehensive income, end of the period		$ (18)		$ (47)	$ 3
[1]	Net of income tax recovery of $55 million for the year ended Dec. 31, 2021 (2020 —$8 million expense, 2019 — $16 million expense).
[2]	Refer to Note 29 for details on components of, and changes in, accumulated other comprehensive earnings (loss).

Share-Based Payment Plans (Deta

Share-Based Payment Plans (Details) shares in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)shares	Dec. 31, 2020CAD ($)shares	Dec. 31, 2019CAD ($)shares	Mar. 31, 2021shares	Feb. 29, 2016shares
Executive officers
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of share options granted (in shares) | shares	0.7	0.7	1.4
Weighted average exercise price of share options granted in share-based payment arrangement	$ 9.86	$ 9.17	$ 5.65
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)	$ 14,000,000	15,000,000	19,000,000
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)	$ 3,000,000	$ 1,000,000	2,000,000
Stock Options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of shares authorized (in shares) | shares		16.5		14.5	14.5
Stock Options | Executive officers
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	3 years
Compensation expense (reversal)	$ 2,000,000	$ 2,000,000	$ 1,000,000
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, 2021sharesCAD ($)
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Number of options (in shares) | shares	3.2
Weighted average remaining contractual life (in years)	4 years 2 months 12 days
Weighted average exercise price (in dollars per share)	$ 7.54
Minimum
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Exercise price of outstanding share options (in dollars per share)	5
Maximum
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Exercise price of outstanding share options (in dollars per share)	$ 9

Employee Future Benefits (Detai

Employee Future Benefits (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of defined benefit plans [line items]
Administration expenses	$ 1	$ 1	$ 2
Weighted average duration of defined benefit obligation	13 years 7 months 6 days
Minimum
Disclosure of defined benefit plans [line items]
Employer contribution (as percent)	500.00%
Maximum
Disclosure of defined benefit plans [line items]
Employer contribution (as percent)	1000.00%
Registered
Disclosure of defined benefit plans [line items]
Administration expenses	$ 1	1	2
Registered | Letter of credit
Disclosure of defined benefit plans [line items]
Letter of credit, posted	97
Registered | Related parties [member]
Disclosure of defined benefit plans [line items]
Administration expenses	0	0
Supplemental Pension Plan
Disclosure of defined benefit plans [line items]
Administration expenses	$ 0	0	0
Other
Disclosure of defined benefit plans [line items]
Maximum age disabled and retired members eligible for benefits	65 years
Administration expenses	$ 0	$ 0	$ 0

Employee Future Benefits - Cost

Employee Future Benefits - Costs Recognized (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	$ 6	$ 8	$ 10
Administration expenses	1	1	2
Defined benefit expense	6	15	19
Defined contribution expense	8	9	9
Net expense	14	24	28
Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	14	20	23
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	(8)	(12)	(13)
Curtailment and amendment gain	(7)	(2)	(3)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	3	5	7
Administration expenses	1	1	2
Defined benefit expense	1	9	13
Defined contribution expense	8	9	9
Net expense	9	18	22
Registered | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	3	5
Interest cost	12	16	19
Curtailment and amendment gain	(7)	(2)
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	(8)	(11)	(12)
Curtailment and amendment gain	(7)	(2)	(3)
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	2	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 Pension Plan | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	2	2
Interest cost	2	3	3
Curtailment and amendment gain	0	0
Supplemental Pension Plan | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	0	(1)	(1)
Curtailment and amendment gain	0	0	0
Other
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	1	1	1
Administration expenses	0	0	0
Defined benefit expense	1	2	2
Defined contribution expense	0	0	0
Net expense	1	2	2
Other | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	1	1
Interest cost	0	1	1
Curtailment and amendment gain	0	0
Other | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	0	0	0
Curtailment and amendment gain	$ 0	$ 0	$ 0

Employee Future Benefits - Stat

Employee Future Benefits - Status of Plans (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	$ (240)	$ (294)
Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(12)	(12)
Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(228)	(282)
Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	353	381	$ 386
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(593)	(675)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(130)	(175)
Registered | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(4)	(5)
Registered | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(126)	(170)
Registered | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	339	367	373
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(469)	(542)	(543)
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(87)	(95)
Supplemental Pension Plan | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(6)	(5)
Supplemental Pension Plan | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(81)	(90)
Supplemental Pension Plan | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	14	14	13
Supplemental Pension Plan | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(101)	(109)	(99)
Other
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(23)	(24)
Other | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(2)	(2)
Other | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(21)	(22)
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)	$ (23)	$ (24)	$ (22)

Employee Future Benefits - Fair

Employee Future Benefits - Fair Value of Plan Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	$ (294)
Administration expenses	(1)	$ (1)	$ (2)
Net asset, ending of period	(240)	(294)
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	381	386
Interest on plan assets	8	12	13
Net return on plan assets	13	24
Contributions	12	13
Benefits paid	(60)	(51)
Effect of translation on US plans		(2)
Net asset, ending of period	353	381	386
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(175)
Administration expenses	(1)	(1)	(2)
Net asset, ending of period	(130)	(175)
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	367	373
Interest on plan assets	8	11	12
Net return on plan assets	14	25
Contributions	5	6
Benefits paid	(54)	(45)
Effect of translation on US plans		(2)
Net asset, ending of period	339	367	373
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(95)
Administration expenses	0	0	0
Net asset, ending of period	(87)	(95)
Supplemental Pension Plan | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	14	13
Interest on plan assets	0	1	1
Net return on plan assets	(1)	(1)
Contributions	6	6
Benefits paid	(5)	(5)
Effect of translation on US plans		0
Net asset, ending of period	14	14	13
Other
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(24)
Administration expenses	0	0	0
Net asset, ending of period	(23)	(24)
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	0
Net return on plan assets	0	0
Contributions	1	1
Benefits paid	(1)	(1)
Effect of translation on US plans		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, 2021	Dec. 31, 2020
Disclosure of fair value of plan assets [line items]
Money market and cash and cash equivalents	$ 20	$ 19
Total	353	381
Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	33	64
US
Disclosure of fair value of plan assets [line items]
Equity securities	20	30
International
Disclosure of fair value of plan assets [line items]
Equity securities	126	103
Private [Member]
Disclosure of fair value of plan assets [line items]
Equity securities	1	1
AAA
Disclosure of fair value of plan assets [line items]
Bonds	28	36
AA
Disclosure of fair value of plan assets [line items]
Bonds	54	67
A
Disclosure of fair value of plan assets [line items]
Bonds	36	34
BBB
Disclosure of fair value of plan assets [line items]
Bonds	25	23
Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	10	4
Level I
Disclosure of fair value of plan assets [line items]
Money market and cash and cash equivalents	0	0
Total	48	1
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	0	0
Level I | International
Disclosure of fair value of plan assets [line items]
Equity securities	47	0
Level I | Private [Member]
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
Level I | BBB
Disclosure of fair value of plan assets [line items]
Bonds	1	1
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]
Money market and cash and cash equivalents	20	19
Total	300	379
Level II | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	29	64
Level II | US
Disclosure of fair value of plan assets [line items]
Equity securities	20	30
Level II | International
Disclosure of fair value of plan assets [line items]
Equity securities	79	103
Level II | Private [Member]
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	28	36
Level II | AA
Disclosure of fair value of plan assets [line items]
Bonds	54	67
Level II | A
Disclosure of fair value of plan assets [line items]
Bonds	36	34
Level II | BBB
Disclosure of fair value of plan assets [line items]
Bonds	24	22
Level II | Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	10	4
Level III
Disclosure of fair value of plan assets [line items]
Money market and cash and cash equivalents	0	0
Total	5	1
Level III | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	4	0
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 [Member]
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
Level III | BBB
Disclosure of fair value of plan assets [line items]
Bonds	0	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, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	$ 294
Current service cost	6	$ 8	$ 10
Defined benefit obligation, ending of period	240	294
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	675
Interest cost	14	20	23
Defined benefit obligation, ending of period	593	675
Registered
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	175
Current service cost	3	5	7
Defined benefit obligation, ending of period	130	175
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	542	543
Current service cost	3	5
Interest cost	12	16	19
Benefits paid	(54)	(45)
Curtailment and amendment gain	(7)	(2)
Actuarial loss arising from financial assumptions	(26)	43
Actuarial gain arising from experience adjustments	(1)	(17)
Effect of translation on US plans		(1)
Defined benefit obligation, ending of period	469	542	543
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	95
Current service cost	2	2	2
Defined benefit obligation, ending of period	87	95
Supplemental Pension Plan | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	109	99
Current service cost	2	2
Interest cost	2	3	3
Benefits paid	(5)	(5)
Curtailment and amendment gain	0	0
Actuarial loss arising from financial assumptions	(7)	10
Actuarial gain arising from experience adjustments	0	0
Effect of translation on US plans		0
Defined benefit obligation, ending of period	101	109	99
Other
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	24
Current service cost	1	1	1
Defined benefit obligation, ending of period	23	24
Other | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	24	22
Current service cost	1	1
Interest cost	0	1	1
Benefits paid	(1)	(1)
Curtailment and amendment gain	0	0
Actuarial loss arising from financial assumptions	(1)	2
Actuarial gain arising from experience adjustments	0	0
Effect of translation on US plans		(1)
Defined benefit obligation, ending of period	23	24	22
Total | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	675	664
Current service cost	6	8
Interest cost	14	20
Benefits paid	(60)	(51)
Curtailment and amendment gain	(7)	(2)
Actuarial loss arising from financial assumptions	(34)	55
Actuarial gain arising from experience adjustments	(1)	(17)
Effect of translation on US plans		(2)
Defined benefit obligation, ending of period	$ 593	$ 675	$ 664

Employee Future Benefits - Cont

Employee Future Benefits - Contributions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021CAD ($)
Registered
Disclosure of defined benefit plans [line items]
Expected employer contributions	$ 5
Supplemental Pension Plan
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	$ 13

Employee Future Benefits - Assu

Employee Future Benefits - Assumptions (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Other, through 2027
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	4.50%
Maximum age disabled and retired members eligible for benefits	65 years
Percentage of reasonably possible decrease in actuarial assumption	0.30%
Other, through 2030
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	4.50%	4.50%
Maximum age disabled and retired members eligible for benefits	65 years
Percentage of reasonably possible decrease in actuarial assumption	0.30%	0.30%
Other, through 2030 | Canada
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	4.50%	4.50%
Other, 2029 through 2030
Assumed health-care cost trend rate
Maximum age disabled and retired members eligible for benefits	65 years
Other, 2029 through 2030 | Canada
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)		4.50%
Other, 2029 through 2030 | US
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)		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	2.80%	2.40%
Rate of compensation increase	2.90%	2.90%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%
Accrued Benefit Obligation | Supplemental Pension Plan
Disclosure of defined benefit plans [line items]
Discount rate	2.80%	2.30%
Rate of compensation increase	3.00%	3.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%
Accrued Benefit Obligation | Other, through 2027
Disclosure of defined benefit plans [line items]
Discount rate	2.70%	2.30%
Rate of compensation increase	0.00%	0.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	6.80%	6.80%
Dental-care cost escalation	4.00%	4.00%
Other, through 2027 | Registered
Disclosure of defined benefit plans [line items]
Discount rate	2.40%	3.00%
Rate of compensation increase	2.90%	2.90%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%
Other, through 2027 | Supplemental Pension Plan
Disclosure of defined benefit plans [line items]
Discount rate	2.30%	3.00%
Rate of compensation increase	3.00%	3.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%
Other, through 2027 | Other, through 2027
Disclosure of defined benefit plans [line items]
Discount rate	2.30%	3.00%
Rate of compensation increase	0.00%	0.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	7.10%	7.10%
Dental-care cost escalation	4.00%	4.00%

Employee Future Benefits - Sens

Employee Future Benefits - Sensitivity Analysis (Details) $ in Millions	Dec. 31, 2021CAD ($)
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)	1.00%
Percentage of reasonably possible increase in actuarial assumption (as percent)	1.00%
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)	1.00%
Percentage of reasonably possible increase in actuarial assumption (as percent)	1.00%
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)	1.00%
Percentage of reasonably possible increase in actuarial assumption (as percent)	1.00%
10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Percentage of reasonably possible increase in actuarial assumption (as percent)	10.00%
Percentage of reasonably possible increase in actuarial assumption (as percent)	10.00%
Registered Pension Plan | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	$ 61
Registered Pension Plan | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	3
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	20
Registered Pension Plan | US | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	3
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 Pension Plan | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	15
Supplemental Pension Plan | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Supplemental 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
Supplemental Pension Plan | Canada | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	4
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	2
Other | Canada | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Other | US | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1
Other | US | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Other | 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
Other | US | 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, 2021
Wind and Solar | Skookumchuck
Disclosure of joint operations [line items]
Proportion of ownership interest in joint venture	49.00%
Sheerness | Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Goldfields Power | Australian Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Fort Saskatchewan | Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	60.00%
Fortescue River Gas Pipeline | Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	43.00%
McBride Lake | Wind and Solar
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Soderglen | Wind and Solar
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Pingston | Hydro generation
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%

Cash Flow Information (Details)

Cash Flow Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of cash flow statement [Abstract]
Accounts receivable	$ (28)	$ (79)	$ 261
Prepaid expenses	9	2	0
Income taxes receivable	0	(4)	(6)
Inventory	42	6	(13)
Accounts payable, accrued liabilities and provisions	153	160	(130)
Income taxes payable	(2)	4	9
Change in non-cash operating working capital balances	$ 174	$ 89	$ 121

Cash Flow Information Changes i

Cash Flow Information Changes in Liabilities from Financing Activities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	$ 4,150	$ 3,575
Cash issuances	173	1,153
Repayments and dividends paid	(301)	(706)
New leases	1	16
Dividends declared	90	107
Foreign exchange impact	(39)	5
Other	(10)	0
Balance at end of the period	4,064	4,150
Long-term debt and lease liabilities
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	3,361	3,212
Cash issuances	173	753
Repayments and dividends paid	(214)	(620)
New leases	1	16
Dividends declared	0	0
Foreign exchange impact	(39)	5
Other	(15)	(5)
Balance at end of the period	3,267	3,361
Exchangeable securities (Note 25)
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	730	326
Cash issuances	0	400
Repayments and dividends paid	0	0
New leases	0	0
Dividends declared	0	0
Foreign exchange impact	0	0
Other	5	4
Balance at end of the period	735	730
Dividends payable (common and preferred)
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	59	37
Cash issuances	0	0
Repayments and dividends paid	(87)	(86)
New leases	0	0
Dividends declared	90	107
Foreign exchange impact	0	0
Other	0	1
Balance at end of the period	$ 62	$ 59

Capital Disclosure of component

Capital Disclosure of components of capital (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of components of capital [Line Items]
Long-term debt		$ 3,267	$ 3,361
Increase (decrease) in financial liabilities		(94)
Exchangeable securities		735	730
Increase (decrease) in exchangeable securities		5
Equity		2,593	3,436	$ 4,062
Cash and cash equivalents		(947)	(703)	(411)	$ (89)
Increase (decrease) in cash and cash equivalents		(244)	(292)	(322)
Current restricted cash and cash equivalents		(70)	(71)
Fair value asset of hedging instruments on long-term debt		(2)	(2)
Increase (decrease) in hedging instruments, liabilities		0
Total capital		5,629	6,811
Increase (decrease) in capital		(1,182)
Common shares
Disclosure of components of capital [Line Items]
Equity		2,901	2,896
Increase (decrease) in equity		5
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		46	38	42
Increase (decrease) in equity		8
Deficit
Disclosure of components of capital [Line Items]
Equity		(2,453)	(1,826)	(1,455)
Increase (decrease) in equity		(627)
Accumulated other comprehensive income
Disclosure of components of capital [Line Items]
Equity	[1]	146	302	454
Increase (decrease) in equity		(156)
Non-controlling interests
Disclosure of components of capital [Line Items]
Equity		1,011	1,084	$ 1,101
Increase (decrease) in equity		(73)
TransAlta OCP
Disclosure of components of capital [Line Items]
Current restricted cash and cash equivalents		(17)	$ (11)
Increase (decrease) in restricted cash and cash equivalents		$ (6)
[1]	Refer to Note 29 for details on components of, and changes in, accumulated other comprehensive earnings (loss).

Capital Disclosure of cash flow

Capital Disclosure of cash flow statement (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of classes of share capital [line items]
Cash flows from (used in) operating activities	$ 1,001	$ 702	$ 849
Increase (decrease) in cash flow from (used in) operating activities	299
Change in non-cash operating working capital balances	(174)	(89)	(121)
Increase (decrease) in non cash working capital	(85)
Cash flow from operations before changes in working capital	827	613	728
Increase (decrease) in cash flow from operations before changes in working capital	214
Distributions paid to subsidiaries’ non-controlling interests	156	97	106
Increase (decrease) in dividends paid to non controlling interests	(59)
Property, plant and equipment expenditures	480	486	417
Increase (decrease) in property, plant and equipment expenditure	6
Net inflows (outflows) of cash	104	(56)
Increase (decrease) in net inflows (outflows) of cash	160
Credit facilities | Committed credit facilities
Disclosure of classes of share capital [line items]
Undrawn borrowing capacity under line of credit	1,300	1,500
Common shares
Disclosure of classes of share capital [line items]
Dividends paid	48	47	45
Increase (decrease) in dividends paid	(1)
Preferred shares
Disclosure of classes of share capital [line items]
Dividends paid	39	$ 39	$ 40
Increase (decrease) in dividends paid	$ 0

Related Party Transactions Disc

Related Party Transactions Disclosure of interests in subsidiaries (Details) $ in Millions, $ in Millions	Feb. 26, 2021CAD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2019	Dec. 31, 2021USD ($)
Disclosure of subsidiaries [line items]
Receivables due from associates		$ (18)		$ (14)
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)		60.10%	60.40%
Consideration received	$ 213
Canada | TransAlta Generation Partnership
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)		100.00%
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)		100.00%
Canada | TransAlta Renewables Inc.
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		49.00%
US | EMG International, LLC
Disclosure of subsidiaries [line items]
Proportion of ownership interest in joint venture		30.00%
US | TransAlta Centralia Generation, LLC
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)		100.00%
US | TransAlta Energy Marketing (U.S.), Inc.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)		100.00%
Australia | TransAlta Energy (Australia), Pty Ltd.
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)		100.00%

Related Party Transactions Di_2

Related Party Transactions Disclosure of transactions between related parties (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party [Abstract]
Total compensation	$ 30	$ 27	$ 30
Short-term employee benefits	14	12	13
Post-employment benefits	1	2	2
Termination benefits	0	0	2
Share-based payments	$ 15	$ 13	$ 13

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions, $ in Millions, $ in Millions	Nov. 05, 2021USD ($)MW	Apr. 01, 2021CAD ($)MW	Feb. 26, 2021CAD ($)MW	Oct. 22, 2020CAD ($)	Oct. 22, 2020AUD ($)	Aug. 01, 2020CAD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Dec. 23, 2020MW
Disclosure of subsidiaries [line items]
Receivables due from associates							$ (18)	$ (14)
US Wind Projects
Disclosure of subsidiaries [line items]
Notes and debentures issued							$ 7	$ 6
WindCharger Battery Storage Project
Disclosure of subsidiaries [line items]
Consideration received						$ 12
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Proceeds from redemption of intercompany securities				$ 480	$ 515
Amount receivable from employees					$ 200
Interest rate					4.32%
Windrise Wind Facility
Disclosure of subsidiaries [line items]
Capacity of facility (in megawatts) | MW			206						206
Skookumchuck
Disclosure of subsidiaries [line items]
Capacity of facility (in megawatts) | MW		137
Ada Cogeneration Facility
Disclosure of subsidiaries [line items]
Capacity of facility (in megawatts) | MW		29
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Consideration received			$ 213
TransAlta Renewables Inc. | Windrise Wind Facility
Disclosure of subsidiaries [line items]
Percentage of voting equity interests acquired									100.00%
TransAlta Renewables Inc. | Skookumchuck
Disclosure of subsidiaries [line items]
Percentage of voting equity interests acquired		49.00%
Consideration received		$ 103
TransAlta Renewables Inc. | Ada Cogeneration Facility
Disclosure of subsidiaries [line items]
Percentage of voting equity interests acquired		100.00%
Consideration received		$ 43
TransAlta Renewables Inc. | Solar Facilities In North Carolina
Disclosure of subsidiaries [line items]
Percentage of voting equity interests acquired	100.00%
Capacity of facility (in megawatts) | MW	122
Consideration received	$ 102

Commitments and Contingencies -

Commitments and Contingencies - Commitments (Details) $ in Millions, $ in Millions	Dec. 31, 2021CAD ($)	Jul. 30, 2015USD ($)
Disclosure of Commitments [Line Items]
Coal supply and mining agreements1	$ 339
Long-term service agreements	289
Operating leases	43
Growth	1,217
TransAlta Energy Transition Bill	12	$ 55
Total	2,675
Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	743
Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	32
2022
Disclosure of Commitments [Line Items]
Coal supply and mining agreements1	76
Long-term service agreements	89
Operating leases	4
Growth	941
TransAlta Energy Transition Bill	6
Total	1,172
2022 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	47
2022 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	9
2023
Disclosure of Commitments [Line Items]
Coal supply and mining agreements1	98
Long-term service agreements	46
Operating leases	3
Growth	276
TransAlta Energy Transition Bill	6
Total	492
2023 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	54
2023 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	9
2024
Disclosure of Commitments [Line Items]
Coal supply and mining agreements1	90
Long-term service agreements	43
Operating leases	3
Growth	0
TransAlta Energy Transition Bill	0
Total	187
2024 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	45
2024 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	6
2025
Disclosure of Commitments [Line Items]
Coal supply and mining agreements1	75
Long-term service agreements	32
Operating leases	1
Growth	0
TransAlta Energy Transition Bill	0
Total	158
2025 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	44
2025 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	6
2026
Disclosure of Commitments [Line Items]
Coal supply and mining agreements1	0
Long-term service agreements	25
Operating leases	1
Growth	0
TransAlta Energy Transition Bill	0
Total	73
2026 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	45
2026 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	2
2027
Disclosure of Commitments [Line Items]
Coal supply and mining agreements1	0
Long-term service agreements	54
Operating leases	31
Growth	0
TransAlta Energy Transition Bill	0
Total	593
2027 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	508
2027 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	$ 0

Commitments and Contingencies_2

Commitments and Contingencies (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2021CAD ($)	Dec. 31, 2021USD ($)	Jun. 30, 2021TJ	Jul. 30, 2015USD ($)
Disclosure of Commitments [Line Items]
Long-term firm natural gas delivery transportation, amount transferred per day | TJ				400
TransAlta Energy Transition Bill		$ 12			$ 55
Funded portion of energy bill commitment			$ 46
Increase (decrease) in loss contingency accrual, percentage	15.00%
Increase (decrease) in loss contingency accrual	$ 3
Keephills Unit 1
Disclosure of Commitments [Line Items]
Estimated financial effect of contingent liabilities	12
Tidewater
Disclosure of Commitments [Line Items]
Long-term firm natural gas delivery transportation, amount transferred per day | TJ				139
Increase (decrease) through modification of contractual cash flows, financial assets	$ (1,300)
Pioneer Pipeline
Disclosure of Commitments [Line Items]
Long-term firm natural gas delivery transportation, amount transferred per day | TJ				275

Segments Disclosures - Addition

Segments Disclosures - Additional Information (Details) - segment	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Disclosure of major customers [line items]
Number of segments	6
Customer 1
Disclosure of major customers [line items]
Percentage of entity's revenue	35.00%	15.00%

Segments Disclosures - Reported

Segments Disclosures - Reported Segment Earnings (Loss) and Segment Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of operating segments [line items]
Revenues	$ 2,721	$ 2,101	$ 2,347
Fuel and purchased power	1,054	805	881
Carbon compliance	178	163	205
Gross margin	1,489	1,133	1,261
OM&A	511	472
Taxes, other than income taxes	32	33	29
Net other operating expense (income)	8	(11)	(49)
Termination of Sundance B and C PPAs	0	0	(56)
Adjusted EBITDA
Equity income from associate	9	1	0
Finance lease income	25	7	6
Depreciation and amortization	(529)	(654)	(590)
Asset impairment	(648)	(84)	(25)
Gains on disposals of investments	0	0	88
Net interest expense	245	238	179
Foreign exchange gain (loss)	16	17	(15)
Gains on disposals of non-current assets	54	9	46
Earnings (loss) before income taxes	(380)	(303)	193
Previously Reported
Disclosure of operating segments [line items]
Revenues	2,721	2,101	2,347
Fuel and purchased power	1,054	805	881
OM&A	511		475
Net other operating expense (income)	8	(11)
Operating segments
Disclosure of operating segments [line items]
Revenues	2,768	2,174	2,344
Fuel and purchased power	843	618	756
Carbon compliance	178	163	205
Gross margin	1,747	1,393	1,383
OM&A	491	472
Taxes, other than income taxes	33	33	29
Net other operating expense (income)	(40)	(39)	(49)
Termination of Sundance B and C PPAs			(56)
Adjusted EBITDA	1,263	927	984
Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	2,739	2,104	2,347
Fuel and purchased power	1,054	805	881
OM&A	513		475
Net other operating expense (income)	8	(11)
Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenues	(34)	42	(33)
Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	41	17	24
Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenues	25	7	6
Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	(3)	4
Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	(4)	(4)	(4)
Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power	(190)	(146)	(121)
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 expense (income)	(48)
Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating expense (income)		(28)
Material reconciling items
Disclosure of operating segments [line items]
Revenues	(29)	(70)	3
Fuel and purchased power	211	187	125
Carbon compliance	0	0	0
Gross margin	(240)	(257)	(122)
OM&A	22	0
Taxes, other than income taxes	0	0	0
Net other operating expense (income)	48	28	0
Termination of Sundance B and C PPAs			0
Adjusted EBITDA
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 expense (income)	0	0
Material reconciling items | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenues	34	(42)	33
Material reconciling items | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	(41)	(17)	(24)
Material reconciling items | Finance lease income
Disclosure of operating segments [line items]
Revenues	(25)	(7)	(6)
Material reconciling items | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	3	(4)
Material reconciling items | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	4	4	4
Material reconciling items | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power	190	146	121
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 expense (income)	48
Material reconciling items | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating expense (income)		28
Material reconciling items | Contribution from equity accounted investments
Disclosure of operating segments [line items]
Revenues	(18)	(3)
Fuel and purchased power	0	0
Carbon compliance	0	0
Gross margin	(18)	(3)
OM&A	(2)	0
Taxes, other than income taxes	(1)	0
Net other operating expense (income)	0	0
Adjusted EBITDA
Material reconciling items | Contribution from equity accounted investments | Previously Reported
Disclosure of operating segments [line items]
Revenues	(18)	(3)
Fuel and purchased power	0	0
OM&A	(2)
Net other operating expense (income)	0	0
Material reconciling items | Contribution from equity accounted investments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenues	0	0
Material reconciling items | Contribution from equity accounted investments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	0	0
Material reconciling items | Contribution from equity accounted investments | Finance lease income
Disclosure of operating segments [line items]
Revenues	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
Material reconciling items | Contribution from equity accounted investments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	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 expense (income)	0
Material reconciling items | Contribution from equity accounted investments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating expense (income)		0
Hydro | Operating segments
Disclosure of operating segments [line items]
Revenues	383	152	156
Fuel and purchased power	16	8	7
Carbon compliance	0	0	0
Gross margin	367	144	149
OM&A	42	37
Taxes, other than income taxes	3	2	3
Net other operating expense (income)	0		0
Termination of Sundance B and C PPAs			0
Adjusted EBITDA	322	105	110
Hydro | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	383	152	156
Fuel and purchased power	16	8	7
OM&A	42		36
Net other operating expense (income)	0	0
Hydro | Operating segments | Unrealized mark-to-market (gain) loss
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
Hydro | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Hydro | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power	0	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 expense (income)	0
Hydro | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating expense (income)		0
Wind and Solar | Operating segments
Disclosure of operating segments [line items]
Revenues	348	334	295
Fuel and purchased power	17	25	16
Carbon compliance	0	0	0
Gross margin	331	309	279
OM&A	59	53
Taxes, other than income taxes	10	8	8
Net other operating expense (income)	0		(10)
Termination of Sundance B and C PPAs			0
Adjusted EBITDA	262	248	231
Wind and Solar | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	323	332	312
Fuel and purchased power	17	25	16
OM&A	59		50
Net other operating expense (income)	0	0
Wind and Solar | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenues	25	2	(17)
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
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 | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power	0	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 expense (income)	0
Wind and Solar | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating expense (income)		0
Gas | Operating segments
Disclosure of operating segments [line items]
Revenues	1,132	848	887
Fuel and purchased power	374	221	230
Carbon compliance	118	120	138
Gross margin	640	507	519
OM&A	173	166
Taxes, other than income taxes	13	13	9
Net other operating expense (income)	(40)	(39)	(41)
Termination of Sundance B and C PPAs			(14)
Adjusted EBITDA	494	367	403
Gas | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	1,109	787	851
Fuel and purchased power	457	325	315
OM&A	175		162
Net other operating expense (income)	(40)	(11)
Gas | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenues	(40)	33	6
Gas | Operating segments | Decrease in finance lease receivable
Disclosure of operating segments [line items]
Revenues	41	17	24
Gas | Operating segments | Finance lease income
Disclosure of operating segments [line items]
Revenues	25	7	6
Gas | Operating segments | Unrealized foreign exchange gain on commodity
Disclosure of operating segments [line items]
Revenues	(3)	4
Gas | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	(4)	(4)	(4)
Gas | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power	(79)	(100)	(81)
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 expense (income)	0
Gas | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating expense (income)		(28)
Energy Transition
Disclosure of operating segments [line items]
Asset impairment	(191)
Energy Transition | Operating segments
Disclosure of operating segments [line items]
Revenues	728	690	893
Fuel and purchased power	432	352	499
Carbon compliance	60	48	77
Gross margin	236	290	317
OM&A	97	106
Taxes, other than income taxes	6	9	8
Net other operating expense (income)	0	0	0
Termination of Sundance B and C PPAs			(42)
Adjusted EBITDA	133	175	227
Energy Transition | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	709	704	905
Fuel and purchased power	560	435	539
OM&A	117		124
Net other operating expense (income)	48	0
Energy Transition | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenues	19	(14)	(12)
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
Energy Transition | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Energy Transition | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power	(111)	(46)	(40)
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 expense (income)	(48)
Energy Transition | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating expense (income)		0
Energy Marketing | Operating segments
Disclosure of operating segments [line items]
Revenues	173	143	119
Fuel and purchased power	0	0	0
Carbon compliance	0	0	0
Gross margin	173	143	119
OM&A	36	30
Taxes, other than income taxes	0	0	0
Net other operating expense (income)	0	0	0
Termination of Sundance B and C PPAs			0
Adjusted EBITDA	137	113	89
Energy Marketing | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	211	122	129
Fuel and purchased power	0	0	0
OM&A	36		30
Net other operating expense (income)	0	0
Energy Marketing | Operating segments | Unrealized mark-to-market (gain) loss
Disclosure of operating segments [line items]
Revenues	(38)	21	(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	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 | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power	0	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 expense (income)	0
Energy Marketing | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating expense (income)		0
Corporate | Operating segments
Disclosure of operating segments [line items]
Revenues	4	7	(6)
Fuel and purchased power	4	12	4
Carbon compliance	0	(5)	(10)
Gross margin	0	0	0
OM&A	84	80
Taxes, other than income taxes	1	1	1
Net other operating expense (income)	0	0	2
Termination of Sundance B and C PPAs			0
Adjusted EBITDA	(85)	(81)	(76)
Corporate | Operating segments | Previously Reported
Disclosure of operating segments [line items]
Revenues	4	7	(6)
Fuel and purchased power	4	12	4
OM&A	84		73
Net other operating expense (income)	0	0
Corporate | Operating segments | Unrealized mark-to-market (gain) loss
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
Corporate | Operating segments | Australian interest income
Disclosure of operating segments [line items]
Fuel and purchased power	0	0	0
Corporate | Operating segments | Mine depreciation
Disclosure of operating segments [line items]
Fuel and purchased power	0	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 expense (income)	$ 0
Corporate | Operating segments | Impact of Sheerness going off-coal
Disclosure of operating segments [line items]
Net other operating expense (income)		$ 0

Segments Disclosures - Selected

Segments Disclosures - Selected Consolidated Statements of Financial Position Information (Details) - CAD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of operating segments [line items]
PP&E	$ 5,320	$ 5,822	$ 6,207
Right-of-use assets	95	141	146
Intangible assets	256	313	$ 318
Goodwill	463	463
Wind and Solar
Disclosure of operating segments [line items]
Goodwill	175	175
Energy Marketing
Disclosure of operating segments [line items]
Goodwill	30	30
Corporate
Disclosure of operating segments [line items]
PP&E	33	16
Right-of-use assets	18	22
Intangible assets	36	41
Goodwill	0	0
Operating segments | Hydro
Disclosure of operating segments [line items]
PP&E	466	467
Right-of-use assets	5	6
Intangible assets	3	4
Goodwill	258	258
Operating segments | Wind and Solar
Disclosure of operating segments [line items]
PP&E	2,304	2,005
Right-of-use assets	64	55
Intangible assets	147	159
Goodwill	175	175
Operating segments | Gas
Disclosure of operating segments [line items]
PP&E	2,036	2,102
Right-of-use assets	7	5
Intangible assets	56	66
Goodwill	0	0
Operating segments | Energy Transition
Disclosure of operating segments [line items]
PP&E	481	1,232
Right-of-use assets	1	53
Intangible assets	9	36
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	5	7
Goodwill	$ 30	$ 30

Segments Disclosures - Additi_2

Segments Disclosures - Additions to non-current assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	$ 480	$ 486	$ 417
Purchase of intangible assets	9	14	14
Corporate
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	28	13	1
Purchase of intangible assets	8	13	12
Operating segments | Hydro
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	29	22	23
Purchase of intangible assets	0	0	0
Operating segments | Wind and Solar
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	166	174	229
Purchase of intangible assets	0	0	0
Operating segments | Gas
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	167	199	74
Purchase of intangible assets	0	0	0
Operating segments | Energy Transition
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	90	78	90
Purchase of intangible assets	1	1	2
Operating segments | Energy Marketing
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	0	0	0
Purchase of intangible assets	$ 0	$ 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of operating segments [abstract]
Depreciation and amortization	$ 529	$ 654	$ 590
Mine depreciation	190	144	119
Depreciation and amortization on the Consolidated Statements of Cash Flows	$ 719	$ 798	$ 709

Segments Disclosures - Geograph

Segments Disclosures - Geographic Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure of geographical areas [line items]
Revenues	$ 2,721	$ 2,101	$ 2,347
PP&E	5,320	5,822	6,207
Right-of-use assets	95	141	146
Intangible assets	256	313	318
Other assets	142	206
Goodwill	463	463
Canada
Disclosure of geographical areas [line items]
Revenues	1,854	1,227	1,460
PP&E	4,051	4,661
Right-of-use assets	52	107
Intangible assets	141	185
Other assets	15	74
US
Disclosure of geographical areas [line items]
Revenues	731	716	727
PP&E	860	737
Right-of-use assets	39	30
Intangible assets	85	94
Other assets	61	61
Australia
Disclosure of geographical areas [line items]
Revenues	136	158	$ 160
PP&E	409	424
Right-of-use assets	4	4
Intangible assets	30	34
Other assets	$ 66	$ 71