TransAlta (TAC) 40-F 3 Mar 21 2020 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2020shares
Document And Entity Information [Abstract]
Document Type	40-F
Document Period End Date	Dec. 31, 2020
Amendment Flag	false
Entity Registrant Name	TransAlta Corporation
Entity Central Index Key	0001144800
Entity Current Reporting Status	Yes
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Common Shares Outstanding	270,244,741
Entity Emerging Growth Company	false
Entity Incorporation, State or Country Code	A0
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
Document Annual Report	true
Document Registration Statement	false
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
Business Contact
Document And Entity Information [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

Consolidated Statements of Earn

Consolidated Statements of Earnings (Loss) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Profit or loss [abstract]
Revenue (Note 5)	$ 2,101	$ 2,347	$ 2,249
Fuel, carbon compliance and purchased power (Note 6)	968	1,086	1,100
Gross margin	1,133	1,261	1,149
Operations, maintenance and administration (Note 6)	472	475	515
Depreciation and amortization	654	590	574
Asset impairment charge (Note 7)	84	25	73
Gain on termination of Keephills 3 coal rights contract	0	(88)	0
Taxes, other than income taxes	33	29	31
Termination of Sundance B and C PPAs	0	(56)	(157)
Net other operating expense (income) (Note 9)	(11)	(49)	(47)
Operating income	(99)	335	160
Equity income (Note 10)	1	0	0
Finance lease income	7	6	8
Net interest expense	(238)	(179)	(250)
Foreign exchange gain (loss)	17	(15)	(15)
Gain on sale of assets and other (Note 4(R) and 18)	9	46	1
Earnings (loss) before income taxes	(303)	193	(96)
Income tax expense (recovery)	(50)	17	(6)
Net earnings (loss)	(253)	176	(90)
Net earnings (loss) attributable to:
TransAlta shareholders	(287)	82	(198)
Non-controlling interests (Note 12)	34	94	108
Net earnings (loss)	(253)	176	(90)
Preferred share dividends (Note 25)	49	30	50
Net earnings (loss) attributable to common shareholders	$ (336)	$ 52	$ (248)
Weighted average number of common shares outstanding in the year (in shares)	275	283	287
Net earnings (loss) per share attributable to common shareholders, basic and diluted (in CAD per share)	$ (1.22)	$ 0.18	$ (0.86)

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of comprehensive income [abstract]
Net earnings (loss)		$ (253)	$ 176	$ (90)
Other comprehensive income (loss)
Net actuarial gains (losses) on defined benefit plans, net of tax	[1]	(11)	(26)	15
Losses on derivatives designated as cash flow hedges, net of tax		(1)	0	0
Total items that will not be reclassified subsequently to net earnings		(12)	(26)	15
Gains (losses) on translating net assets of foreign operations, net of tax		(11)	(59)	84
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax		11	21	(41)
Gains (losses) on derivatives designated as cash flow hedges, net of tax	[2]	20	61	(8)
Reclassification of gains on derivatives designated as cash flow hedges to net earnings, net of tax	[3]	(110)	(42)	(46)
Total items that will be reclassified subsequently to net earnings		(90)	(19)	(11)
Other comprehensive income (loss)		(102)	(45)	4
Total comprehensive income (loss)		(355)	131	(86)
Total comprehensive income (loss) attributable to:
TransAlta shareholders		(439)	54	(210)
Non-controlling interests		$ 84	$ 77	$ 124
[1]	Net of income tax recovery of $3 million for the year ended Dec. 31, 2020 (2019 — $7 million recovery, 2018 — $5 million expense).
[2]	Net of income tax expense of $8 million for the year ended Dec. 31, 2020 (2019 —$16 million expense, 2018 — $1 million recovery).
[3]	Net of reclassification of income tax expense of $31 million for the year ended Dec. 31, 2020 (2019 —$10 million expense,  2018 — $11 million expense).

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of comprehensive income [abstract]
Net actuarial gains (losses)	$ (3)	$ (7)	$ 5
Gain (losses) on derivatives designated as cash flow hedges, income tax expense (recovery)	8	16	(1)
Reclassification of gains on derivatives designated as cash flow hedges to net earnings, income tax expense	$ 31	$ 10	$ 11

Consolidated Statements of Fina

Consolidated Statements of Financial Position - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Assets [abstract]
Cash and cash equivalents	$ 703	$ 411
Restricted cash	71	32
Trade and other receivables	583	462
Prepaid expenses	31	19
Risk management assets	171	166
Inventory	238	251
Assets held for sale	105	0
Current assets	1,902	1,341
Investments	100	0
Long-term portion of finance lease receivable	228	176
Risk management assets	521	640
PP&E	5,822	6,207
Right-of-use assets	141	146
Intangible assets	313	318
Goodwill	463	464
Deferred income tax assets	51	18
Other assets	206	198
Total assets	9,747	9,508
Liabilities [abstract]
Accounts payable and accrued liabilities	599	413
Current portion of decommissioning and other provisions	59	58
Risk management liabilities	94	81
Current contract liabilities	1	1
Income taxes payable	18	14
Dividends payable	59	37
Current portion of long-term debt and finance lease obligations	105	513
Current liabilities	935	1,117
Credit facilities, long-term debt and lease liabilities	3,256	2,699
Exchangeable securities	730	326
Decommissioning and other provisions	614	488
Deferred income tax liabilities	396	472
Risk management liabilities	68	29
Non-current contract liabilities	14	14
Defined benefit obligation and other long-term liabilities	298	301
Equity
Contributed surplus	38	42
Deficit	(1,826)	(1,455)
Accumulated other comprehensive income	302	454
Equity attributable to shareholders	2,352	2,961
Non-controlling interests	1,084	1,101
Total equity	3,436	4,062
Total liabilities and equity	9,747	9,508
Gross carrying amount
Assets [abstract]
PP&E	13,398	13,395
Intangible assets	833	788
Liabilities [abstract]
Accounts payable and accrued liabilities	599
Dividends payable	59
Exchangeable securities	750
Accumulated depreciation
Assets [abstract]
PP&E	(7,576)	(7,188)
Intangible assets	(520)	(470)
Common shares
Equity
Issued capital	2,896	2,978
Preferred shares
Equity
Issued capital	$ 942	$ 942

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
Changes in equity [abstract]
Adjustments on implementation of IFRS 16	$ 3						$ 3					$ 3
Adjusted beginning balance	4,137			$ 3,059	$ 942	$ 11	(1,493)			$ 481		3,000			$ 1,137
Balance, beginning of year at Dec. 31, 2018	4,134			3,059	942	11	(1,496)			481		2,997			1,137
Changes in equity [abstract]
Net earnings (loss)	176						82					82			94
Other comprehensive income (loss)
Net losses on translating net assets of foreign operations, net of hedges and of tax	(38)									(38)		(38)
Net gains on derivatives designated as cash flow hedges, net of tax	19									19		19
Net actuarial losses on defined benefits plans, net of tax	(26)									(26)		(26)
Intercompany FVOCI investments	0									17		17			(17)
Total comprehensive income (loss)	131						82			(28)		54			77
Dividends	(30)	$ (34)	$ (30)					$ (34)	$ (30)				$ (34)	$ (30)
Changes in non-controlling interests in TransAlta Renewables (Note 4(V) and 13)	28						5			1		6			22
Shares purchased under NCIB	(68)			(83)			15					(68)
Effect of share-based payment plans (Note 30)	33			2		31						33
Distributions paid, and payable, to non-controlling interests	(135)														(135)
Balance, end 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 income (loss)
Net gains 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
Total comprehensive income (loss)	(355)						(287)			(152)		(439)			84
Dividends	(49)	$ (58)	$ (49)					$ (58)	$ (49)				$ (58)	$ (49)
Changes in non-controlling interests in TransAlta Renewables (Note 4(V) and 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
[1]	Refer to Note 29 for details on components of, and changes in, accumulated other comprehensive income (loss).

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating activities
Net earnings (loss)	$ (253)	$ 176	$ (90)
Depreciation and amortization	798	709	710
Net gain on sale of assets	(9)	(45)	0
Accretion of provisions	30	23	24
Decommissioning and restoration costs settled	(18)	(34)	(31)
Deferred income tax recovery	(85)	(18)	(34)
Unrealized (gain) loss from risk management activities	42	(32)	30
Unrealized foreign exchange loss	1	13	28
Provisions	9	13	7
Asset impairment charges	84	25	73
Equity income, net of distributions from Joint Ventures	(1)	0	0
Other non-cash items	15	(102)	147
Cash flow from operations before changes in working capital	613	728	864
Change in non-cash operating working capital balances	89	121	(44)
Cash flow from operating activities	702	849	820
Investing activities
Additions to property, plant and equipment	(486)	(417)	(277)
Additions to intangibles	(14)	(14)	(20)
Restricted cash	(39)	34	(35)
Loan receivable	(5)	(10)
Loan receivable			1
Acquisitions, net of cash acquired	(32)	(117)	(30)
Acquisition of investments (Note 10)	(102)	0	0
Investment in the Pioneer Pipeline	0	(83)	(15)
Proceeds on sale of property, plant and equipment	6	13	2
Realized gains on financial instruments	2	3	2
Decrease in finance lease receivable	17	24	59
Other	(12)	23	15
Change in non-cash investing working capital balances	(22)	32	(96)
Cash flow used in investing activities	(687)	(512)	(394)
Financing activities
Net increase (decrease) in borrowings under credit facilities	(106)	(119)	312
Repayment of long-term debt	(489)	(96)	(1,179)
Issuance of long-term debt	753	166	345
Issuance of exchangeable securities	400	350	0
Net proceeds on sale of non-controlling interest in subsidiary	0	0	144
Repurchase of common shares under NCIB	(57)	(68)	(23)
Realized gains on financial instruments	3	0	48
Distributions paid to subsidiaries' non-controlling interests	(97)	(106)	(165)
Decrease in finance lease obligations	(25)	(21)	(18)
Financing fees and other	(11)	(35)	(31)
Change in non-cash financing working capital balances	(13)	0	2
Cash flow from (used in) financing activities	272	(14)	(651)
Cash flow from (used in) operating, investing, and financing activities	287	323	(225)
Effect of translation on foreign currency cash	5	(1)	0
Increase (decrease) in cash and cash equivalents	292	322	(225)
Cash and cash equivalents, beginning of year	411	89	314
Cash and cash equivalents, end of year	703	411	89
Supplemental cash flow information
Cash income taxes paid	36	35	87
Cash interest paid	201	185	188
Common shares
Financing activities
Dividends paid	(47)	(45)	(46)
Preferred shares
Financing activities
Dividends paid	$ (39)	$ (40)	$ (40)

Corporate Information

Corporate Information	12 Months Ended
	Dec. 31, 2020
Corporate Information and Statement of IFRS Compliance [Abstract]
Corporate Information	Corporate Information A. Description of the Business TransAlta Corporation (“TransAlta” or the “Corporation”) was incorporated under the Canada Business Corporations Act in March 1985. The Corporation became a public company in December 1992. Its head office is located in Calgary, Alberta. I. Generation Segments The six generation segments of the Corporation are as follows: Hydro, Wind and Solar, North American Gas, Australian Gas, Alberta Thermal, and Centralia. The Corporation 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 such as system support. Electricity sales made by the Corporation’s commercial and industrial group are assumed to be sourced from the Corporation’s production and have been included in the Alberta Thermal segment. 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. 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 Corporation’s central finance, legal, administrative, corporate development and investor relation functions. Activities and charges directly or reasonably attributable to other segments are allocated thereto. In 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 and assets held for sale, 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 March 2, 2021. C. Basis of Consolidation The consolidated financial statements include the accounts of the Corporation and the subsidiaries that it controls. Control exists when the Corporation 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.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Significant Accounting Policies	Significant Accounting Policies A. Revenue Recognition I. Revenue from Contracts with Customers The majority of the Corporation’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 Corporation 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 Corporation’s performance to date. The Corporation 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 Corporation’s contracts may contain more than one performance obligation. Transaction Price The Corporation 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 Corporation'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 Corporation expects to be entitled to in exchange for transferring the good or service. The Corporation 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 Corporation’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 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 Corporation’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 Corporation receives consideration before the performance obligations have been satisfied. A contract asset is recorded when the Corporation has rights to consideration for the completion of a performance obligation before it has invoiced the customer. The Corporation 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. The Corporation recognizes a significant financing component where the timing of payment from the customer differs from the Corporation’s performance under the contract and where that difference is the result of the Corporation financing the transfer of goods and services. II. Revenue from Other Sources 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 Corporation 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. 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 Corporation 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. Foreign Currency Translation The Corporation, its subsidiary companies and joint arrangements each determine their functional currency based on the currency of the primary economic environment in which they operate. The Corporation’s functional currency is the Canadian dollar, while the functional currencies of its subsidiary companies and joint arrangements are the Canadian, US or Australian dollar. Transactions denominated in a currency other than the functional currency of an entity are translated at the exchange rate in effect on the transaction date. The resulting exchange gains and losses are included in each entity’s net earnings in the period in which they arise. The Corporation’s foreign operations are translated to the Corporation’s presentation currency, which is the Canadian dollar, for inclusion in the consolidated financial statements. Foreign-denominated monetary and non-monetary assets and liabilities of foreign operations are translated at exchange rates in effect at the end of the reporting period, and revenue and expenses are translated at exchange rates in effect on the transaction date. The resulting translation gains and losses are included in other comprehensive income (loss) (“OCI”) with the cumulative gain or loss reported in accumulated other comprehensive income (loss) (“AOCI”). Amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in a foreign net investment as a result of a disposal, partial disposal or loss of control. C. 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 Corporation’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 Corporation 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 Corporation 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 Corporation has made an accounting policy choice to recognize the impacts of the tax attributes in net interest expense. The Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation’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 Corporation 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 Corporation 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 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 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. D. Cash and Cash Equivalents Cash and cash equivalents are comprised of cash and highly liquid investments with original maturities of three months or less. E. Collateral Paid and Received The terms and conditions of certain contracts may require the Corporation or its counterparties to provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may decrease the credit limits granted to the Corporation or its counterparties and accordingly increase the amount of collateral that may have to be provided by the Corporation or its counterparties. F. Inventory I. Fuel The Corporation’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 Corporation 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 Corporation 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 Corporation 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. G. Property, Plant and Equipment The Corporation’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 1-52 years Wind generation 1-29 years Gas generation 1-17 years Coal generation 1-29 years Mining property and equipment 1-9 years Capital spares and other 2-52 years TransAlta capitalizes borrowing costs on capital invested in projects under construction (see Note 2(R)). 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. H. 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, carbon compliance and purchased power in the Consolidated Statements of Earnings (Loss). Amortization commences when the intangible asset is available for use and is computed on a straight-line basis over the intangible asset’s estimated useful life, except for coal rights, which are amortized using a unit-of-production basis, based on the estimated mine reserves. Estimated useful lives of intangible assets may be determined, for example, with reference to the term of the related contract or licence agreement. The estimated useful lives and amortization methods are reviewed annually with the effect of any changes being accounted for prospectively. Intangible assets consist of power sale contracts with fixed prices higher than market prices at the date of acquisition, coal rights, software and intangibles under development. Estimated remaining useful lives of intangible assets are as follows: Software 2-7 years Power sale contracts 1-20 years I. Impairment of Tangible and Intangible Assets Excluding Goodwill At the end of each reporting period, the Corporation 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 Corporation’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 Corporation 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 Corporation’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 “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 Corporation. 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. J. 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 impairmen

Accounting Changes

Accounting Changes	12 Months Ended
	Dec. 31, 2020
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Accounting Changes	Accounting Changes A. Current Accounting Changes I. Amendments to IAS 1 and IAS 8 Definition of Material The Corporation adopted the amendments to IAS 1 and IAS 8 as of Jan. 1, 2020. The amendments provide a new definition of material that states “information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.” The amendments clarify that materiality will depend on the nature or magnitude of information, either individually or in combination with other information, in the context of the financial statements. A misstatement of information is material if it could reasonably be expected to influence decisions made by the primary users. These amendments had no impact on the consolidated financial statements of, nor is there expected to be any future impact to, the Corporation. II. Amendments to IFRS 7 and 9 Interest Rate Benchmark Reform In September 2019, the IASB issued amendments to the IFRS relating to Interest Rate Benchmark Reform - amending IFRS 9, IAS 39 and IFRS 7. These amendments provide temporary relief during the period of uncertainty from applying specific hedge accounting requirements to hedging relationships directly affected by the ongoing interest rate benchmark reforms. These amendments are mandatory for annual periods beginning on or after Jan. 1, 2020. The Corporation adopted these amendments as of Jan. 1, 2020. There were no hedging relationships that were directly affected on Jan. 1, 2020. During the first quarter of 2020, the Corporation entered into cash flow hedges of interest rate risk associated with a future forecasted debt issuance using London Interbank Offered Rate ("LIBOR") based derivative instruments. As a temporary relief, provided by the IFRS 9 amendments, the Corporation has assumed that the LIBOR interest rate on which the cash flows of the interest rate swaps are based is not altered by interbank offered rates ("IBOR") reform when assessing if the hedge is highly effective. III. Change in Estimates Useful Life of PP&E at Alberta Thermal 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 Corporation'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. As at Dec. 31, 2020, the carrying value of the Highvale mine, including PP&E, right-of-use assets and intangible assets, was $373 million, During the third quarter of 2019, the Corporation adjusted the useful lives of certain coal assets, effective Sept. 1, 2019, to reflect the changes announced related to the Clean Energy Investment Plan (see Note 4(A) for further details). As a result, assets used only for coal-burning operations were adjusted to shorten their useful lives whereas other asset lives were extended as they were identified as being used after the coal-to-gas or combined-cycle conversions. Due to the impact of shortening the lives of the coal assets, overall depreciation expense for the year ended Dec. 31, 2019 increased by approximately $16 million. In 2018, as a result of the Off-Coal Agreement (“OCA”) with the Government of Alberta described in Note 9(B), the Corporation adjusted the useful lives of some of its mine assets to align with the Corporation's coal-to-gas conversion plans. As a result, depreciation expense and intangibles amortization for the year ended Dec.31, 2018, increased by $38 million. In the third quarter of 2018, the Corporation retired Sundance Unit 2 and recorded an impairment charge of $38 million for the remaining net book value of the asset. In the third quarter of 2020, the Corporation recognized an impairment on Sundance Unit 3 in the amount of $70 million, due to the Corporation's decision to retire the unit. The retirement decision for Sundance Unit 3 was largely driven by an assessment of future market conditions, the age and condition of the unit, and our ability to supply energy and capacity from our generation portfolio in Alberta. Useful Life of PP&E at Wind and Solar During the third quarter of 2019, the allocation of the costs recognized for the components of the Wind and Solar PP&E and the useful lives for these identified components were reviewed. As a result of the review, additional components were identified for parts where the useful lives are shorter than the original estimate. The useful life of each of these components was reduced from 30 years to either 15 years or 10 years. Accordingly, depreciation expense for the year ended Dec. 31, 2019, increased by approximately $11 million. Sheerness During the second quarter of 2019, the Corporation adjusted the useful life of its Sheerness coal-fired facility assets to align with the dual-fuel conversion plans. As a result, the assets used for coal-burning operations as well as the other asset lives were extended and depreciation expense for the year ended Dec. 31, 2019, decreased by approximately $8 million. The useful lives may be revised or extended in compliance with the Corporation's accounting policies, dependent upon future operating decisions and events. Decommissioning and other provisions In the fourth quarter of 2020, the Corporation adjusted the Sarnia decommissioning and restoration provision to reflect an updated engineering study. The Corporation'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 Corporation 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 Corporation'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. During the third quarter of 2019, the Corporation adjusted the Centralia mine decommissioning and restoration provision as management no longer believed that the fine coal recovery and reclamation work would be completed as originally proposed. At the end of 2019, the Corporation's best estimate of the decommissioning and restoration provision increased by $141 million. Since the Centralia mine is no longer operating and reached the end of its useful life in 2006, this adjustment resulted in the immediate recognition of the full $141 million, through asset impairment in net earnings. B. Future Accounting Changes Amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use The Corporation plans to early adopt the amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use on Jan. 1, 2021. The amendment has a mandatory effective date of Jan. 1, 2022. The amendments prohibit deducting from the cost of an item of property, plant and equipment any proceeds from selling items produced while bringing the asset to the location and condition necessary for it to be capable of operating. No adjustments are expected from early adopting the amendments. IFRS 7 Financial Instruments, Disclosures - Interest Rate Benchmark Reform 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 are effective Jan. 1, 2021, and will be adopted by the Corporation in 2021, no financial impact is expected upon adoption. 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.

Significant and Subsequent Even

Significant and Subsequent Events	12 Months Ended
	Dec. 31, 2020
Significant Events [Abstract]
Significant and Subsequent Events	A. Clean Energy Investment Plan TransAlta's Clean Energy Investment Plan announced in 2019 includes converting our existing Alberta coal assets to natural gas and advancing our leadership position in on-site generation and renewable energy. The Clean Energy Investment Plan provided further details of previously highlighted initiatives that TransAlta has been continuing to progress since early 2017. TransAlta’s Clean Energy Investment Plan includes converting three of our existing Alberta thermal units to gas during 2021 by replacing existing coal burners with natural gas burners. The cost to convert each unit is expected to be approximately $35 million. On Feb. 1, 2021, we announced the completion of the conversion to gas of Sundance Unit 6. The Corporation continues to advance the conversion of its Keephills Unit 2 and Keephills Unit 3 for completion later in 2021 and has issued Full Notice to Proceed for both units. In addition, on April 4, 2020, the dual-fuel conversion of Sheerness Unit 2 was completed. The Sheerness facility will receive it's last coal shipment in the first quarter of 2021, with coal stock being actively depleted until the end of 2021. The elimination of coal as a fuel source will reduce future fuel costs and greenhouse gas ("GHG") costs at Sheerness. The highlights of these gas conversion investments include: ▪ Positioning TransAlta’s fleet as a low-cost generator in the Alberta energy-only market; ▪ Generating attractive returns by leveraging the Corporation’s existing infrastructure; ▪ Significantly extending the life and cash flows of our Alberta thermal assets; and ▪ Significantly reducing air emissions and costs. The Clean Energy Investment Plan also includes repowering the steam turbines at Sundance Unit 5 and, potentially, Keephills Unit 1 by installing one or more combustion turbines and heat recovery steam generators, thereby creating highly efficient combined-cycle units. The repowered units are expected to be a 35 per cent to 45 per cent lower capital investment when compared to a new combined-cycle facility, while achieving a similar heat rate. During the first quarter of 2020, we received regulatory approval from the Alberta Utilities Commission ("AUC") and Alberta Environment and Parks for the repowering of Sundance Unit 5 and Keephills Unit 1 into combined-cycle units. During the fourth quarter of 2020, an equipment supply agreement was executed as part of the strategy to repower Sundance Unit 5 into a highly efficient combined cycle unit. The commercial operation date is anticipated in the fourth quarter of 2023. The Sundance Unit 5 repowered combined-cycle unit will have a capacity of approximately 730 MW and is expected to cost approximately $800 million to $825 million, well below a greenfield combined-cycle project. As part of this transaction, we also acquired a long-term PPA for capacity plus energy, including the passthrough of GHG costs, starting in late 2023 with Shell Energy North America (Canada). The Corporation will continue to evaluate the prospect for the repowering of Keephills Unit 1 in 2021 and 2022, as a supply addition to the Alberta market in the 2026 to 2030 time frame. TransAlta has determined to cease coal-fired operations in Canada by Jan 1, 2022. During the third quarter of 2020, the Board approved the accelerated shutdown of the Highvale mine by the end of 2021, and the useful life of the related assets was adjusted to align with the Corporation's conversion to gas plans. As a result, the Corporation announced that Keephills Unit 1 and Sundance Unit 4 will discontinue firing with coal and will only operate on gas effective Jan. 1, 2022. The maximum capability of these units will be reduced to 70 MW and 113 MW, respectively. As at Dec. 31, 2020, the carrying value of the Highvale mine, including PP&E right-of-use assets and intangible assets, was $373 million. As a result, our cost per tonne of coal will increase as the fixed coal costs will be spread over lower volumes. During the second half of 2020, the increased depreciation expense and our cost per tonne of coal exceeded the net realizable value of the coal inventory and a writedown of $37 million was recognized in fuel, carbon compliance and purchased power. As the Highvale mine moves into the reclamation phase, our anticipated coal consumption is expected to continue to decline, further increasing the cost of coal, and future expected writedowns in fuel costs. In 2020, we started the year with 2.1 million tonnes of coal inventory, during which we mined an additional 2.3 million tonnes and consumed 3.5 million tonnes. We ended the year with approximately 1 million tonnes of coal inventory and we will continue to actively deplete our coal stock as we wind down our mining activity by the end of 2021. The Corporation’s Clean Energy Investment Plan also consists of three wind projects in the United States, one wind project in Alberta and a cogeneration facility that is discussed in more detail later in this section. The Big Level wind project ("Big Level") and Antrim wind project ("Antrim") began commercial operations on Dec. 19, 2019, and Dec, 24, 2019, respectively. The Skookumchuck wind project began commercial operation on Nov. 7, 2020, and was acquired by the Corporation on Nov. 25. 2020. The Windrise wind project ("Windrise") is currently under construction. These projects are underpinned by long-term PPAs with highly creditworthy counterparties. In addition, TransAlta has entered into agreements to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant ("K3"). Please see Note 4(J) for additional details on the current status of the Kaybob cogeneration project. B. Pioneer Pipeline On Dec. 17, 2018, the Corporation exercised its option to acquire 50 per cent ownership in the Pioneer gas pipeline ("Pioneer Pipeline") for $83 million. Tidewater Midstream & Infrastructure Ltd.'s (“TMI”) and TransAlta each own a 50 per cent interest in the Pioneer Pipeline, which is backstopped by a 15-year take-or-pay agreement from TransAlta at market rate tolls. During the fourth quarter of 2019, TransAlta recognized a right-of-use asset and lease liability for the portion of the Pioneer Pipeline that is not directly owned. During 2019, the Pioneer Pipeline transported its first gas four months ahead of schedule to TransAlta's generating units at Sundance and Keephills. The Pioneer Pipeline initially had approximately 50 MMcf/day of natural gas flowing during the start-up phase where initial flows fluctuated depending on market conditions. Firm throughput of approximately 130 MMcf/day of natural gas began flowing through the Pioneer Pipeline on Nov. 1, 2019. The Pioneer Pipeline is held in a separate entity that is a joint operation with TMI. The Corporation 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 within the Alberta Thermal segment. The Pioneer Pipeline is classified as a joint operation, due to the fact that TransAlta is currently the only customer and both parties are providing the only cash flows to fund the operations. On Oct. 1, 2020, TransAlta announced that it had entered into a definitive Purchase and Sale Agreement providing for the sale of its 50 per cent interest in the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. (“ATCO”) (the "Transaction"). The purchase price of $255 million represents both TransAlta's and TMI's interests. This agreement replaces the previous Purchase and Sale agreement to sell the Pioneer Pipeline to NOVA Gas Transmission Ltd. (“NGTL”) from the second quarter of 2020. ATCO acquired the right to purchase the Pioneer Pipeline through an option agreement with NGTL. Following closing of the Transaction, the Pioneer Pipeline will be integrated into NGTL's and ATCO's Alberta integrated natural gas transmission systems to provide reliable natural gas supply to TransAlta's Sundance and Keephills power generating stations. At Dec. 31, 2020, our interest in the Pioneer Pipeline is included in assets held for sale in the Consolidated Statements of Financial Position. In addition, TransAlta has entered into incremental long-term firm natural gas delivery transportation agreements with NGTL for 351 TJ per day, bringing the total long-term firm natural gas transportation contracts up to 400 TJ per day by 2023. TransAlta’s current commitments, including the 139 TJ per day supply arrangement with TMI, will remain in place until the closing of the Transaction. The Transaction is subject to customary regulatory approvals and is anticipated to close during the second quarter of 2021. C. Skookumchuck Wind Project On April 12, 2019, TransAlta signed an agreement with Southern Power Company, a subsidiary of Southern Company, to have the option to purchase a 49 per cent interest in SP Skookumchuck Investments, LLC ("Skookumchuck") with Southern Power upon the facility's commercial operation date. 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 began commercial operation on Nov. 7, 2020. On Nov. 25, 2020, TransAlta completed the acquisition of Skookumchuck. TransAlta's total capital investment was $163 million, with TransAlta paying cash of $86 million (US$66 million) with the remaining $77 million (US$59 million) being funded with tax equity financing. The investment has been classified as a joint venture, as the investment is held in a separate entity and the Corporation has rights to the net assets of Skookumchuck. The Corporation reports its interests in joint arrangements in its consolidated financial statements using the equity method recognizing its share of income (loss) in the Consolidated Statements of Earnings (Loss). The project has a 20-year PPA with Puget Sound Energy. TransAlta has entered into an definitive agreement with TransAlta Renewables to sell the Corporation's interest in Skookumchuck, which is expected to close in April 2021, as further described below in this section. D. WindCharger On Aug. 1, 2020, the WindCharger battery storage project ("WindCharger") was sold to TransAlta Renewables. Wind-Charger has been operational since Oct. 15, 2020 and is the first utility-scale battery energy storage project in Alberta. The WindCharger project has a nameplate capacity of 10 MW with a total storage capacity of 20 MWh. WindCharger is located in southern Alberta in the Municipal District of Pincher Creek next to TransAlta’s existing Summerview wind facility substation. WindCharger stores energy produced by the nearby Summerview II wind facility and discharges it into the Alberta electricity grid at times of peak demand. TransAlta is expected to receive co-funding of almost 50 per cent of the $14 million construction cost from Emissions Reduction Alberta. WindCharger is participating in both the wholesale energy and ancillary services market of the Alberta Electric System Operator ("AESO"). E. Windrise On Dec. 17, 2018, TransAlta's 207 MW Windrise wind project was identified by the AESO as one of the three selected projects in the third round of the Renewable Electricity Program. TransAlta and the AESO subsequently executed a Renewable Electricity Support Agreement with a 20-year term. Windrise is situated on 11,000 acres of land located in the county of Willow Creek, Alberta, and is expected to cost approximately $270 million to $285 million. Windrise has secured approval for the wind facility and transmission line required to connect the facility to the Alberta grid from the AUC. Construction activities on Windrise continue to advance with all appropriate procedures in place to protect the construction team during the COVID-19 pandemic. However as a result of COVID-19 and related delays in construction, the commercial operation date is expected to occur during the second half of 2021. As of Dec. 31, 2020, Windrise was 78 per cent complete. On Feb. 26, 2021, TransAlta Renewables acquired Windrise from the Corporation as described further below. F. Acquisition of Wind Development Projects In 2019, TransAlta acquired a portfolio of wind development projects in the US. If the Corporation decides to move forward with any of these projects, additional consideration may be payable on a project-by-project basis only in the event a project achieves commercial operations prior to Dec. 31, 2025. G. EMG International Acquisition On Nov. 30, 2020, TransAlta acquired a 30 per cent equity interest in EMG to diversify our sustainability offerings to customers while directly supporting our clean energy transition and sustainability goals. 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. EMG’s wastewater treatment process converts organic waste into a valuable source of renewable energy. Their technology produces a biogas stream that can be used as fuel to generate electricity, displacing energy consumed from higher emitting resources. The investment provides a unique opportunity for TransAlta to leverage its vast expertise in on-site generation to support further advancements by EMG in the waste-to-energy space. This investment will advance the Corporation's presence in the US sustainability and on-site generation markets. The investment has been classified as an Investment in associate, as the Corporation owns 30 per cent of the entity and has representation on the management committee. The Corporation reports its investment in associates in its consolidated financial statements using the equity method recognizing its share of income (loss) in the Consolidated Statement of Earnings (Loss). H. TransAlta Renewables Acquisitions On Dec. 23, 2020, the Corporation announced that it had entered into definitive agreements for the acquisition by TransAlta Renewables of its 100 per cent direct interest in the 207 MW Windrise wind project located in the Municipal District of Willow Creek, Alberta; a 49 per cent economic interest in the 137 MW Skookumchuck wind facility located across Thurston and Lewis counties in Washington State; and a 100 per cent economic interest in the 29 MW Ada cogeneration facility located in Ada, Michigan. TransAlta Renewables' acquisition of the Windrise closed on Feb. 26, 2021, and the acquisition of the economic interests in the Ada cogeneration facility and the Skookumchuck wind facility are expected to close in April 2021. The total acquisition value for the portfolio of assets is expected to be $439 million, which includes the remaining construction costs for the Windrise wind project. TransAlta Renewables will fund the acquisition and remaining construction costs with the proceeds from the TEC Hedland financing. Please refer to Note 4(L) for further details. I. BHP Nickel West Contract Extension On Oct. 22, 2020, Southern Cross Energy ("SCE"), a subsidiary of the Corporation, replaced and extended its current PPA with BHP Billiton Nickel West Pty Ltd. ("BHP"). SCE is composed of four generation facilities with a combined capacity of 245 MW in the Goldfields region of Western Australia. The new agreement was effective Dec. 1, 2020, and replaces the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extends the term to Dec. 31, 2038, and provides SCE with the exclusive right to supply thermal and electrical energy from the Southern Cross Facilities for BHP's mining operations located in the Goldfields region of Western Australia. The extension will provide SCE a return on new capital investments, which will be required to support BHP's future power requirements and recently announced emission reduction targets. The amendments within the PPA also provide BHP participation rights in integrating renewable electricity generation, including solar and wind, with energy storage technologies, subject to the satisfaction of certain conditions. Evaluation of renewable energy supply and carbon emissions reduction initiatives under the extended PPA with SCE are underway, including a 18.5MW solar photovoltaic facility supported by a battery energy storage system and a waste heat steam turbine system. For accounting purposes, the original agreement was accounted for as an operating lease. Under the new PPA, the agreement is now accounted for as a finance lease. As a result, we derecognized net assets of $77 million, which includes balances for PP&E, intangible assets, deferred credits and prepaid expenses. In addition, we recognized a finance lease receivable of $89 million and a gain on asset disposition of $12 million. Subsequent to the transaction, the Corporation incurred additional major maintenance costs in relation to these assets which was recorded as a reduction to the gain on asset disposition. J. Agreement to Construct and Own a Cogeneration Plant in Alberta 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 the year and begin construction in December 2020. On Sept. 25, 2020, the AUC released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. We are in ongoing commercial and technical discussions with ET Canada relative to the project at K3, or potentially developing a new project at another site owned and/or operated by ET Canada. K. Acquisition of a Contracted Cogeneration Asset in Michigan On May 19, 2020, the Corporation closed the previously announced 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 ("Ada") in Michigan that is contracted under a PPA and a steam sale agreement for approximately six years with Consumers Energy and Amway. The fair values of the identifiable assets and liabilities of the acquired entity in the business combination as at the date of acquisition were: As at May 19, 2020 Fair value recognized Assets Net working capital 6 Property, plant and equipment 1 Intangible assets (1) 37 Risk management liabilities (current and long-term) (5) Decommissioning provisions (1) Total identifiable net assets at fair value 38 Cash consideration 32 Working capital consideration 6 Total purchase consideration transferred 38 (1) This relates to the power sales contract acquired and will be amortized over six years. L. TEC Hedland Pty Ltd. Secures AU$800 Million Financing On Oct. 22, 2020, TEC Hedland Pty Ltd. ("TEC"), a subsidiary of the Corporation, closed an AU$800 million senior secured note offering ("Offering"), by way of a private placement, which is secured by, among other things, a first ranking charge over all assets of TEC. The Offering bears interest at 4.07 per cent per annum, payable quarterly and maturing on June 30, 2042, with principal payments starting on Mar. 31, 2022. The Offering has a rating of BBB by Kroll Bond Rating Agency. TransAlta Renewables has received $480 million (AU$515 million) of the proceeds from the Offering through the redemption of certain intercompany structures. An additional AU$200 million has been loaned to TransAlta Renewables by TransAlta Energy (Australia) Pty Ltd. ("TEA"), which is a subsidiary of TransAlta. The loan bears interest at 4.32 per cent and will be repaid by Oct. 23, 2022 or on demand. The remaining proceeds from the Offering were set aside for required reserves and transaction costs. TransAlta Renewables used a portion of the proceeds from the redemption and the intercompany loan to repay existing indebtedness on its credit facility and to acquire the asset and economic interests noted above. M. Strategic Investment by Brookfield On March 22, 2019, the Corporation entered into an agreement (the "Investment Agreement") whereby Brookfield Renewable Partners or its affiliates (collectively “Brookfield”) agreed to invest $750 million (the "Investment") in the Corporation through the purchase of exchangeable securities. The securities are exchangeable by Brookfield 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 earnings before interest, taxes, depreciation and amortization ("EBITDA"). 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 consideration for redeemable, retractable first preferred shares. The proceeds from the first tranche were used to accelerate our conversion to gas program. The Corporation intends to use the proceeds from the second tranche of the financing to advance the Corporation’s conversion to gas program, to fund other growth initiatives and for general corporate purposes. Upon entering into the Investment Agreement and as required under the terms of the agreement, the Corporation 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. See Note 25 for further details. In accordance with the terms of the Investment Agreement, TransAlta has formed a Hydro Assets Operating Committee consisting of two representatives from Brookfield and two representatives from TransAlta to collaborate in connection with the operation and maximization of the value of the Alberta Hydro Assets. In connection with this, the Corporation has committed to pay Brookfield an annual fee of $1.5 million for six years beginning May 1, 2019 (the "Brookfield Hydro Fee"), which is recognized in the operations, maintenance and administration expense on the Consolidated Statements of Earnings (Loss). TransAlta has indicated that it intends to return up to $250 million of capital to shareholders through share repurchases within three years of receiving the first tranche of the Investment. As of Dec. 31, 2020, 15,068,900 common shares have been repurchased and $129 million under the normal course issuer bid normal course issuer bid("NCIB") program. Under the terms of the Investment Agreement, Brookfield committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to not less than nine per cent by May 1, 2021. As of Jan. 8, 2021, Brookfield, through its affiliates, held, owned or had control over an aggregate of 33,845,685 common shares, representing approximately 12.4 per cent of the issued and outstanding common shares, calculated on an undiluted basis. In connection with the Investment, Brookfield is entitled to nominate two directors for election to the Board. On April 23, 2019, the Mangrove Partners Master Fund Ltd. ("Mangrove") commenced an action in the Ontario Superior Court of Justice alleging, among other things, oppression by the Corporation and its directors and seeking to set aside the Brookfield Investment Agreement. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter was adjourned due to the COVID-19 pandemic and is now scheduled to proceed to trial for three weeks starting April 19, 2021. Refer to Note 36 for further details. N. Centralia Unit 1 Retirement The Corporation owns a two-unit 1,340 MW thermal coal-fired facility in Centralia, Washington in relation to which we have entered into a number of multiple year medium- and short-term energy sales agreements. In 2011, Washington State passed the TransAlta Energy Transition Bill (chapter 180, Laws of 2011) (the "Bill'') allowing the Centralia thermal facility to comply with the State's GHG emissions performance standards by ceasing coal generation in one of its two boilers by the end of 2020 and the other by the end of 2025. The Bill removed restrictions that had previously been imposed on the facility limiting the duration of new contracts from the facility and limiting the technology that the facility would be required to implement for nitrogen oxide controls. Centralia Unit 1 was retired from service effective Dec. 31, 2020. O. Mothballing of Sundance Units and Sundance Unit 3 Retirement On March 8, 2019, the Corporation announced that the AESO granted an extension to the mothballing of Sundance Units 3 and 5, which are to remain mothballed until Nov. 1, 2021, extended from April 1, 2020. On July 22, 2020, the Corporation announced that it gave notice to the AESO to retire Sundance Unit 3 effective July 31, 2020. The retirement decision was largely driven by TransAlta’s assessment of future market conditions, the age and condition of the unit and our ability to supply energy and capacity from our generation portfolio in Alberta. This decision advances our transition to 100 per cent clean electricity by 2025. The Corporation recognized an impairment charge of approximately $70 million ($52 million after-tax) during the third quarter 2020. P. COVID-19 The World Health Organization declared a Public Health Emergency of International Concern relating to COVID-19 on Jan. 30, 2020, which they subsequently declared, on March 11, 2020, as a global pandemic. The outbreak of COVID-19 has resulted in governments worldwide enacting emergency measures to constrain the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods, self-isolation, physical and social distancing and the closure of non-essential business, have caused significant disruption to businesses globally, which has resulted in an uncertain and challenging economic environment. The Corporation continued to operate under its business continuity plan, which focused on ensuring that: (i) employees who could work remotely did so; and (ii) employees who operate and maintain our facilities, and who were not able to work remotely, were able to work safely and in a manner that ensured they remained healthy. During the second and third quarters of 2020, the Corporation successfully brought employees who were working remotely back to the office without compromising health and safety standards. In November 2020, as a result of rising COVID-19 case counts in the Province of Alberta and in light of office attendance restrictions eventually imposed by the Government of Alberta, staff at TransAlta's head office returned to remote work protocols. All of TransAlta's offices and sites follow strict health screening and social distancing protocols with personal protective equipment readily available and in use. Further, TransAlta maintains travel bans aligned to local jurisdictional guidance, enhanced cleaning procedures, revised work schedules, contingent work teams and the reorganization of processes and procedures to limit contact with other employees and contractors on-site. While our financial results have been impacted by price and demand as a result of COVID-19, all of our facilities continue to remain fully operational and capable of meeting our customers' needs. The Corporation continues to work and serve all of our customers and counterparties under the terms of their contracts. We have not experienced interruptions to service requirements. Electricity and steam supply continue to remain a critical service requirement to all of our customers and have been deemed an essential service in our jurisdictions. During the second quarter of 2020, the Government of Canada passed the Canada Emergency Wage Subsidy as part of its COVID-19 Economic Response Plan. The program's intent is to support employment by providing expense relief to companies that experienced revenue declines in 2020. In January 2021, TransAlta applied for support under this program and expects to receive $8 million (pre-tax) for application periods in 2020. This represents a portion of the funding that the Corporation is eligible for and will be used in supporting a strategy to add incremental employment within the Corporation. Q. Normal Course Issuer Bid 2020 On May 26, 2020, the Corporation announced that the Toronto Stock Exchange ("TSX") accepted the notice filed by the Corporation to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, the Corporation may repurchase up to a maximum of 14,000,000 common Shares, representing approximately 7.02 per cent of its public float of common shares as at May 25, 2020. 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 the Corporation is authorized to make purchases under the NCIB commenced on May 29, 2020, and ends on May 28, 2021, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Corporation’s election. Under TSX rules, not more than 228,157 common shares (being 25 per cent of the average daily trading volume on the TSX of 912,630 common shares for the six months ended April 30, 2020) can be purchased on the TSX on any single trading day under the NCIB, with the exception that one block purchase in excess of the daily maximum is permitted per calendar week. During the year ended Dec. 31, 2020, under the current and previous NCIB, the Corporation purchased and cancelled a total of 7,352,600 common shares at an average price of $8.33 per common share, for a total cost of $61 million. See Note 27 for further details. 2019 On May 27, 2019, the Corporation announced that the TSX accepted the notice filed by the Corporation to implement a NCIB for a portion of its common shares. Pursuant to such NCIB, the Corporation was permitted to repurchase up to a maximum of 14,000,000 common shares, representing approximately 4.92 per cent of issued and outstanding common shares as at May 27, 2019. During the year ended Dec. 31, 2019, the Corporation purchased and cancelled a total of 7,716,300 common shares at an average price of $8.80 per common share, for a total cost of $68 million. See Note 27 for further details. 2018 On March 9, 2018, the Corporation announced that the TSX accepted the notice filed by the Corporation to implement an NCIB for a portion of its common shares. Pursuant to such NCIB, the Corporation was permitted to repurchase up to a maximum of 14,000,000 common shares, representing approximately 4.86 per cent of issued and outstanding common shares as at March 2, 2018. During the year ended Dec. 31, 2018, the Corporation purchased and cancelled a total of 3,264,500 common shares at an average price of $7.02 per common share, for a total cost of $23 million. R. TransAlta and Capital Power Swap Non-Operating Interests in Keephills 3 and Genesee 3 On Oct. 1, 2019, the Corporation closed a transaction with Capital Power Corporation ("Capital Power") to swap TransAlta's 50 per cent ownership interest in the 466 MW Genesee 3 facility for Capital Power's 50 per cent ownership interest in the 463 MW Keephills 3 facility. As a result, TransAlta now owns 100 per cent of the Keephills 3 facility and Capital Power owns 100 per cent of the Genesee 3 facility. The transaction price for each non-operating interest largely offset each other, resulting in a net payment of approximately $10 million from Capital Power to TransAlta. Final working capital true-ups and settlements occurred in November 2019, with a net working capital difference of less than $1 million paid by TransAlta to Capital Power. In 2019, the Corporation early-adopted 2020 amendments to IFRS 3 Business Combinations , which introduce an optional fair value concentration test. The Corporat

Revenue

Revenue	12 Months Ended
	Dec. 31, 2020
Disclosure of revenue from contracts with customers [Abstract]
Revenue	Revenue A. Disaggregation of Revenue The majority of the Corporation'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 Corporation disaggregates into the following groups for the purpose of determining how economic factors affect the recognition of revenue. Year ended Dec. 31, 2020 Hydro Wind North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate and Other Total Revenues from contracts with 141 261 196 90 325 10 — — 1,023 Revenue from leases (3) — — 8 60 55 — — — 123 Revenue from derivatives and — (2) 4 — (12) 283 122 12 407 Government incentives 1 4 — — — — — — 5 Revenue from other (4) 10 66 9 8 251 204 — (5) 543 Total revenue 152 329 217 158 619 497 122 7 2,101 Revenues from contracts with customers Timing of revenue recognition At a point in time — 25 — — 23 10 — — 58 Over time 141 236 196 90 302 — — — 965 Total revenue from contracts 141 261 196 90 325 10 — — 1,023 (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. In addition, during the third quarter of 2020, merchant revenue within this segment was reclassified from revenue from contracts with customers to revenue from other and prior periods were adjusted. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. (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 and other miscellaneous. Year ended Dec. 31, 2019 Hydro Wind North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate and Other Total Revenues from contracts with 142 244 190 87 395 10 — — 1,068 Revenue from leases (3) — — — 65 65 — — — 130 Revenue from derivatives and — 18 2 — (17) 160 129 4 296 Government incentives — 8 — — — — — — 8 Revenue from other (4) 14 42 17 8 373 401 — (10) 845 Total revenue 156 312 209 160 816 571 129 (6) 2,347 Revenues from contracts with customers Timing of revenue recognition At a point in time — 27 — — 41 10 — — 78 Over time 142 217 190 87 354 — — — 990 Total revenue from contracts with customers 142 244 190 87 395 10 — — 1,068 (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. In addition, during the third quarter of 2020, merchant revenue within this segment was reclassified from revenue from contracts with customers to revenue from other and prior periods were adjusted. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. (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 and other miscellaneous. Year ended Dec. 31, 2018 Hydro Wind and North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate Total Revenues from contracts with 132 206 206 91 517 9 — — 1,161 Revenue from leases (3) 7 27 — 68 68 — — — 170 Revenue from derivatives and — (20) 4 — (1) 115 67 — 165 Government incentives — 16 — — — — — — 16 Revenue from other (4) 17 53 22 6 328 318 — (7) 737 Total revenue 156 282 232 165 912 442 67 (7) 2,249 Revenues from contracts with customers Timing of revenue recognition At a point in time — 18 — — 38 9 — — 65 Over time 132 188 206 91 479 — — — 1,096 Total revenue from contracts with customers 132 206 206 91 517 9 — — 1,161 (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. In addition, during the third quarter of 2020, merchant revenue within this segment was reclassified from revenue from contracts with customers to revenue from other and prior periods were adjusted. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. (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 and other miscellaneous. B. Contract Liabilities The Corporation has recognized the following revenue-related contract liabilities: Contract liabilities 2020 2019 Balance, beginning of the year 15 88 IFRS 16 transition adjustments (1) — 15 Amounts transferred to revenue included in opening balance (1) (10) Consideration received 1 5 Increases due to interest accrued and expensed during the period — 5 Contract termination associated with the purchase of Keephills 3 (Note 4(R)) — (88) Consideration paid 2 — Performance obligations satisfied (2) — Balance, end of year 15 15 Current portion 1 1 Long-term portion 14 14 (1) In 2019, on transition to IFRS 16, some contracts that were previously considered leases under IAS 17 did not meet the definition of a lease under IFRS 16 and therefore were assessed under IFRS 15 and balances were transferred from deferred revenue to contract liabilities. The opening contract liabilities in 2019 were primarily comprised of consideration received from the Corporation’s Keephills 3 joint operation partner, Capital Power, for which the Corporation had a future obligation to transfer goods and services to Capital Power under the contract. On closing of the Keephills 3 and Genesee 3 swap, wherein the Corporation acquired Capital Power's 50 per cent ownership interest in Keephills 3 and sold its 50 per cent ownership interest in Genesee 3, the agreement with Capital Power was terminated in 2019 and the Corporation no longer had any further performance obligations and the related contract liability balance was recognized in net earnings. The remaining contract liabilities outstanding at Dec. 31, 2020, and Dec. 31, 2019, primarily relate to prepayments relating to the Corporation's New Richmond and Bone Creek facilities where the Corporation still has to fulfil its performance obligations. 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 following practical expedients: ▪ The Corporation recognizes revenue from the contract in an amount that is equal to the amount invoiced where the amount invoiced represents the value to the customer of the service performed to date. Certain of the Corporation’s contracts at some of its wind, hydro, gas and solar facilities, and within its commercial and industrial business, qualify for this practical expedient. For these contracts, the Corporation is not required to disclose information about the remaining unsatisfied performance obligations. ▪ Contracts with an original expected duration of less than 12 months. Additionally, in many of the Corporation’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 Corporation’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. Further, adjustments to revenue to recognize a significant financing component in a contract are not included in the amounts disclosed for remaining performance obligations. 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 Corporation from its contractual portfolio. Hydro At Dec. 31, 2020, the Corporation's PPA with the Balancing Pool to provide the capacity of 12 hydro facilities throughout the province of Alberta concluded. Future production will be sold into the merchant market. The Corporation has contracts for blackstart services at specific hydro facilities, which will conclude at the end of 2030. The Corporation also has a contract with the Government of Alberta to manage water on the Bow River for flood and drought mitigation purposes, which concludes in 2021. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2020, are approximately $31 million, which the Corporation expects to recognize approximately $8 million in 2021 and approximately $2 million to $3 million annually from 2022-2030. The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount invoiced is applied to all hydro energy contracts in Ontario, British Columbia and Washington; accordingly, disclosures related to remaining performance obligations are not provided for these contracts. Wind and Solar At Dec. 31, 2020, the Corporation 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 Corporation expects to recognize such amounts as revenue as it delivers electricity over the remaining terms of the contracts, until 2024, 2034 and 2033, respectively. Electricity delivered is ultimately dependent upon the wind resource, which is outside of the Corporation’s control. Amounts delivered, and therefore revenue recognized, in the future will vary. These variable revenues for electricity delivered are considered to be fully constrained, and will be recognized over time as the performance obligation, the delivery of electricity, is satisfied. Accordingly, these revenues are excluded from these disclosures. The Corporation 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 2020 through 2024. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2020, are approximately $13 million, of which the Corporation expects to recognize between approximately $2 million to $5 million annually through to contract expiry. The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount invoiced is applied to wind energy contracts in Ontario, New Brunswick, Quebec and Wyoming, and for all solar contracts; accordingly, disclosures related to remaining performance obligations are not provided for these contracts. North American Gas At Dec. 31, 2020, the Corporation 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 Corporation to stand ready to deliver electricity and steam. A summary of the key terms of these contracts is set out below. The energy supply agreements require specified amounts of steam to be delivered to each customer, and have pricing terms that include fixed and variable charges for electricity, capacity and steam, as well as a true-up based on contractual minimum volumes of steam. The steam reconciliation is based on an estimate of the customer’s steam volume taken and the contractual minimum volume, and various factors including the annual average market price of electricity and the average locally posted and index prices of natural gas, as well as transportation. For steam volumes not taken by the customer, a revenue-sharing mechanism provides for sharing of revenues earned by the Corporation using that steam to generate and sell electricity. Capacity and electricity pricing vary from contract to contract and are subject to annual indexation at varying rates. Electricity and steam delivered is ultimately dependent upon customer requirements, which is outside of the Corporation’s control. The variable revenues under the contracts are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Corporation expects to recognize revenue as it delivers electricity and steam until the completion of the contract in late 2022. At the same gas facility, the Corporation 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 Corporation’s control and are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Corporation 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, 2020, the Corporation had contracts with customers to deliver steam, hot water and chilled water from one of its other gas facilities in Ontario, extending through 2023. Prices under these contracts are at fixed base amounts per gigajoule and are subject to escalation annually for both gas prices and inflation. The contracts include minimum annual take-or-pay volumes. The Corporation's contract with its customer for provision of steam and electricity output at its Alberta cogeneration facility, effective Jan. 1, 2020 through Dec. 31, 2029, 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 thus are variable in nature and are considered to be fully constrained and excluded from these disclosures. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2020, are approximately $13 million in total, of which the Corporation expects to recognize between approximately $4 million to $5 million annually for the duration of the contracts. The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount invoiced is applied to some of the Corporation’s other gas facilities’ contracts in Ontario and the United States; accordingly, disclosures related to remaining performance obligations are not provided for these contracts. Australian Gas At Dec. 31, 2020, the Corporation 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. Prices may be subject to true-up adjustments for deviations from expected heat rates and are subject to various escalators to reflect inflation. Electricity delivered is ultimately dependent upon customer requirements, which is outside of the Corporation’s control. These variable revenues for electricity delivered are considered to be fully constrained, and will be recognized at a point in time as the performance obligation, the delivery of electricity, is satisfied. Accordingly, these revenues are excluded from these disclosures. The contracts have durations that range from 2026 to 2042. One of the Corporation's PPA with its customer 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. The Corporation also earns revenues from providing operation and maintenance services for the facility for a fixed monthly fee. Pricing is subject to periodic review under the PPA and subject to escalation to reflect inflation out to the end of the contract in 2038. Other revenue streams are based on cost-recovery mechanisms and thus are variable in nature and considered to be fully constrained and excluded from these disclosures. Estimated future revenues related to the remaining performance obligations for these contracts as at Dec. 31, 2020, are approximately $2,594 million, of which the Corporation expects to recognize approximately $203 million in total over the next two fiscal years and on average, between approximately $100 million to $126 million annually thereafter for the duration of the remaining contract. Alberta Thermal At Dec. 31, 2020, the Corporation's PPAs with the Balancing Pool for capacity and electricity from two of its coal facilities concluded. Future production will be sold into the merchant market. The Corporation also has several contracts for sale of byproducts of coal combustion from certain of its coal facilities. The contracts range in duration from one The Corporation has a contract, commencing in late 2023, for the sale of capacity and electricity, exercisable at the option of the customer, under which the Corporation 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, 2020, are approximately $336 million, of which the Corporation 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. Centralia The Corporation’s long-term contract for the sale of electricity produced at its US Coal plant is considered a derivative and is designated as an all-in-one hedge. Accordingly, while revenues for electricity delivered to the customer are recognized pursuant to the contractual terms, the revenues are not accounted for under IFRS 15 and the contract has been excluded from any required IFRS 15 disclosures. The Corporation also has a contract for the sale of byproducts of coal combustion from its US Coal plant. Generally, revenues vary based on market prices that are subject to factors outside of the Corporation’s control, and the quantities delivered and sold, which are ultimately dependent upon customer demand. These variable revenues are considered to be fully constrained, and will be recognized at a point in time as the performance obligation, the delivery of byproducts, is satisfied. Accordingly, these revenues are excluded from these disclosures.

Expenses by Nature

Expenses by Nature	12 Months Ended
	Dec. 31, 2020
Analysis of income and expense [abstract]
Expenses by Nature	Expenses by Nature Expenses classified by nature are as follows: Year ended Dec. 31 2020 2019 2018 Fuel, carbon compliance and Operations, Fuel, carbon compliance and Operations, Fuel, carbon compliance and Operations, Fuel and carbon compliance 574 — 669 — 656 — Coal inventory writedown (Note 17) 37 — — — — — Purchased power 163 — 246 — 210 — Mine depreciation 144 — 119 — 136 — Salaries and benefits 50 235 52 228 98 245 Other operating expenses — 237 — 247 — 270 Total 968 472 1,086 475 1,100 515

Asset Impairment Charges and Re

Asset Impairment Charges and Reversals	12 Months Ended
	Dec. 31, 2020
Disclosure of impairment of assets [Abstract]
Asset Impairment Charges and Reversals	Asset Impairment and Reversals As part of the Corporation’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 Corporation 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 Corporation 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 Corporation’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to the Corporation’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 2073. A. 2020 Sundance Unit 3 In the third quarter of 2020, the Corporation recognized an impairment on Sundance Unit 3 in the amount of $70 million in the Alberta Thermal segment, due to the Corporation's decision to retire the unit (see Note 4(O)). Previously, the Corporation had expected Sundance Unit 3 to remain mothballed until November 2021. 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 recoverable value of the scrap materials. BC Hydro Facility In the third quarter of 2020, the Corporation recorded an impairment of $2 million in the Hydro segment, due to a review of water resources that resulted in a revision to the forecasted production at a BC hydro facility. The impairment assessment was based on fair value less costs of disposal using discounted cash flow projections based on the Corporation's long-range forecasts. The resulting fair value measurement is categorized as a Level III fair value measurement. The key assumptions impacting the determination of fair value are electricity production and sales prices, which are subject to measurement uncertainty. Centralia Land In the fourth quarter of 2020, the Corporation recognized an impairment of $9 million (US$7 million) in the Centralia segment due to a decrease in the fair value of the land determined through a third-party appraiser. In addition to the asset impairments noted above, a net asset impairment of $3 million was recognized for changes in the decommissioning and restoration liabilities related to the Centralia mine and Sundance Unit 1, which are no longer operating and have reached the end of their useful lives (see Note 23). B. 2019 Centralia Thermal Facility In 2012, the Corporation recorded an impairment of $347 million relating to the Centralia thermal facility CGU. As part of the annual impairment test, the Corporation considers possible indicators of impairment at the Centralia thermal facility CGU. 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 full recoverability test in 2019. The updated fair value included sustained changes in the power price market and cost of coal due to contract renegotiations. As a result of the recoverability test, an impairment reversal of $151 million was recorded in the Centralia segment. The valuations are categorized as Level III fair value measurements and subject to measurement uncertainty based on the key assumptions outlined below, and on inputs to the Corporation’s long-range forecast, including changes to fuel costs, operating costs, capital expenses and the level of contractedness under the Memorandum of Agreement ("MOA") for coal transition established with the State of Washington. The valuation period includes cash flows until the decommissioning of the facility in 2025. The Corporation utilized the Corporation's long-range forecast and the following key assumptions in 2019 compared with 2016 assumptions, which was the most recent detailed valuation: 2019 2016 Mid-Columbia annual average power prices US$30 to US$42 per MWh US$22 to US$46 per MWh On-highway diesel fuel on coal shipments US$2.35 to US$2.40 per gallon US$1.69 to US$2.09 per gallon Discount rates 5.2 to 6.4 per cent 5.4 to 5.7 per cent During 2019, the Corporation adjusted the Centralia mine decommissioning and restoration provision as management no longer believes that the fine coal recovery and reclamation work will occur as originally proposed. At the end of 2019, the Corporation's best estimate of the decommissioning and restoration provision increased by $141 million. Since the Centralia mine is no longer operating and reached the end of its useful life in 2006, this adjustment results in the immediate recognition of the full $141 million, through asset impairment charges in net earnings. Refer to Note 3(A)(III) and 23 for further details on the Centralia mine decommissioning and restoration provision. Assets Held for Sale In the fourth quarter of 2019, the Corporation identified several trucks and associated inventory to be sold within the Alberta Thermal segment and accordingly wrote the assets down to net realizable value, resulting in an impairment charge of $15 million. C. 2018 Sundance Unit 2 In the third quarter of 2018, the Corporation recognized an impairment charge on Sundance Unit 2 in the amount of $38 million, due to the Corporation’s decision to retire Sundance Unit 2. Previously, the Corporation had expected Sundance Unit 2 to remain mothballed for a period of up to two years and therefore remain within the Alberta merchant CGU. The impairment assessment was based on value in use and included the estimated future cash flows expected to be derived from the unit until its retirement on July 31, 2018. Discounting did not have a material impact. Lakeswind and Kent Breeze On May 31, 2018, TransAlta Renewables acquired an economic interest in Lakeswind through the subscription of tracking preferred shares of a subsidiary of the Corporation and also purchased Kent Breeze (see Note 4(V)). In connection with these acquisitions, the assets were fair valued using discount rates that average approximately seven per cent. Accordingly, the Corporation has recorded an impairment of $12 million using the valuation in the agreement as the indicator of fair value less cost of disposal in 2018. The impairment charge had an $11 million impact on PP&E and a $1 million impact on intangible assets (refer to Note 18 and 20). D. Project Development Costs

Finance Lease Receivables

Finance Lease Receivables	12 Months Ended
	Dec. 31, 2020
Disclosure of maturity analysis of finance lease payments receivable [abstract]
Finance Lease Receivables	Finance Lease Receivables Amounts receivable under the Corporation’s finance leases associated with the Poplar Creek cogeneration facility and in 2020, the Southern Cross Energy facilities are as follows: As at Dec. 31 2020 2019 Minimum Present value of Minimum Present value of Within one year 63 56 20 20 Second to fifth years inclusive 169 126 80 74 More than five years 100 82 120 97 332 264 220 191 Less: unearned finance lease income 68 — 29 — Total finance lease receivables 264 264 191 191 Included in the Consolidated Statements of Financial Position as: Current portion of finance lease receivables (Note 14) 36 15 Long-term portion of finance lease receivables 228 176 264 191

Net Other Operating Income

Net Other Operating Income	12 Months Ended
	Dec. 31, 2020
Analysis of income and expense [abstract]
Net Other Operating Income	Net Other Operating Income Net other operating income includes the following: Year ended Dec. 31 2020 2019 2018 Coal supply agreement 29 — — Alberta Off-Coal Agreement (40) (40) (40) Insurance recoveries — (10) (7) Other expenses — 1 — Net other operating income (11) (49) (47) A.Onerous Contract Provision for Coal Supply Agreement During the fourth quarter of 2020, an onerous contract provision of $29 million was recognized as a result of a decision to accelerate our plans to eliminate coal as a fuel source by the end of 2021 at the Sheerness facility. The last coal shipment is expected to be received during the first quarter of 2021, while payments required under the contract will continue until 2025. B. Alberta Off-Coal Agreement The Corporation receives payments from the Government of Alberta for the cessation of coal-fired emissions from its interest in the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030. The swap of ownership interests in Keephills 3 and Genesee 3 did not impact the payments received. Refer to Note 4(R) for further details. Under the terms of the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million ($37 million, net to the Corporation), which commenced Jan. 1, 2017, and will terminate at the end of 2030. The Corporation 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. 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 Corporation obtained financing against the OCA payments. Refer to Note 4(X) and 24 for further details. C. Insurance Recoveries There were no insurance recoveries in 2020. During 2019, the Corporation received $10 million in insurance recoveries, which related to insurance proceeds for tower fires at Wyoming and Summerview.

Investments

Investments	12 Months Ended
	Dec. 31, 2020
Interests In Other Entities [Abstract]
Investments	Investments The Corporation’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 (1) 86 16 102 Equity income 1 — 1 Change in foreign exchange rates (2) (1) (3) Balance, Dec. 31, 2020 85 15 100 (1) Contributions were paid in US dollars and were US$66 million for Skookumchuck and US$12 million for EMG, including contingent consideration. Summarized financial information on the results of operations relating to the Corporation’s pro-rata interests in Skookumchuck and EMG is as follows: Year ended Dec. 31 2020 Results of operations Revenues 3 Expenses (2) Proportionate share of net earnings 1 On Nov. 25, 2020, TransAlta purchased a 49 per cent interest in Skookumchuck, a 136.8 MW wind facility located in Lewis and Thurston counties near Centralia in Washington state consisting of 38 Vestas 136 wind turbines. Summarized financial information relating to 100 per cent of Skookumchuck, including adjustments for the application of consistent accounting policies and the Corporation’s purchase price adjustments, is as follows: Year ended Dec. 31 2020 Revenues 6 Depreciation and amortization 2 Interest expense 1 Net earnings 3 Other comprehensive loss — Total comprehensive loss 3 As at Dec. 31 2020 Current assets 6 Non-current assets 382 Current liabilities (65) Non-current liabilities (150) Net assets 173 Additional items included above Cash and cash equivalents 1 Current financial liabilities (1) (27) Non-current financial liabilities (1) (147) (1) Excludes trade and other payables and provisions. A reconciliation of the carrying amount to the Corporation’s 49 per cent interest in the Skookumchuck is as follows: As at Dec. 31 2020 Net assets 173 Less: 51 per cent of Skookumchuck net assets not owned by the Corporation (88) Net investment 85 Skookumchuck’s ability to make distributions to its owners, including the Corporation, is dependent on available cash flow and is restricted by covenants and conditions, including principal and interest funding requirements imposed by the tax equity financing agreements. Skookumchuck's approximate future payments under contractual commitments are as follows: 2021 2022 2023 2024 2025 2026 and thereafter Total Long-term service agreements (1) 1 1 1 1 1 28 33 (1) Refer to Note 36 for further details on long-term service agreements. Joint arrangements at Dec. 31, 2020, included the following: Joint operations Segment Ownership (per cent) Description Sheerness Alberta Thermal 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 Pioneer Pipeline Alberta Thermal 50 Natural gas pipeline in Alberta operated by TMI Goldfields Power Australian Gas 50 Gas-fired facility in Australia operated by TransAlta Fort Saskatchewan North American Gas 60 Cogeneration facility in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta Fortescue River Australian 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 ventures 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, 2020
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 2020 2019 2018 Interest on debt 158 161 184 Interest on exchangeable securities (Note 25) 34 20 — Interest income (10) (13) (11) Capitalized interest (Note 18) (8) (6) (2) Loss on redemption of bonds (Note 24) — — 24 Interest on lease liabilities 8 4 3 Credit facility fees, bank charges and other interest 18 15 13 Tax shield on tax equity financing (Note 24) (1) 1 (35) — Interest on line loss rule proceeding (Note 36(I)(I)) 5 — — Other (2) 2 10 15 Accretion of provisions (Note 23) 30 23 24 Net interest expense 238 179 250 (1) 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 investment is treated as debt under IFRS and the monetization of the tax depreciation is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Taxes [Abstract]
Income Taxes	Income Taxes A. Consolidated Statements of Earnings I. Rate Reconciliations Year ended Dec. 31 2020 2019 2018 Earnings (loss) before income taxes (303) 193 (96) Net earnings (loss) attributable to non-controlling interests not subject to tax 2 (26) (19) Adjusted earnings (loss) before income taxes (301) 167 (115) Statutory Canadian federal and provincial income tax rate (%) 24.5 % 26.5 % 26.8 % Expected income tax expense (recovery) (74) 44 (31) Increase (decrease) in income taxes resulting from: Differences in effective foreign tax rates 3 5 (3) Deferred income tax expense related to temporary difference on investment in 9 — — Writedown (reversal of writedown) of deferred income tax assets 8 (9) 27 Statutory and other rate differences (7) (31) — Other 11 8 1 Income tax expense (recovery) (50) 17 (6) Effective tax rate (%) 17 % 10 % 5 % II. Components of Income Tax Expense The components of income tax expense are as follows: Year ended Dec. 31 2020 2019 2018 Current income tax expense 35 35 28 Deferred income tax expense (recovery) related to the origination and reversal of (95) 22 (61) Deferred income tax expense related to temporary difference on investment in 9 — — Deferred income tax recovery resulting from changes in tax rates or laws (1) (7) (31) — Deferred income tax expense (recovery) arising from the writedown (reversal of writedown) of deferred income tax assets (2) 8 (9) 27 Income tax expense (recovery) (50) 17 (6) Year ended Dec. 31 2020 2019 2018 Current income tax expense 35 35 28 Deferred income tax recovery (85) (18) (34) Income tax expense (recovery) (50) 17 (6) (1) In 2020 the Corporation recognized a deferred income tax recovery of $7 million (2019 —$31 million) related to a decrease in the Alberta corporate tax rate from 11 per cent to 8 per cent. The tax decrease was originally scheduled as follows: 11 per cent effective July 1, 2019, 10 per cent effective Jan. 1, 2020, 9 per cent effective Jan. 1, 2021, and 8 per cent effective Jan. 1, 2022. The Government of Alberta enacted the rate to decrease to 8 per cent effective Dec. 9, 2020. (2) During the year ended Dec. 31, 2020, the Corporation recorded a writedown of deferred tax assets of $8 million (2019 — $9 million writedown reversal, 2018 — $27 million writedown). 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 Corporation’s directly owned US operations. The Corporation evaluates at each period end, whether it is probable that sufficient future taxable income would be available from the Corporation’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 2020 2019 2018 Income tax expense (recovery) related to: Net impact related to cash flow hedges (23) 6 (12) Net actuarial gains (losses) (3) (7) 5 Income tax expense reported in equity (26) (1) (7) C. Consolidated Statements of Financial Position Significant components of the Corporation’s deferred income tax assets (liabilities) are as follows: As at Dec. 31 2020 2019 Net operating loss carryforwards (1) 469 494 Future decommissioning and restoration costs 140 122 Property, plant and equipment (717) (828) Risk management assets and liabilities, net (107) (141) Employee future benefits and compensation plans 62 56 Interest deductible in future periods 22 42 Foreign exchange differences on US-denominated debt 31 40 Other deductible temporary differences 2 4 Net deferred income tax liability, before writedown of deferred income tax assets (98) (211) Writedown of deferred income tax assets (247) (243) Net deferred income tax liability, after writedown of deferred income tax assets (345) (454) (1) Net operating losses expire between 2029 and 2039. The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows: As at Dec. 31 2020 2019 Deferred income tax assets (1) 51 18 Deferred income tax liabilities (396) (472) Net deferred income tax liability (345) (454) (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 Corporation’s long-range forecasts. D. Contingencies As of Dec. 31, 2020, the Corporation had recognized a net liability of nil (2019 —

Non-Controlling Interests

Non-Controlling Interests	12 Months Ended
	Dec. 31, 2020
Interests In Other Entities [Abstract]
Non-Controlling Interests	Non-Controlling Interests The Corporation’s subsidiaries and operations that have non-controlling interests are as follows: Subsidiary/Operation Non-controlling interest as at Dec. 31, 2020 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 Corporation. 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. On May 31, 2018, TransAlta Renewables implemented a dividend reinvestment plan ("DRIP") for Canadian holders of common shares of TransAlta Renewables. Commencing with the dividend paid on July 31, 2018, eligible shareholders could elect to automatically reinvest monthly dividends into additional common shares of the Corporation. The Corporation does not participate in the DRIP. In the fourth quarter of 2020, TransAlta Renewables suspended the DRIP in respect of any future declared dividends. The dividend paid on Oct. 30, 2020, to shareholders of record on Oct. 15, 2020, was the last dividend payment eligible for reinvestment by participating shareholders. Subsequent dividends will be paid only in cash. As a result of the DRIP and the Share Offering described in Note 4(W), the Corporation’s share of ownership and equity participation in TransAlta Renewables has changed as follows: Period Ownership and voting Equity participation Aug. 1, 2017 to June 21, 2018 64.0 64.0 June 22, 2018 to July 30, 2018 61.1 61.1 July 31, 2018 to Nov. 29, 2018 61.0 61.0 Nov. 30, 2018 to Dec. 31, 2018 60.9 60.9 Jan. 1, 2019 to Mar. 31, 2019 60.8 60.8 April 1, 2019 to June 30, 2019 60.6 60.6 July 1, 2019 to Sept. 30, 2019 60.5 60.5 Oct. 1, 2019 to Dec. 31, 2019 60.4 60.4 Jan. 1, 2020 to Mar. 31, 2020 60.3 60.3 April 1, 2020 to June 30, 2020 60.2 60.2 July 1, 2020 to Dec. 31, 2020 60.1 60.1 Year ended Dec. 31 2020 2019 2018 Revenues 436 446 462 Net earnings 97 183 241 Total comprehensive income 223 138 281 Amounts attributable to the non-controlling interests: Net earnings 40 73 94 Total comprehensive income 90 56 110 Distributions paid to non-controlling interests 80 69 79 As at Dec. 31 2020 2019 Current assets 743 293 Long-term assets 2,913 3,409 Current liabilities (364) (152) Long-term liabilities (987) (1,237) Total equity (2,305) (2,313) Equity attributable to non-controlling interests (948) (941) Non-controlling interests’ share (per cent) 39.9 39.6 B. TA Cogen Year ended Dec. 31 2020 2019 2018 Results of operations Revenues 146 181 185 Net earnings (loss) (13) 43 29 Total comprehensive income (loss) (13) 43 29 Amounts attributable to the non-controlling interest: Net earnings (loss) (6) 21 14 Total comprehensive income (loss) (6) 21 14 Distributions paid to Canadian Power Holdings Inc. 17 37 86 As at Dec. 31 2020 2019 Current assets 69 41 Long-term assets 323 328 Current liabilities (78) (27) Long-term liabilities (37) (19) Total equity (277) (323) Equity attributable to Canadian Power Holdings Inc. (136) (160) Non-controlling interest share (per cent) 49.99 49.99

Trade and Other Receivables

Trade and Other Receivables	12 Months Ended
	Dec. 31, 2020
Subclassifications of assets, liabilities and equities [abstract]
Trade and Other Receivables	Trade and Other Receivables As at Dec. 31 2020 2019 Trade accounts receivable 488 399 Collateral paid (Note 16) 49 42 Current portion of finance lease receivables (Note 8) 36 15 Income taxes receivable 10 6 Trade and other receivables 583 462

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2020
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, 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 receivable — — 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. Carrying value as at Dec. 31, 2019 Derivatives Derivatives Amortized cost Total Financial assets Cash and cash equivalents (1) — — 411 411 Restricted cash — — 32 32 Trade and other receivables — — 462 462 Long-term portion of finance lease receivables — — 176 176 Risk management assets Current 71 95 — 166 Long-term 607 33 — 640 Other assets (Note 22) — — 47 47 Financial liabilities Accounts payable and accrued liabilities — — 413 413 Dividends payable — — 37 37 Risk management liabilities Current 1 80 — 81 Long-term 1 28 — 29 Credit facilities, long-term debt and lease liabilities (2) — — 3,212 3,212 Exchangeable securities (Note 25) — — 326 326 (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 Corporation has access. In the absence of an active market, the Corporation 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 Corporation looks primarily to external readily observable market inputs. However, if not available, the Corporation 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 Corporation 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 Corporation has the ability to access at the measurement date. In determining Level I fair values, the Corporation 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 Corporation’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 Corporation 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 Corporation 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 Corporation 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 volatilities and correlations between products derived from historical price relationships. The Corporation 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. The Corporation 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. Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by the Corporation’s risk management department. Level III fair values are primarily calculated within the Corporation’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. 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, is as follows, and excludes the effects on fair value of certain unobservable inputs such as liquidity and credit discount (described as “base fair values”), as well as inception gains or losses. 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, commodity volatilities and correlations, delivery volumes and shapes. As at Dec. 31, 2020 Description Base fair value Sensitivity Valuation technique Unobservable input Range Reasonable possible change Long-term power sale – US 598 +35 Long-term price forecast Illiquid future power prices (per MWh) US$24 to US$32 Price decrease of US$3 or price increase of US$5 -59 Coal transportation – US (16) +3 Numerical derivative valuation Illiquid future power prices (per MWh) US$24 to US$32 Price decrease of US$3 or price increase of US$5 Volatility 15% to 40% 80% to 120% -5 Rail rate escalation US$21 to US$24 zero to 4% Full requirements – Eastern US 11 +3 Historical bootstrap Volume 95% to 105% -3 Cost of supply (+/-) US$1 per MWh Long-term wind energy sale –Eastern US (29) +22 Long-term price forecast Illiquid future power prices (per MWh) US$35 to US$52 Price increase or decrease of US$6 -22 Illiquid future REC prices (per unit) US$11 Price increase or decrease of US$1 Others (4) +5 -5 As at Dec. 31, 2019 Description Base fair value Sensitivity Valuation technique Unobservable input Range Reasonable possible change Long-term power sale – US 737 +46 Long-term price forecast Illiquid future power prices (per MWh) US$20 to US$28 Price decrease of US$3 or a price increase of US$9 -139 Structured products – Eastern US 7 +2 Option valuation techniques, historical bootstrap and historical price regression analysis Basis relationship 91% to 112% 4% to 6% -2 Non-standard shape factors 63% to 116% 4% to 10% Full requirements –Eastern US 10 +3 Historical bootstrap Volume 95% to 105% -3 Cost of supply (+/-) US$1 per MWh Long-term wind energy sale – Eastern US (28) +20 Long-term price forecast Illiquid future power prices (per MWh) US$38 to US$60 Price increase or decrease of US$6 -20 Illiquid future REC prices (per unit) US$9 Price increase or decrease of US$1 Others (6) +8 -8 i. Long-Term Power Sale – US The Corporation 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 2022, 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). Prior to the second quarter of 2018, the base price forecast was developed using an additional independent industry forecast. The contract is denominated in US dollars. With the weakening of the US dollar relative to the Canadian dollar from Dec. 31, 2019, to Dec. 31, 2020, the base fair value and the sensitivity values have decreased by approximately $14 million and $1 million, respectively. ii. Structured Products – Eastern US The Corporation has structured fixed priced power in the eastern United States. Under these contracts, the Corporation has agreed to buy or sell power at non-liquid locations or during non-standard hours. As at Dec. 31, 2020, the Corporation did not have any material open positions on structured fixed priced power contracts. The key unobservable inputs in the valuation of the fixed priced power contracts are market forward spreads and non-standard shape factors. A historical regression analysis has been performed to model the spreads between non-liquid and liquid hubs. The non-standard shape factors have been determined using the historical data. iii. Coal Transportation - US The Corporation has a coal rail transport agreement that includes an upside sharing mechanism, with a contract start date of Jan. 1, 2021, and extending 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 2022, 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 judgement. iv. Full Requirements – Eastern US The Corporation has a portfolio of full requirement service contracts, whereby the Corporation agrees to supply specific utility customer needs for a range of products that may include electrical energy, capacity, transmission, ancillary services, renewable energy credits 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. v. Long-Term Wind Energy Sale – Eastern US In relation to the Big Level, the Corporation has a long-term contract for differences whereby the Corporation 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 ("RECs") 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. 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, 2020, are as follows: Level I — $13 million net liability (Dec. 31, 2019 — $3 million net liability), Level II — $27 million net liability (Dec. 31, 2019 — $9 million net asset) and Level III — $582 million net asset (Dec. 31, 2019 — $686 million net asset). Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2020, are primarily attributable to contract settlements, unfavourable changes in market prices and unfavourable changes in foreign exchange rates. The following tables summarize the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification level during the years ended Dec. 31, 2020 and 2019, respectively: Year ended Dec. 31, 2020 Year ended Dec. 31, 2019 Hedge Non-hedge Total Hedge Non-hedge Total Opening balance 678 8 686 689 6 695 Changes attributable to: Market price changes on existing contracts (18) 3 (15) 77 8 85 Market price changes on new contracts — 7 7 — 14 14 Contracts settled (71) (10) (81) (57) (19) (76) Change in foreign exchange rates (16) 1 (15) (31) (1) (32) Transfers into (out of) Level III — — — — — — Net risk management assets at end of period 573 9 582 678 8 686 Additional Level III information: Gains (losses) recognized in other comprehensive income (34) — (34) 46 — 46 Total gains included in earnings before income taxes 71 11 82 57 21 78 Unrealized gains included in earnings before income — 1 1 — 2 2 III. Other Risk Management Assets and Liabilities Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in managing exposures on non-energy marketing transactions such as interest rates, the net investment in foreign operations and other foreign currency risks. Hedge accounting is not always applied. Other risk management assets and liabilities with a total net liability fair value of $12 million as at Dec. 31, 2020 (Dec. 31, 2019 – $4 million net asset) 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, 2020, are primarily attributable to favorable 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 Level I Level II Level III Total value (1) Exchangeables securities – Dec. 31, 2020 — 769 — 769 730 Long-term debt – Dec. 31, 2020 — 3,480 — 3,480 3,227 Exchangeable securities – Dec. 31, 2019 — 342 — 342 326 Long-term debt – Dec. 31, 2019 — 3,157 — 3,157 3,070 (1) Includes current portion. The fair values of the Corporation’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 Corporation 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 2020 2019 2018 Unamortized net gain at beginning of year 9 49 105 New inception gains (losses) (1) (13) 3 (14) Change in foreign exchange rates — — 5 Amortization recorded in net earnings during the year (29) (43) (47) Unamortized net gain (loss) at end of year (2) (33) 9 49 (1) During 2020, the Corporation 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 1 forward price curve at inception of the contract.

Risk Management Activities

Risk Management Activities	12 Months Ended
	Dec. 31, 2020
Financial Instruments [Abstract]
Risk Management Activities	Risk Management Activities A. Risk Management Strategy The Corporation is exposed to market risk from changes in commodity prices, foreign exchange rates, interest rates, credit risk and liquidity risk. These risks affect the Corporation’s earnings and the value of associated financial instruments that the Corporation holds. In certain cases, the Corporation seeks to minimize the effects of these risks by using derivatives to hedge its risk exposures. The Corporation’s risk management strategy, policies and controls are designed to ensure that the risks it assumes comply with the Corporation’s internal objectives and its risk tolerance. The Corporation 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 Corporation 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 Corporation may apply hedge accounting to those hedging commodity price risk and foreign currency risk. The use of financial derivatives is governed by the Corporation’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 Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation 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 and (liabilities) are as follows: 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 As at Dec. 31, 2019 Cash flow Not Total Commodity risk management Current 70 15 85 Long-term 606 1 607 Net commodity risk management assets 676 16 692 Other Current — — — Long-term — 4 4 Net other risk management assets — 4 4 Total net risk management assets 676 20 696 I. Netting Arrangements Information about the Corporation’s financial assets and liabilities that are subject to enforceable master netting arrangements or similar agreements is as follows: As at Dec. 31 2020 2019 Current Long-term Current Long-term Current Long-term Current Long-term Gross amounts recognized 120 69 (132) (104) 316 631 (191) (100) Gross amounts set-off (69) (10) 69 10 (140) (42) 140 42 Net amounts as included in the 51 59 (63) (94) 176 589 (51) (58) C. Nature and Extent of Risks Arising from Financial Instruments I. Market Risk a. Commodity Price Risk Management The Corporation 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 Corporation’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 Corporation’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 Corporation’s proprietary trading business and commodity derivatives used in hedging relationships associated with the Corporation’s electricity generating activities. To mitigate the risk of adverse commodity price changes, the Corporation 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 Corporation 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 Corporation’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 Corporation’s exposure to market risks or the manner in which these risks are managed or measured. i. Commodity Price Risk Management – Proprietary Trading The Corporation’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 Corporation’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, 2020, associated with the Corporation’s proprietary trading activities was $1 million (2019 — $1 million, 2018 — $2 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 Corporation’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 Corporation’s reported net earnings. TransAlta has entered into various contracts with other parties whereby the other parties have agreed to pay a fixed price for electricity to TransAlta. While not all of the contracts create an obligation for the physical delivery of electricity to other parties, the Corporation has the intention and believes it has sufficient electrical generation available to satisfy these contracts and, where able, has designated these as cash flow hedges for accounting purposes. As a result, changes in market prices associated with these cash flow hedges do not affect net earnings in the period in which the price change occurs. Instead, changes in fair value are deferred until settlement through AOCI, at which time the net gain or loss resulting from the combination of the hedging instrument and hedged item affects net earnings. VaR at Dec. 31, 2020, associated with the Corporation’s commodity derivative instruments used in generation hedging activities was $12 million (2019 — $25 million, 2018 — $18 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, 2020, associated with these transactions was $15 million (2019— $8 million, 2018 — $13 million). iii. Commodity Price Risk Management – Hedges The Corporation’s outstanding commodity derivative instruments designated as hedging instruments are as follows: As at Dec. 31 2020 2019 Type Notional Notional Notional Notional Electricity (MWh) (1) 95 — 222 — (1) Excludes the long-term power sale - US contract. For further details on this contract, refer to Note 15(B)(I)(c)(i). During 2020, unrealized pre-tax gains of $1 million (2019 — $1 million, 2018 — $4 million) 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 Corporation’s outstanding commodity derivative instruments not designated as hedging instruments are as follows: As at Dec. 31 2020 2019 Type Notional Notional Notional Notional Electricity (MWh) 12,944 8,258 16,097 7,204 Natural gas (GJ) 23,035 177,448 38,062 55,023 Transmission (MWh) — 1,578 — 1,818 Emissions (MWh) 1,831 2,112 184 138 Emissions (tonnes) 2,160 2,365 2,436 2,446 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 Corporation’s borrowing costs and the capacity payments received under the Alberta coal PPAs. Changes in the cost of capital may also affect the feasibility of new growth initiatives. The Corporation's credit facility and the Poplar Creek non-recourse bond are the only debt instruments subject to floating interest rates, which represent 7 per cent of the Corporation’s debt as at Dec. 31, 2020 (2019 – 11 per cent). Interest rate risk is managed with the use of derivatives. The Corporation's outstanding interest rate derivative instruments are as follows. At Dec. 31, 2020, the Corporation had interest rate swap agreements in place with a notional amount of US$150 million whereby the Corporation 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 on the notional amount. The swap is being used to hedge interest rate exposure on a highly probable future US$400 million fixed rate debt issuance. At Dec. 31, 2020, the Corporation had a bond lock agreement in place with a notional amount of $75 million whereby on the pricing date, if the difference between the underlying 5.75 per cent Government of Canada bond and the forward bond price of $150 million (forward yield 1.20 per cent) is positive, the Corporation receives settlement. If the difference is negative, the Corporation pays settlement. The swap is being used to hedge interest rate exposure on a highly probable future $150 million fixed rate debt issuance. There were no interest rate derivative instruments outstanding in 2019 or 2018. IBOR reform could impact interest rate risk with respect to the Corporation'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: in addition the non-recourse bond references the three month CDOR. To date, no US dollar drawings have been made on the facility and there is currently a plan to discontinue the six- twelve month CDOR, which does not impact the facility or the non-recourse bond. Outstanding forward starting interest rate swaps in both Canadian and US dollars should not be affected as they are set to settle in 2021 prior to any IBOR changes being made. The Corporation is monitoring the reform and does not expect any material impacts. c. Currency Rate Risk The Corporation 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 Corporation 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 Corporation'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 Corporation’s net investment in foreign subsidiaries, the Corporation 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 Corporation’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 (2019 — US$370 million). ii. Cash Flow Hedges The Corporation 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 2020 2019 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign Exchange Forward Contracts - foreign-denominated receipts/expenditures CAD71 USD54 (2) 2021 CAD124 USD95 — 2020-2021 iii. Non-Hedges As part of the sale of the Corporation's economic interest in the Australian Assets to TransAlta Renewables, the Corporation agreed to mitigate the risks to TransAlta Renewables' shareholders of adverse changes in the US and Australian in respect of cash flows from the Australian Assets in relation to the Canadian dollar to June 30, 2020. The financial effects of the agreements eliminate on consolidation. In order to mitigate some of the risk that is attributable to non-controlling interests, the Corporation entered into foreign currency contracts with third parties to the extent of the non-controlling interest percentage of the expected cash flow over five years to June 30, 2020. Hedge accounting was not applied to these foreign currency contracts. The Corporation 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 2020 2019 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign exchange forward contracts – foreign-denominated receipts/expenditures AUD197 CAD181 (14) 2021-2024 AUD286 CAD266 — 2020 - 2023 USD47 CAD72 9 2021-2024 USD108 CAD139 (4) 2020 - 2023 AUD4 USD3 — 2021 CAD1 EUR1 — 2021 Foreign exchange forward contracts – foreign-denominated debt CAD191 USD150 2 2022 CAD191 USD150 6 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 Corporation’s functional currency, is outlined below. The sensitivity analysis has been prepared using management’s assessment that an average three cent (2019 — three cent, 2018 — four 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 2020 2019 2018 Currency Net earnings increase (decrease) (1) OCI gain (1),(2) Net earnings increase (1) OCI gain (1),(2) Net earnings decrease (1) OCI gain (1),(2) USD (8) 1 (18) 2 (13) — AUD (4) — (6) — (7) — Total (12) 1 (24) 2 (20) — (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 Corporation by failing to discharge their obligations, and the risk to the Corporation associated with changes in creditworthiness of entities with which commercial exposures exist. The Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at Dec. 31, 2020: Investment grade (Per cent) Non-investment grade (Per cent) Total (Per cent) Total Trade and other receivables (1) 92 8 100 583 Long-term finance lease receivable 100 — 100 228 Risk management assets (1) 93 7 100 692 Loan receivable (2) — 100 100 52 Total 1,555 (1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts. (2) The counterparty has no external credit rating. 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 Corporation did not have significant expected credit losses as at Dec. 31, 2020. The Corporation’s maximum exposure to credit risk at Dec. 31, 2020, 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, 2020, was $22 million (2019 — $5 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., off-takers). 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 Corporation’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, 2020, TransAlta maintains an investment grade rating from one credit rating agency and below investment grade ratings from two credit rating agencies. Between 2021 and 2023, the Corporation has approximately $1 billion of debt maturing, comprised of approximately $631 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments. We expect to refinance the debt maturing in 2022. Collateral is posted based on negotiated terms with counterparties, which can include the Corporation’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Corporation’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 Corporation does not use derivatives or hedge accounting to manage liquidity risk. A maturity analysis of the Corporation's financial liabilities is as follows: 2021 2022 2023 2024 2025 2026 and thereafter Total Accounts payable and accrued liabilities 599 — — — — — 599 Long-term debt (1) 96 626 277 119 136 2,010 3,264 Exchangeable securities (2) — — — — 750 — 750 Commodity risk management (assets) (92) (87) (131) (131) (103) 2 (542) Other risk management (assets) liabilities 14 — 1 (2) — (1) 12 Lease liabilities (3) (5) 6 5 5 5 118 134 Interest on long-term debt and lease liabilities (4) 161 153 126 119 113 893 1,565 Interest on exchangeable securities (2, 4) 53 52 53 52 — — 210 Dividends payable 59 — — — — — 59 Total 885 750 331 162 901 3,022 6,051 (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 incentive of $13 million, expected to be received in 2021. (4) Not recognized as a financial liability on the Consolidated Statements of Financial Position. IV. Equity Price Risk a. Total Return Swaps The Corporation has certain compensation, deferred and restricted share unit programs, the values of which depend on the common share price of the Corporation. The Corporation has fixed a portion of the settlement cost of these programs by entering into a total return swap for which hedge accounting has not been applied. The total return swap is cash settled every quarter based upon the difference between the fixed price and the market price of the Corporation’s common shares at the end of each quarter. D. Hedging Instruments – Uncertainty of Future Cash Flows The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount, timing and uncertainty of future cash flows: Maturity 2021 2022 2023 2024 2025 2026 and thereafter Cash flow hedges (1) Foreign currency forward contracts Notional amount ($ millions) CAD/USD 54 — — — — — Average Exchange Rate CAD/USD 0.7648 — — — — — Commodity derivative instruments Electricity Notional amount (thousands MWh) 3,424 3,329 3,329 3,338 2,628 — Average Price ($ per MWh) 69.51 71.91 73.72 75.56 77.44 — (1) The interest rate swaps detailed above both settle in 2021. 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, 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 As at Dec. 31, 2019 Notional amount Carrying amount Line item in the statement of financial position Change in fair Commodity price risk Cash flow hedges Physical power sales 19 MMWh 678 Risk management assets 47 Foreign currency risk Net investment hedges Foreign-denominated debt USD370 CAD483 Credit facilities, long-term debt and lease liabilities 21 The impact of the hedged items on the statement of financial position is as follows: As at Dec. 31 2020 2019 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 – Centralia (33) 417 47 527 Interest rate risk Cash flow hedges Interest expense on long-term 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 11 (21) 21 (21) (1) Included in AOCI. The hedging gain 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, 2020 Effective portion Ineffective portion Derivatives in cash Pre-tax Location of (gain) loss Pre-tax (gain) loss Location of (gain) loss Pre-tax Commodity contracts 41 Revenue (137) Revenue — Foreign exchange forwards on project hedges (1) Property, plant and equipment — Foreign exchange (gain) loss — Forward starting interest rate swaps (12) Interest expense (4) Interest expense — OCI impact 28 OCI impact (141) Net earnings impact — Over the next 12 months, the Corporation estimates that approximately $72 million of after-tax gains 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, 2019 Effective portion Ineffective portion Derivatives in cash Pre-tax Location of (gain) Pre-tax Location of (gain) loss Pre-tax Commodity contracts 77 Revenue (59) Revenue — Forward starting interest rate swaps — Interest expense 6 Interest expense — OCI impact 77 OCI impact (53) Net earnings impact — Year ended Dec. 31, 2018 Effective portion Ineffective portion Derivatives in cash Pre-tax Location of (gain) loss reclassified from OCI Pre-tax Location of (gain) loss Pre-tax Commodity contracts (9) Revenue (67) Revenue — Foreign exchange forwards on US debt — Foreign exchange (gain) loss 3 Foreign exchange (gain) loss — Forward starting interest rate swaps — Interest expense 7 Interest expense — OCI impact (9) OCI impact (57) Net earnings impact — II. Effect of Non-Hedges For the year ended Dec. 31, 2020, the Corporation recognized a net unrealized gain of $43 million (2019 — gain of $33 million, 2018 — loss of $29 million) related to commodity derivatives. For the year ended Dec. 31, 2020, a gain of $11 million (2019 — gain of $24 million, 2018 —gain of $3 million) related to foreign exchange and other derivatives was recognized, which is comprised of net unrealized loss of $2 million (2019 — gains of $6 million, 2018 — gains of $4 million) and net realized gains of $13 million (2019 — gains of $18 million, 2018 — losses of $1 million). F. Collateral I. Financial Assets Provided as Collateral At Dec. 31, 2020, the Corporation provided $49 million (2019 – $42 million) in cash and cash equival

Inventory

Inventory	12 Months Ended
	Dec. 31, 2020
Disclosure of inventories [Abstract]
Inventory	Inventory Inventory held in the normal course of business, which includes coal, emission credits, parts and materials, and natural gas, is valued at the lower of cost and net realizable value. Inventory held for trading, which includes natural gas and emission credits and allowances, is valued at fair value less costs to sell. In the third quarter of 2020, the Corporation adjusted the useful life of its Highvale mine assets to align with the Corporation's conversion to gas plans. The standard cost of coal has increased as a result of the increased depreciation costs, in addition to reduced coal consumption. As the cost is not expected to be recovered based on current power pricing, the Corporation recognized a $37 million writedown to net realizable value on its internally produced coal inventory for the year ended Dec. 31, 2020. The components of inventory are as follows: As at Dec. 31 2020 2019 Parts and materials 107 108 Coal 83 130 Deferred stripping costs 8 6 Natural gas 2 3 Purchased emission credits (1) 38 4 Total 238 251 (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. The change in inventory is as follows: Balance, Dec. 31, 2018 242 Net addition 12 Change in foreign exchange rates (3) Balance, Dec. 31, 2019 251 Net addition 26 Writedowns (37) Change in foreign exchange rates (2) Balance, Dec. 31, 2020 238 No inventory is pledged as security for liabilities. The Corporation purchases emissions credits and also generates emissions credits from its Wind and Solar and Hydro segments. Emission credits generated from our business have no recorded book value but will be used to offset other emissions obligations in the future, resulting in reduced fuel compliance costs. At Dec. 31, 2020, we currently hold 1,434,761 purchased emission credits (2019 — 388,155) recorded at $38 million (2019 — $4 million) and approximately 502,653 (2019 — 411,115) emission credits with no recorded book value.

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2020
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 Coal Gas generation Renewable Mining property Assets under Capital spares and other (1) Total Cost As at Dec. 31, 2018 94 5,937 1,964 3,286 1,338 200 383 13,202 Adjustments on implementation of IFRS 16 — — — (7) (101) — — (108) Additions — — — — 407 115 522 Acquisitions (Note 4(R) and 4(T)) (2) — 300 — — — 139 — 439 Disposals (3) (2) (389) (260) — (34) — (19) (704) (Impairment) reversals (Note 7) — 448 — (2) (15) — — 431 Revisions and additions to decommissioning and restoration costs (Note 23) — (62) 11 2 26 — — (23) Retirement of assets — (158) (26) (7) (10) — — (201) Change in foreign exchange rates (1) (63) (40) (17) (3) (4) (6) (134) Transfers (4) — 103 22 319 25 (514) 16 (29) As at Dec. 31, 2019 91 6,116 1,671 3,574 1,226 228 489 13,395 Additions — — — — — 478 8 486 Acquisitions (Note 4(K)) — — 1 — — — — 1 Disposals (2) (1) — — — — (2) (5) Impairment (Note 7) (9) (69) — (2) — — (1) (81) Revisions and additions to decommissioning and restoration costs (Note 23) — 21 (11) 8 76 — — 94 Retirement of assets — (35) (12) (7) (3) — (1) (58) Change in foreign exchange rates (1) (37) 45 (14) (2) — 6 (3) Transfers (4) 17 142 (263) 33 (29) (211) (120) (431) As at Dec. 31, 2020 96 6,137 1,431 3,592 1,268 495 379 13,398 Accumulated depreciation As at Dec. 31, 2018 — 3,765 1,128 1,161 830 — 154 7,038 Adjustments on implementation of IFRS 16 — — — (3) (43) — — (46) Depreciation — 304 77 136 97 — 16 630 Retirement of assets — (158) (23) (3) (6) — — (190) Disposals (3) — (170) (255) — (14) — — (439) Impairment reversal (Note 7) — 297 — — — — — 297 Change in foreign exchange rates — (52) (16) (4) (2) — (2) (76) Transfers — 10 (11) (3) (22) — — (26) As at Dec. 31, 2019 — 3,996 900 1,284 840 — 168 7,188 Depreciation — 352 76 142 133 — 14 717 Retirement of assets — (31) (10) (6) (4) — — (51) Disposals — (1) — — — — (1) (2) Change in foreign exchange rates — (35) 18 (4) (2) — 2 (21) Transfers — — (212) — (29) — (14) (255) As at Dec. 31, 2020 — 4,281 772 1,416 938 — 169 7,576 Carrying amount As at Dec. 31, 2018 94 2,172 836 2,125 508 200 229 6,164 As at Dec. 31, 2019 91 2,120 771 2,290 386 228 321 6,207 As at Dec. 31, 2020 96 1,856 659 2,176 330 495 210 5,822 (1) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance, and the Australian gas pipeline. (2) 2019 includes $308 million related to the acquisition of the Keephills 3 facility with $300 million included in coal generation and the remainder in assets under construction. (3) In 2019, we sold the Genesee 3 facility and sold the major components of the Mississauga facility. In addition, Centralia sold boiler parts included in capital spares and other for a net loss of $17 million. The Highvale mine also sold trucks included in mining property and equipment for a net loss of $18 million. Both were recognized in other gains on the statement of earnings (loss). (4) 2020 transfers out of PP&E 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. 2020 transfers between the classifications of PP&E relate to the Centralia land purchase, the Sundance Unit 6 conversion to gas, the WindCharger project and planned major maintenance. 2019 transfers mainly relate to transferring the Pioneer Pipeline and US Wind Projects from assets under construction to coal generation and renewable generation, respectively. Additions in 2020 included cash additions related to the conversions to gas of $93 million, the Windrise wind project of $156 million, the WindCharger battery storage project of $6 million, the Kaybob cogeneration project of $31 million, Centralia mine land of $17 million and planned major maintenance expenditures. Additions in 2019 included cash additions of $417 million (including $169 million related to the construction of the US Wind Projects), $100 million related to the Pioneer Pipeline (including $15 million transferred from other assets) and $5 million related to the Keephills 3 and Genesee 3 asset swap. Refer to Note 4 for further details of these transactions. Depreciation expense increased mainly as a result of decisions to accelerate the Highvale mine shutdown to align with our conversion to gas plans, reflecting our transition away from coal. Depreciation expense also increased due to the Keephills 3 and Genesee 3 swap, the reversal of the impairment at Centralia and the changes in useful lives, all of which were effective in the second half of 2019. For further details on these changes, refer to Note 3(A)(III) and Note 4(R).

Right of Use Asset

Right of Use Asset	12 Months Ended
	Dec. 31, 2020
Disclosure of leases [Abstract]
Right of Use Assets	Right-of-Use Assets The Corporation 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 New leases recognized Jan. 1, 2019 29 22 1 — — 52 Adjustments on recognition (1) (1) (4) — — — (5) Transfers from PP&E, intangibles — — 3 35 — 38 As at Jan. 1, 2019 28 18 4 35 — 85 Additions 32 2 — 2 45 81 Depreciation (1) (4) (2) (11) — (18) Changes in foreign exchange rates (1) — — — — (1) Transfers — — — (1) — (1) 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 (1) Adjusted by the amount of any prepaid or accrued lease payments, onerous contract provisions and lease inducements. In November 2019, the Corporation recognized a right-of-use asset and corresponding lease liability related to the initial 15-year term of its contract for transporting natural gas on the Pioneer Pipeline. The transportation contract provides the Corporation with the right to extend the contract for up to eight additional renewal periods of 24-months each. The amounts recognized represent the 50 per cent of the pipeline that is not owned by the Corporation. In December 2019, the Corporation recognized an additional $31 million of right-of-use assets and $31 million of lease liabilities for land leases at certain wind facilities as a result of revised interpretations of the unit of account identified asset concepts present in IFRS 16. For the year ended Dec. 31, 2020, TransAlta paid $33 million (2019 — $25 million) related to recognized lease liabilities, consisting of $8 million in interest (2019 —$4 million) and $25 million (2019 — $21 million) in principal repayments. For the year ended Dec. 31, 2020, the Corporation expensed nil related to short-term (2019 — $2 million) and nil related to low-value leases (2019 — $1 million). Short-term leases (term of less than 12 months) and leases with total lease payments below the Corporation's capitalization threshold do not require recognition as lease liabilities and right-of-use assets.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2020
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: Coal rights Software Power Intangibles Total Cost As at Dec. 31, 2018 185 339 237 46 807 Assets transferred to right-of-use assets on implementation of IFRS 16 (Note 19) — (5) — — (5) Additions — — — 14 14 Acquisition — 1 — 15 16 Disposals (Note 4(R)) (37) (1) — — (38) Change in foreign exchange rates — (4) (1) (1) (6) Transfers 1 48 14 (63) — As at Dec. 31, 2019 149 378 250 11 788 Additions — — — 14 14 Acquisition (Note 4(K)) — — 37 — 37 Disposals — (1) — — (1) Change in foreign exchange rates — — (2) — (2) Transfers — 35 (16) (22) (3) As at Dec. 31, 2020 149 412 269 3 833 Accumulated amortization As at Dec. 31, 2018 117 221 96 — 434 Assets transferred to right-of-use assets on — (3) — — (3) Amortization 8 31 11 — 50 Disposals (Note 4(R)) (9) (1) — — (10) Change in foreign exchange rates — (1) — — (1) Transfers 1 (1) — — — As at Dec. 31, 2019 117 246 107 — 470 Amortization 8 28 15 — 51 Disposals — (1) — — (1) Transfers — (1) 1 — — As at Dec. 31, 2020 125 272 123 — 520 Carrying amount As at Dec. 31, 2018 68 118 141 46 373 As at Dec. 31, 2019 32 132 143 11 318 As at Dec. 31, 2020 24 140 146 3 313

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2020
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 2020 2019 Hydro 258 258 Wind and Solar 175 176 Energy Marketing 30 30 Total goodwill 463 464 For the purposes of the 2020 annual goodwill impairment review, the Corporation 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 Corporation's long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair value measurement is categorized within Level III of the fair value hierarchy. No impairment of goodwill arose for any segment. In 2020, the Corporation relied on the recoverable amounts determined in 2019 for the Hydro and Energy Marketing segments in performing the 2020 annual 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 electricity production and sales prices. 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. Forecasted sales prices for each facility are determined by taking into consideration contract prices for facilities subject to long- or short-term contracts, forward price curves for merchant plants and regional supply-demand balances. Where forward price curves are not available for the duration of the facility’s useful life, prices are determined by extrapolation techniques using historical industry and company-specific data. Electricity prices used in these 2020 models ranged between $6 to $160 per MWh during the forecast period (2019 – $5 to $183 per MWh). Discount rates used for the goodwill impairment calculation in 2020 ranged from 4.8 per cent to 6.3 per cent (2019 – 3.6 per cent to 7.0 per cent). No reasonable possible change in the assumptions would have resulted in an impairment of goodwill.

Other Assets

Other Assets	12 Months Ended
	Dec. 31, 2020
Disclosure of financial assets [abstract]
Other Assets	Other Assets The components of other assets are as follows: As at Dec. 31 2020 2019 South Hedland prepaid transmission access and distribution costs 70 67 Deferred licence fees — 9 Project development costs 25 19 Long-term prepaids and other assets 59 56 Loan receivable 52 47 Total other assets 206 198 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. Deferred licence fees consist primarily of licences to lease the land on which certain generating assets are located, and are amortized on a straight-line basis over the useful life of the generating assets to which the licences relate. Project development costs primarily include the project costs for US wind development projects (Note 4(F)) and an Alberta Hydro development project. Some projects were written off in 2019 and 2018 as they are no longer proceeding (see Note 7(D)). 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, 2020
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 Total Balance, Dec. 31, 2018 407 49 456 IFRS 16 transition adjustment — (2) (2) Liabilities incurred 7 7 14 Liabilities settled (34) (9) (43) Accretion 23 — 23 Acquisition of liabilities 16 3 19 Disposition of liabilities (23) (9) (32) Revisions in estimated cash flows (1) 96 7 103 Revisions in discount rates (1) 16 — 16 Reversals — (1) (1) Change in foreign exchange rates (7) — (7) 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 (2) 61 11 72 Revisions in discount rates (3) 36 — 36 Reversals — (6) (6) Change in foreign exchange rates (4) — (4) Balance, Dec. 31, 2020 608 65 673 (1) During 2019, the Corporation adjusted the Centralia mine decommissioning and restoration provision as management no longer believes that the fine coal recovery and reclamation work will occur as originally proposed. Refer to Note 3(A)(III) for further details. In addition, due to the changes in estimated useful lives, the discount rates used for the Alberta Thermal and mining operations decommissioning provisions were changed. The use of a lower inflation rate decreased the corresponding liabilities. (2) During 2020, the Corporation 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. Refer to Note 3(A)(III) for further details. This increase was partially offset by a decrease in the Sarnia decommissioning and restoration provision as a result of an updated engineering study. (3) 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, 2019 501 45 546 Current portion 36 22 58 Non-current portion 465 23 488 Balance, Dec. 31, 2020 608 65 673 Current portion 21 38 59 Non-current portion 587 27 614 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 $1.4 billion, which will be incurred between 2021 and 2073. The majority of the costs will be incurred between 2025 and 2050. At Dec. 31, 2020, the Corporation had provided a surety bond in the amount of US$147 million (2019 – US$147 million) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2020, the Corporation had provided letters of credit in the amount of $131 million (2019 – $128 million) in support of future decommissioning obligations at the Alberta Highvale mine. B. Other Provisions Other provisions also include provisions arising from ongoing business activities and include amounts related to commercial disputes between the Corporation 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 Corporation’s ability to settle the provisions in the most favourable manner. In addition, during the fourth quarter of 2020 an onerous contract provision of $29 million was recognized as a result of a decision to accelerate our plans to eliminate coal as a fuel source at the Sheerness facility by the end of 2021. The last coal shipment is expected to be received during the first quarter of 2021, while payments required under the contract will continue until 2025.

Credit Facilities, Long-Term De

Credit Facilities, Long-Term Debt and Lease Liabilities	12 Months Ended
	Dec. 31, 2020
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 2020 2019 Carrying Face Interest (1) Carrying Face Interest (1) Credit facilities (2) 114 114 2.7 % 220 220 3.5 % Debentures 249 251 7.1 % 647 651 5.8 % Senior notes (3) 886 894 5.4 % 905 914 5.4 % Non-recourse (4) 1,837 1,858 4.1 % 1,144 1,157 4.3 % Other (5) 141 147 7.1 % 154 162 7.1 % 3,227 3,264 3,070 3,104 Lease liabilities 134 142 3,361 3,212 Less: current portion of long-term debt (97) (494) Less: current portion of lease liabilities (8) (19) Total current long-term debt and lease liabilities (105) (513) Total credit facilities, long-term debt and lease 3,256 2,699 (1) Interest is an average rate weighted by principal amounts outstanding 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, 2020 — US$700 million (Dec. 31, 2019 — US$700 million). (4) Includes AU$800 million TEC offering. (5) Includes US$110 million at Dec. 31, 2020 (Dec. 31, 2019 — US$117 million) of tax equity financing. The Corporation's credit facilities are summarized in the table below: As at Dec. 31, 2020 Facility Utilized Available Maturity Outstanding letters of credit (1) Actual drawings TransAlta Corporation Committed syndicated bank facility (2) 1,250 379 114 757 Q2 2023 Canadian committed bilateral credit facilities (3) 240 150 — 90 Q2 2021 & 2022 TransAlta Renewables Committed credit facility (2) 700 92 — 608 Q2 2023 Total 2,190 621 114 1,455 (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, 2020, we provided cash collateral of $49 million. (2) TransAlta has letters of credit of $89 million and TransAlta Renewables has letters of credit of $92 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities. (3) One of the bilateral $80 million credit facilities has a maturity date of Q2 2021;the remaining two bilateral credit facilities has a maturity date of Q2, 2022. The $1.95 billion (Dec. 31, 2019 – $1.95 billion) committed syndicated bank facilities are the primary source for short-term liquidity after the cash flow generated from the Corporation's business. Interest rates on the credit facilities vary depending on the option selected – Canadian prime, bankers' acceptances, US LIBOR or US base rate – in accordance with a pricing grid that is standard for such facilities. In 2019, the Corporation renewed these credit facilities and TransAlta Renewables' facility was increased by $200 million to $700 million. The Corporation is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. In addition to the $1.5 billion available under the credit facilities, the Corporation also has $703 million of available cash and cash equivalents and $17 million ($11 million principal portion) in cash restricted for repayment of the OCP bonds (refer to section E below). Debentures bear interest at fixed rates ranging from 6.9 per cent to 7.3 per cent and have maturity dates ranging from 2029 to 2030. On Nov. 25, 2020, the Corporation redeemed $400 million of its then due 5.0 per cent medium term notes. On Aug. 2, 2018, the Corporation early redeemed all of its outstanding 6.40 per cent debentures, which were due Nov. 18, 2019, for the principal amount of $400 million. The redemption price was $425 million in aggregate, including a $19 million prepayment premium recognized in net interest expense and $6 million in accrued and unpaid interest to the redemption date. Senior notes bear interest at rates ranging from 4.5 per cent to 6.5 per cent and have maturity dates ranging from 2022 to 2040. During 2018, the Corporation early redeemed its outstanding 6.650 per cent US$500 million senior notes due May 15, 2018. The repayment was hedged with foreign exchange forwards and cross-currency swaps. The redemption price for the notes was approximately $617 million (US$516 million), including a $5 million early redemption premium, recognized in net interest expense, and $14 million in accrued and unpaid interest to the redemption date. A total of US$370 million (2019 — US$370 million) of the senior notes has been designated as a hedge of the Corporation’s net investment in US foreign operations. Non-recourse debt consists of bonds and debentures that have maturity dates ranging from 2023 to 2042 and bear interest at rates ranging from 2.95 per cent to 4.51 per cent. 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 repay indebtedness on the credit facility and to fund future growth opportunities within TransAlta Renewables. During 2018, the Corporation: ▪ Paid out the US$25 million non-recourse debt related to its Mass Solar projects. ▪ Monetized the OCA and closed a $345 million bond offering through its indirect wholly owned subsidiary TransAlta OCP by way of private placement. The non-recourse amortizing bonds bear interest from their date of issuance at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030. Other 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, and tax equity financings related to Big Level and Antrim of $112 million (2019 — $122 million) and Lakeswind of $22 million (2019 — $23 million). During 2019, coinciding with Antrim and Big Level each achieving commercial operation, TransAlta received tax equity funding of approximately US$41 million and US$85 million, respectively. Refer to Note 4(T) for further details. 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 acquired tax equity which was initially recognized at its fair value. Tax equity financing balances are reduced by the value of tax benefits (production tax credits and tax depreciation) 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. In 2019, the Big Level and Antrim projects claimed accelerated (bonus) tax depreciation of $35 million in total, which was allocated to the tax equity investor, and had the effect of reducing the tax equity financing balance. 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 Corporation anticipates the maturity dates of the tax equity financings will be: Big Level and Antrim - in December 2029, 10 years from commercial operation of the projects; and Lakeswind - March 31, 2029. TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2020, the Corporation was in compliance with all debt covenants. B. Restrictions related to Non-Recourse Debt and Other Debt The Melancthon Wolfe Wind, Pingston, TAPC Holdings LP, New Richmond, KHWLP, TEC Hedland and TransAlta OCP non-recourse bonds with a carrying value of $1.8 billion as at Dec. 31, 2020 (Dec. 31, 2019 - $1.1 billion) are subject to customary financing conditions and covenants that may restrict the Corporation’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 third quarter of 2020. However, funds in these entities that have accumulated since the third quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2021. At Dec. 31, 2020, $73 million (Dec. 31, 2019 –$42 million) of cash was subject to these financial restrictions. Proceeds received from the TEC Notes in the amount of AU$7 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. C. Security Non-recourse debts totalling $1,441 million as at Dec. 31, 2020 (Dec. 31, 2019 – $719 million) are each secured by a first ranking charge over all of the respective assets of the Corporation’s subsidiaries that issued the bonds, which include PPE with total carrying amounts of $1,277 million at Dec. 31, 2020 (Dec. 31, 2019 – $967 million) and intangible assets with total carrying amounts of $88 million (Dec. 31, 2019 – $63 million). At Dec. 31, 2020, a non-recourse bond of approximately $111 million (Dec. 31, 2019 – $119 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 $285 million (Dec. 31, 2019 – $305 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 Corporation receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million, net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030. D. Principal Repayments 2021 2022 2023 2024 2025 2026 and thereafter Total Principal repayments (1) 96 626 277 119 136 2,010 3,264 Lease liabilities (2) (5) 6 5 5 5 118 134 (1) Excludes impact of hedge accounting and derivatives. (2) Lease liabilities include a lease incentive of $13 million, expected to be received in 2021. E. Restricted Cash At Dec. 31, 2020, the Corporation had $9 million (Dec. 31, 2019 – $15 million) in restricted cash related to the Big Level tax equity financing that is held in a construction reserve account. The proceeds will be released from the construction reserve account upon certain conditions being met, which are expected to be finalized in 2021. The Corporation had $17 million (Dec. 31, 2019 – $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 2021. The Corporation also had $45 million (Dec. 31, 2019 – nil) 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 $100 million demand letters of credit facilities. Letters of credit issued by TransAlta Renewables are drawn on its uncommitted $100 million demand letter of credit facility.

Exchangeable Securities

Exchangeable Securities	12 Months Ended
	Dec. 31, 2020
Exchangeable Securities [Abstract]
Exchangeable Securities	Exchangeable Securities On March 22, 2019, the Corporation entered into an Investment Agreement whereby 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"). 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, 2020 Dec. 31, 2019 Carrying value Face value Interest Carrying value Face value Interest Exchangeable debentures – due May 1, 2039 330 350 7 % 326 350 7 % Exchangeable preferred shares (1) 400 400 7 % — — 7 % Total long term debt 730 750 326 350 (1) Exchangeable preferred share dividends are reported as interest expense. If Brookfield chooses not to exercise its Option to Exchange as outlined below, TransAlta has the right after Dec. 31, 2028 to redeem for cash all or any portion of the Exchangeable Securities for the original subscription price, plus any accrued but unpaid interest or dividends payable, provided the minimum proceeds to Brookfield for each redemption (other than the final redemption) is not less than $100 million and provided all Exchangeable Securities must be redeemed within 36 months of the first optional redemption. B. Option to Exchange As at Dec. 31, 2020 Dec. 31, 2019 Description Base fair value Sensitivity Base fair value Sensitivity Option to exchange – embedded derivative — nil -33 — nil -27 The Investment Agreement allows Brookfield the Option to Exchange all of the outstanding exchangeable securities into an equity ownership interest of up to a maximum 49 per cent in an entity formed to hold TransAlta’s Alberta Hydro Assets after Dec. 31, 2024. 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 Corporation’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 equity interest, Brookfield will be entitled to receive the balance of the redemption price in cash.

Defined Benefit Obligation and

Defined Benefit Obligation and Other Long-Term Liabilities	12 Months Ended
	Dec. 31, 2020
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 2020 2019 Defined benefit obligation (Note 31) 282 268 Long-term incentive accruals (Note 30) 4 4 Other 12 29 Total 298 301

Common Shares

Common Shares	12 Months Ended
	Dec. 31, 2020
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 2020 2019 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 277.0 2,978 284.6 3,059 Purchased and cancelled under the NCIB (7.3) (79) (7.7) (83) Effects of share-based payment plans — (3) — — Stock options exercised 0.1 — 0.1 2 Issued and outstanding, end of year 269.8 2,896 277.0 2,978 B. NCIB Program Shares purchased by the Corporation 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 Corporation's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2020 2019 Total shares purchased (1) 7,352,600 7,716,300 Average purchase price per share $ 8.33 $ 8.80 Total cost 61 68 Weighted average book value of shares cancelled 79 83 Amount recorded in deficit 18 15 (1) As at Dec. 31, 2020, includes 456,200 (2019 -189,900) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. C. Shareholder Rights Plan The Corporation 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 Corporation’s shareholders every three years for approval, and it was last approved on April 26, 2019. 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 Corporation’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 2020 2019 2018 Net earnings (loss) attributable to common shareholders (336) 52 (248) Basic and diluted weighted average number of common shares outstanding (millions) 275 283 287 Net earnings (loss) per share attributable to common shareholders, basic and diluted (1.22) 0.18 (0.86) E. Dividends On Dec. 23, 2020, the Corporation declared a quarterly dividend of $0.0450 per common share, payable on April 1, 2021. On Nov. 3, 2020, the Corporation declared a quarterly dividend of $0.0425 per common share, payable on Jan. 1, 2021. 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 2020 2019 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 10.2 248 10.2 248 Series B 1.8 45 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 G Cumulative Redeemable Rate Reset Preferred Shares Conversion On Aug. 30, 2019, the Corporation announced that, after taking into account all election notices received by the Sept. 15, 2019, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series G (the “Series G Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series H (the “Series H Shares”), there were 140,730 Series G Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series H Shares. Therefore, none of the Series G Shares were converted into Series H Shares on Sept. 30, 2019. As a result, the Series G Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series G Shares for the five-year period from and including Sept. 30, 2019, to, but excluding, Sept. 30, 2024, will be 4.988 per cent, which is equal to the five-year Government of Canada bond yield of 1.188 per cent, determined as of Aug. 30, 2019, plus 3.80 per cent, in accordance with the terms of the Series G Shares. II. Series E Cumulative Redeemable Rate Reset Preferred Shares Conversion On Sept. 17, 2017, the Corporation announced that, after taking into account all election notices received by the Sept. 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series E (the “Series E Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series F (the “Series F Shares”), there were 133,969 Series E Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series F Shares. Therefore, none of the Series E Shares were converted into Series F Shares on Sept. 30, 2017. As a result, the Series E Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series E Shares for the five-year period from and including Sept. 30, 2017, to, but excluding, Sept. 30, 2022, will be 5.194 per cent, which is equal to the five-year Government of Canada bond yield of 1.544 per cent, determined as of Aug. 31, 2017, plus 3.65 per cent, in accordance with the terms of the Series E Shares. III. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion On June 16, 2017, the Corporation announced that, after taking into account all election notices received by the June 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series C (the “Series C Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series D (the “Series D Shares”), there were 827,628 Series C Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series D Shares. Therefore, none of the Series C Shares were converted into Series D Shares on June 30, 2017. As a result, the Series C Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series C Shares for the five-year period from and including June 30, 2017, to, but excluding, June 30, 2022, will be 4.027 per cent, which is equal to the five-year Government of Canada bond yield of 0.927 per cent, determined as of May 31, 2017, plus 3.10 per cent, in accordance with the terms of the Series C Shares. IV. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On March 17, 2016, the Corporation announced that 1,824,620 of its 12.0 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") were tendered for conversion, on a one-for-one basis, into Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares") after having taken into account all election notices. As a result of the conversion, the Corporation had 10.2 million Series A Shares and 1.8 million Series B Shares issued and outstanding at Dec. 31, 2020. The Series A Shares pay fixed cumulative preferential cash dividends on a quarterly basis for the five The Series B Shares pay quarterly floating rate cumulative preferential cash dividends for the five On March 1, 2021, the Corporation announced that it does not intend to exercise its right to redeem all or any part of the currently outstanding Series A Shares and Series B Shares. The Corporation has provided a notice to the registered shareholders of Series A Shares of the conversion right, on a one-for-one basis, into Series B Shares, and vice versa, providing Series B shareholders the right to exchange Series B Shares, on a one-for-one basis, into Series A Shares. Series A shareholders may elect to retain any or all of their current share holdings and continue to receive a fixed rate quarterly dividend. Series B shareholder may also elect to retain any or all of their current share holdings and continue to receive a floating rate quarterly dividend. After exercising conversion rights, if the balance that remains for either Series A Shares or Series B Shares is less than 1 million, that remaining balance of will automatically convert to the other Series. Shareholders' notice of intention to convert must be received by the transfer agent no later than March 16, 2021 and the conversion date will be effective March 31, 2021. The annual dividend rate for the Series A Shares for the five-year period from and including March 31, 2021, to, but excluding, March 31, 2026, will be 2.877 per cent, which is equal to the five-year Government of Canada Bond yield of 0.847 per cent, determined as of March 1, 2021, plus 2.03 per cent. The annual dividend rate for the Series B Shares for the three month floating rate period from and including March 31, 2021, to, but excluding, June 30, 2021, will be 2.103 per cent based on the most recent auction of 90-day Government of Canada Treasury Bills of 0.073 per cent plus 2.03 per cent. The Floating Quarterly Dividend Rate will be reset every quarter. V. 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 ▪ Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. ▪ Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2020, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over Benchmark (per cent) Convertible to A Fixed 0.67724 March 31, 2021 2.03 B B Floating 0.73801 March 31, 2021 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 2020, 2019 and 2018: Total dividends declared Series 2020 2019 (1) 2018 A 9 5 9 B (2) 1 1 1 C 14 8 14 E 15 9 15 G 10 7 11 Total for the year 49 30 50 (1) No dividends were declared in the first quarter of 2019 as the quarterly dividend related to the period covering the first quarter of 2019 was declared in December 2018. (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. 23, 2020, the Corporation declared a quarterly dividend of $0.16931 per share on the Series A preferred shares, $0.13186 per share on the Series B preferred shares, $0.25169 per share on the Series C preferred shares, $0.32463 per share on the Series E preferred shares, and $0.31175 per share on the Series G preferred shares, all payable on March 31, 2021. TransAlta’s capital is comprised of the following: As at Dec. 31 2020 2019 Increase/ Long-term debt (1) 3,361 3,212 149 Exchangeable securities 730 326 404 Equity Common shares 2,896 2,978 (82) Preferred shares 942 942 — Contributed surplus 38 42 (4) Deficit (1,826) (1,455) (371) Accumulated other comprehensive income 302 454 (152) Non-controlling interests 1,084 1,101 (17) Less: available cash and cash equivalents (2) (703) (411) (292) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (11) (10) (1) Less: fair value asset of hedging instruments on long-term debt (4) (2) (7) 5 Total capital 6,811 7,172 (361) (1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt. (2) The Corporation 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 Corporation includes the principal portion of restricted cash on TransAlta OCP bonds because this cash is restricted specifically to repay outstanding debt. (4) The Corporation 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, 2020
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 2020 2019 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 277.0 2,978 284.6 3,059 Purchased and cancelled under the NCIB (7.3) (79) (7.7) (83) Effects of share-based payment plans — (3) — — Stock options exercised 0.1 — 0.1 2 Issued and outstanding, end of year 269.8 2,896 277.0 2,978 B. NCIB Program Shares purchased by the Corporation 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 Corporation's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2020 2019 Total shares purchased (1) 7,352,600 7,716,300 Average purchase price per share $ 8.33 $ 8.80 Total cost 61 68 Weighted average book value of shares cancelled 79 83 Amount recorded in deficit 18 15 (1) As at Dec. 31, 2020, includes 456,200 (2019 -189,900) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. C. Shareholder Rights Plan The Corporation 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 Corporation’s shareholders every three years for approval, and it was last approved on April 26, 2019. 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 Corporation’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 2020 2019 2018 Net earnings (loss) attributable to common shareholders (336) 52 (248) Basic and diluted weighted average number of common shares outstanding (millions) 275 283 287 Net earnings (loss) per share attributable to common shareholders, basic and diluted (1.22) 0.18 (0.86) E. Dividends On Dec. 23, 2020, the Corporation declared a quarterly dividend of $0.0450 per common share, payable on April 1, 2021. On Nov. 3, 2020, the Corporation declared a quarterly dividend of $0.0425 per common share, payable on Jan. 1, 2021. 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 2020 2019 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 10.2 248 10.2 248 Series B 1.8 45 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 G Cumulative Redeemable Rate Reset Preferred Shares Conversion On Aug. 30, 2019, the Corporation announced that, after taking into account all election notices received by the Sept. 15, 2019, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series G (the “Series G Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series H (the “Series H Shares”), there were 140,730 Series G Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series H Shares. Therefore, none of the Series G Shares were converted into Series H Shares on Sept. 30, 2019. As a result, the Series G Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series G Shares for the five-year period from and including Sept. 30, 2019, to, but excluding, Sept. 30, 2024, will be 4.988 per cent, which is equal to the five-year Government of Canada bond yield of 1.188 per cent, determined as of Aug. 30, 2019, plus 3.80 per cent, in accordance with the terms of the Series G Shares. II. Series E Cumulative Redeemable Rate Reset Preferred Shares Conversion On Sept. 17, 2017, the Corporation announced that, after taking into account all election notices received by the Sept. 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series E (the “Series E Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series F (the “Series F Shares”), there were 133,969 Series E Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series F Shares. Therefore, none of the Series E Shares were converted into Series F Shares on Sept. 30, 2017. As a result, the Series E Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series E Shares for the five-year period from and including Sept. 30, 2017, to, but excluding, Sept. 30, 2022, will be 5.194 per cent, which is equal to the five-year Government of Canada bond yield of 1.544 per cent, determined as of Aug. 31, 2017, plus 3.65 per cent, in accordance with the terms of the Series E Shares. III. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion On June 16, 2017, the Corporation announced that, after taking into account all election notices received by the June 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series C (the “Series C Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series D (the “Series D Shares”), there were 827,628 Series C Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series D Shares. Therefore, none of the Series C Shares were converted into Series D Shares on June 30, 2017. As a result, the Series C Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series C Shares for the five-year period from and including June 30, 2017, to, but excluding, June 30, 2022, will be 4.027 per cent, which is equal to the five-year Government of Canada bond yield of 0.927 per cent, determined as of May 31, 2017, plus 3.10 per cent, in accordance with the terms of the Series C Shares. IV. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On March 17, 2016, the Corporation announced that 1,824,620 of its 12.0 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") were tendered for conversion, on a one-for-one basis, into Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares") after having taken into account all election notices. As a result of the conversion, the Corporation had 10.2 million Series A Shares and 1.8 million Series B Shares issued and outstanding at Dec. 31, 2020. The Series A Shares pay fixed cumulative preferential cash dividends on a quarterly basis for the five The Series B Shares pay quarterly floating rate cumulative preferential cash dividends for the five On March 1, 2021, the Corporation announced that it does not intend to exercise its right to redeem all or any part of the currently outstanding Series A Shares and Series B Shares. The Corporation has provided a notice to the registered shareholders of Series A Shares of the conversion right, on a one-for-one basis, into Series B Shares, and vice versa, providing Series B shareholders the right to exchange Series B Shares, on a one-for-one basis, into Series A Shares. Series A shareholders may elect to retain any or all of their current share holdings and continue to receive a fixed rate quarterly dividend. Series B shareholder may also elect to retain any or all of their current share holdings and continue to receive a floating rate quarterly dividend. After exercising conversion rights, if the balance that remains for either Series A Shares or Series B Shares is less than 1 million, that remaining balance of will automatically convert to the other Series. Shareholders' notice of intention to convert must be received by the transfer agent no later than March 16, 2021 and the conversion date will be effective March 31, 2021. The annual dividend rate for the Series A Shares for the five-year period from and including March 31, 2021, to, but excluding, March 31, 2026, will be 2.877 per cent, which is equal to the five-year Government of Canada Bond yield of 0.847 per cent, determined as of March 1, 2021, plus 2.03 per cent. The annual dividend rate for the Series B Shares for the three month floating rate period from and including March 31, 2021, to, but excluding, June 30, 2021, will be 2.103 per cent based on the most recent auction of 90-day Government of Canada Treasury Bills of 0.073 per cent plus 2.03 per cent. The Floating Quarterly Dividend Rate will be reset every quarter. V. 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 ▪ Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. ▪ Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2020, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over Benchmark (per cent) Convertible to A Fixed 0.67724 March 31, 2021 2.03 B B Floating 0.73801 March 31, 2021 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 2020, 2019 and 2018: Total dividends declared Series 2020 2019 (1) 2018 A 9 5 9 B (2) 1 1 1 C 14 8 14 E 15 9 15 G 10 7 11 Total for the year 49 30 50 (1) No dividends were declared in the first quarter of 2019 as the quarterly dividend related to the period covering the first quarter of 2019 was declared in December 2018. (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. 23, 2020, the Corporation declared a quarterly dividend of $0.16931 per share on the Series A preferred shares, $0.13186 per share on the Series B preferred shares, $0.25169 per share on the Series C preferred shares, $0.32463 per share on the Series E preferred shares, and $0.31175 per share on the Series G preferred shares, all payable on March 31, 2021. TransAlta’s capital is comprised of the following: As at Dec. 31 2020 2019 Increase/ Long-term debt (1) 3,361 3,212 149 Exchangeable securities 730 326 404 Equity Common shares 2,896 2,978 (82) Preferred shares 942 942 — Contributed surplus 38 42 (4) Deficit (1,826) (1,455) (371) Accumulated other comprehensive income 302 454 (152) Non-controlling interests 1,084 1,101 (17) Less: available cash and cash equivalents (2) (703) (411) (292) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (11) (10) (1) Less: fair value asset of hedging instruments on long-term debt (4) (2) (7) 5 Total capital 6,811 7,172 (361) (1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt. (2) The Corporation 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 Corporation includes the principal portion of restricted cash on TransAlta OCP bonds because this cash is restricted specifically to repay outstanding debt. (4) The Corporation includes the fair value of economic and designated hedging instruments on debt in an asset, or liability, position as a reduction, or increase, in the calculation of capital, as the carrying value of the related debt has either increased, or decreased, due to changes in foreign exchange rates.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2020
Disclosure of analysis of other comprehensive income by item [abstract]
Accumulated other comprehensive income	Accumulated Other Comprehensive Income The components of, and changes in, accumulated other comprehensive income (loss) are as follows: 2020 2019 Currency translation adjustment Opening balance, Jan. 1 (21) 17 Gains (losses) on translating net assets of foreign operations, net of reclassifications to net earnings, (11) (59) Gains (losses) on financial instruments designated as hedges of foreign operations, net of 11 21 Balance, Dec. 31 (21) (21) Cash flow hedges Opening balance, Jan. 1 527 508 Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax (1) (91) 19 Balance, Dec. 31 436 527 Employee future benefits Opening balance, Jan. 1 (55) (29) Net actuarial gains (losses) on defined benefit plans, net of tax (2) (11) (26) Balance, Dec. 31 (66) (55) Other Opening balance, Jan. 1 3 (15) Change in ownership of TransAlta Renewables — 1 Intercompany investments at FVOCI (50) 17 Balance, Dec. 31 (47) 3 Accumulated other comprehensive income 302 454 (1) Net of income tax of $23 million for the year ended Dec. 31, 2020 (2019 — $6 million). (2) Net of income tax of $3 million for the year ended Dec. 31, 2020 (2019 — $7 million).

Share-Based Payment Plans

Share-Based Payment Plans	12 Months Ended
	Dec. 31, 2020
Share-based payment arrangements [Abstract]
Share-Based Payment Plans	Share-Based Payment Plans The Corporation 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 Corporation’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 Corporation’s share price over the three-year period and accrue dividends as additional units at the same rate as dividends paid on the Corporation’s common shares. During 2019, as a result of the Corporation's change in its intended settlement policy, the accounting classification of the RSUs and PSUs changed from cash-settled to equity-settled. The RSUs and PSUs have been accounted for as equity-settled grants from the dates of the policy change, with fair values determined as at that date. On average, the fair value of outstanding grants used in accounting for the change was $8.29, measured using the Black-Scholes option pricing model. As a result of this change, the liability for the cash-settled grants ($25 million) has been derecognized and the equity-settled fair value ($24 million) has been recognized in contributed surplus, with the net difference of $1 million representing the cumulative change in compensation expense. No changes were made to the vesting or performance conditions associated with the awards. The Human Resources Committee of the Board has the discretion to determine whether payments on settlement are made through purchase of shares on the open market or in cash. The expenses related to this plan are recognized during the period earned, with the corresponding amounts due under the plan recorded in contributed surplus (2018 — liabilities). Prior to this change, the liability was valued at the end of each reporting period using the closing price of the Corporation’s common shares on the TSX. The pre-tax compensation expense related to PSUs and RSUs in 2020 was $15 million (2019 — $19 million, 2018 — $8 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 Corporation and fluctuates based on the changes in the value of the Corporation’s common shares in the marketplace. DSUs accrue dividends as additional DSUs at the same rate as dividends are paid on the Corporation’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 Corporation. The Corporation 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 $1 million in 2020 (2019 — $2 million, 2018 — nil). C. Stock Option Plans The Corporation is authorized to grant options to purchase up to an aggregate of 16.5 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 2020, the Corporation granted executive officers of the Corporation a total of 0.7 million stock options with a weighted average exercise price of $9.17 that vest after a three — 1.4 million stock options at $5.65; 2018 — 0.7 million stock options at $7.45). The expense recognized relating to these grants during 2020 was approximately $2 million (2019 — approximately $1 million, 2018 — approximately $1 million). The total options outstanding and exercisable under these stock option plans at Dec. 31, 2020, are outlined below: Options outstanding Range of exercise prices (1) ($ per share) Number of options (millions) Weighted average remaining contractual life (years) Weighted average exercise price ($ per share) 5.00 - 10.00 4.0 4.2 6.85 (1) Options currently exercisable as at Dec. 31, 2020.

Employee Future Benefits

Employee Future Benefits	12 Months Ended
	Dec. 31, 2020
Employee Benefits [Abstract]
Employee Future Benefits	Employee Future Benefits A. Description The Corporation sponsors registered pension plans in Canada and the US covering substantially all employees of the Corporation 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, 2020. 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, 2020. 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 Corporation. The Corporation is not obligated to fund the supplemental plan but is obligated to pay benefits under the terms of the plan as they come due. The Corporation posted a letter of credit in March 2020 for the amount of $89 million to secure the obligations under the supplemental plan. The Corporation 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, 2020, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2020. The Corporation provides several defined contribution plans, including an Australian superannuation plan and a US 401(k) savings plan, that provide for company contributions from 5 per cent to 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, 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 Year ended Dec. 31, 2018 Registered Supplemental Other Total Current service cost 9 2 1 12 Administration expenses 1 — — 1 Interest cost on defined benefit obligation 18 3 1 22 Interest on plan assets (13) — — (13) Defined benefit expense 15 5 2 22 Defined contribution expense 10 — — 10 Net expense 25 5 2 32 C. Status of Plans The status of the defined benefit pension and other post-employment benefit plans is as follows: 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) Year ended Dec. 31, 2019 Registered Supplemental Other Total Fair value of plan assets 373 13 — 386 Present value of defined benefit obligation (543) (99) (22) (664) Funded status – plan deficit (170) (86) (22) (278) Amount recognized in the consolidated financial statements: Accrued current liabilities (3) (5) (2) (10) Other long-term liabilities (167) (81) (20) (268) Total amount recognized (170) (86) (22) (278) 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, 2018 368 13 — 381 Interest on plan assets 12 1 — 13 Net return on plan assets 40 — — 40 Contributions 6 4 1 11 Benefits paid (50) (5) (1) (56) Administration expenses (2) — — (2) Effect of translation on US plans (1) — — (1) 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 The fair value of the Corporation’s defined benefit plan assets by major category is as follows: 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 Year ended Dec. 31, 2019 Level I Level II Level III Total Equity securities Canadian — 66 — 66 US — 28 — 28 International — 102 — 102 Private — — 1 1 Bonds AAA — 40 — 40 AA — 68 — 68 A — 37 — 37 BBB 1 21 — 22 Below BBB — 3 — 3 Money market and cash and cash equivalents — 19 — 19 Total 1 384 1 386 Plan assets do not include any common shares of the Corporation at Dec. 31, 2020 and Dec. 31, 2019. The Corporation charged the registered plan nil for administrative services provided for the year ended Dec. 31, 2020 (2019 — 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, 2018 514 80 25 619 Current service cost 7 2 1 10 Interest cost 19 3 1 23 Benefits paid (51) (4) (1) (56) Curtailment (3) — — (3) Actuarial gain arising from demographic assumptions — — (2) (2) Actuarial loss arising from financial assumptions 57 9 2 68 Actuarial gain (loss) arising from experience adjustments 2 9 (4) 7 Effect of translation on US plans (2) — — (2) 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 demographic assumptions — — — — 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 The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2020 is 14.4 years. F. Contributions The expected employer contributions for 2021 for the defined benefit pension and other post-employment benefit plans are as follows: Registered Supplemental Other Total Expected employer contributions 5 5 2 12 G. Assumptions The significant actuarial assumptions used in measuring the Corporation’s defined benefit obligation for the defined benefit pension and other post-employment benefit plans are as follows: As at Dec. 31, 2020 As at Dec. 31, 2019 (per cent) Registered Supplemental Other Registered Supplemental Other Accrued benefit obligation Discount rate 2.4 2.3 2.3 3.0 3.0 3.0 Rate of compensation increase 2.9 3.0 — 2.8 3.0 — Assumed health-care cost trend rate Health-care cost escalation (1)(3) — — 6.8 — — 7.0 Dental-care cost escalation — — 4.0 — — 4.0 Benefit cost for the year Discount rate 3.0 3.0 3.0 3.9 3.8 3.9 Rate of compensation increase 2.9 3.0 — 2.5 3.0 — Assumed health-care cost trend rate Health-care cost escalation (2)(4) — — 7.1 — — 7.4 Dental-care cost escalation — — 4.0 — — 4.0 (1) 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. (2) 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. (3) 2019 Post- and pre-65 rates: decreasing gradually to 4.5% by 2030 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2027 for Canada. (4) 2019 Post- and pre-65 rates: decreasing gradually to 4.5% by 2027 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2027 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, 2020 Registered Supplemental Other Pension Other 1% decrease in the discount rate 74 17 2 3 1 1% increase in the salary scale 5 — — 4 1 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, 2020
Disclosure of interests in other entities [Abstract]
Joint arrangements	Investments The Corporation’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 (1) 86 16 102 Equity income 1 — 1 Change in foreign exchange rates (2) (1) (3) Balance, Dec. 31, 2020 85 15 100 (1) Contributions were paid in US dollars and were US$66 million for Skookumchuck and US$12 million for EMG, including contingent consideration. Summarized financial information on the results of operations relating to the Corporation’s pro-rata interests in Skookumchuck and EMG is as follows: Year ended Dec. 31 2020 Results of operations Revenues 3 Expenses (2) Proportionate share of net earnings 1 On Nov. 25, 2020, TransAlta purchased a 49 per cent interest in Skookumchuck, a 136.8 MW wind facility located in Lewis and Thurston counties near Centralia in Washington state consisting of 38 Vestas 136 wind turbines. Summarized financial information relating to 100 per cent of Skookumchuck, including adjustments for the application of consistent accounting policies and the Corporation’s purchase price adjustments, is as follows: Year ended Dec. 31 2020 Revenues 6 Depreciation and amortization 2 Interest expense 1 Net earnings 3 Other comprehensive loss — Total comprehensive loss 3 As at Dec. 31 2020 Current assets 6 Non-current assets 382 Current liabilities (65) Non-current liabilities (150) Net assets 173 Additional items included above Cash and cash equivalents 1 Current financial liabilities (1) (27) Non-current financial liabilities (1) (147) (1) Excludes trade and other payables and provisions. A reconciliation of the carrying amount to the Corporation’s 49 per cent interest in the Skookumchuck is as follows: As at Dec. 31 2020 Net assets 173 Less: 51 per cent of Skookumchuck net assets not owned by the Corporation (88) Net investment 85 Skookumchuck’s ability to make distributions to its owners, including the Corporation, is dependent on available cash flow and is restricted by covenants and conditions, including principal and interest funding requirements imposed by the tax equity financing agreements. Skookumchuck's approximate future payments under contractual commitments are as follows: 2021 2022 2023 2024 2025 2026 and thereafter Total Long-term service agreements (1) 1 1 1 1 1 28 33 (1) Refer to Note 36 for further details on long-term service agreements. Joint arrangements at Dec. 31, 2020, included the following: Joint operations Segment Ownership (per cent) Description Sheerness Alberta Thermal 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 Pioneer Pipeline Alberta Thermal 50 Natural gas pipeline in Alberta operated by TMI Goldfields Power Australian Gas 50 Gas-fired facility in Australia operated by TransAlta Fort Saskatchewan North American Gas 60 Cogeneration facility in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta Fortescue River Australian 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 ventures 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, 2020
Disclosure of cash flow statement [Abstract]
Cash Flow Information	Cash Flow Information A. Change in Non-Cash Operating Working Capital Year ended Dec. 31 2020 2019 2018 (Use) source: Accounts receivable (79) 261 58 Prepaid expenses 2 — 19 Income taxes receivable (4) (6) — Inventory 6 (13) (21) Accounts payable, accrued liabilities and provisions 160 (130) (97) Income taxes payable 4 9 (3) Change in non-cash operating working capital 89 121 (44) B. Changes in Liabilities from Financing Activities Balance Dec. 31, 2019 Net cash flows New leases Dividends declared Foreign exchange impact Other Balance Dec. 31, 2020 Long-term debt and lease 3,212 133 16 — 5 (5) 3,361 Exchangeable securities 326 400 — — — 4 730 Dividends payable (common and 37 (86) — 107 — 1 59 Total liabilities from financing activities 3,575 447 16 107 5 — 4,150 Balance Dec. 31, 2018 Net cash flows New leases Tax shield on tax equity financing Dividends declared Foreign exchange impact Other Balance Dec. 31, 2019 Long-term debt and lease 3,267 (70) 133 (35) — (42) (41) 3,212 Exchangeable securities — 350 — — — — (24) 326 Dividends payable (common and 58 (85) — — 64 — — 37 Total liabilities from financing 3,325 195 133 (35) 64 (42) (65) 3,575

Capital

Capital	12 Months Ended
	Dec. 31, 2020
Disclosure of notes and other explanatory information [Abstract]
Capital	Capital TransAlta’s capital is comprised of the following: As at Dec. 31 2020 2019 Increase/ Long-term debt (1) 3,361 3,212 149 Exchangeable securities 730 326 404 Equity Common shares 2,896 2,978 (82) Preferred shares 942 942 — Contributed surplus 38 42 (4) Deficit (1,826) (1,455) (371) Accumulated other comprehensive income 302 454 (152) Non-controlling interests 1,084 1,101 (17) Less: available cash and cash equivalents (2) (703) (411) (292) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (11) (10) (1) Less: fair value asset of hedging instruments on long-term debt (4) (2) (7) 5 Total capital 6,811 7,172 (361) (1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt. (2) The Corporation 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 Corporation includes the principal portion of restricted cash on TransAlta OCP bonds because this cash is restricted specifically to repay outstanding debt. (4) The Corporation 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 Corporation’s overall capital management strategy and its objectives in managing capital are as follows: A. Maintain a Strong Financial Position The Corporation 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 Corporation to access capital markets at reasonable interest rates. Maintaining a strong balance sheet also allows its commercial team to contract the Corporation’s portfolio with a variety of counterparties on terms and prices that are favourable to the Corporation’s financial results and provides the Corporation with better access to capital markets through commodity and credit cycles. The Corporation has an investment-grade credit rating from DBRS (stable outlook). During 2020, Moody's reaffirmed its issuer rating of Ba1 with a stable outlook; DBRS reaffirmed the Corporation’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 Corporation’s Unsecured Debt rating and Issuer Rating of BB+ with stable outlook. The Corporation remains focused on strengthening its financial position and cash flow coverage ratios. Credit ratings provide information relating to the Corporation's financing costs, liquidity and operations and affect the Corporation's ability to obtain short-term and long-term financing and/or the cost of such financing. Key rating agencies assess TransAlta’s credit rating using a variety of methodologies, including financial ratios. The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and ratios are not defined under IFRS and may not be comparable to those used by other entities or by rating agencies. These ratios are summarized in the table below: As at Dec. 31 2020 2019 Target Funds from operations before interest to adjusted interest coverage (times) 4.2 4.5 4 to 5 Adjusted funds from operations to adjusted net debt (%) 18.3 19.0 20 to 25 Adjusted net debt to adjusted comparable earnings before interest, taxes, depreciation and amortization (times) 3.9 3.9 3.0 to 3.5 Deconsolidated net debt to deconsolidated comparable EBITDA (times) 4.6 4.2 2.5 to 3.0 Funds from Operations (“FFO”) before Interest to Adjusted Interest Coverage is calculated as FFO less the termination payments for the Sundance B and C PPAs plus interest on debt, exchangeable securities and lease liabilities (net of capitalized interest) divided by interest on debt, exchangeable securities and lease liabilities (net of capitalized interest) plus 50 per cent of dividends paid on preferred shares. The exchangeable preferred shares (see Note 25) are considered equity with dividend payments for credit purposes. FFO is calculated as cash flow from operating activities before changes in working capital and is adjusted for transactions and amounts that the Corporation believes are not representative of ongoing cash flows from operations. The Corporation’s goal is to maintain this ratio in a range of four to five times. Adjusted FFO to Adjusted Net Debt is calculated as FFO less the termination payments for the Sundance B and C PPAs less 50 per cent of dividends paid on preferred shares divided by adjusted net debt (current and long-term debt plus exchangeable securities plus 50 per cent of outstanding preferred shares less available cash and cash equivalents less principal portion of TransAlta OCP restricted cash and including fair value assets of hedging instruments on debt). The exchangeable preferred shares (see Note 25) are considered equity with dividend payments for credit purposes. The Corporation’s goal is to maintain this ratio in a range of 20 to 25 per cent. Adjusted Net Debt to Adjusted Comparable EBITDA is calculated as adjusted net debt divided by adjusted comparable EBITDA. Adjusted comparable EBITDA is calculated as earnings before interest, taxes, depreciation and amortization and is adjusted for transactions and amounts that the Corporation believes are not representative of ongoing business operations as well as the termination payments for the Sundance B and C PPAs. The exchangeable preferred shares (see Note 25) are considered equity with dividend payments for credit purposes. The Corporation’s goal is to maintain this ratio in a range of 3.0 to 3.5 times. Deconsolidated net debt to deconsolidated comparable EBITDA is calculated as deconsolidated net debt (long-term debt, lease liabilities and exchangeable debentures including current portion and fair value (asset) liability of hedging instruments on debt plus 50 per cent issued preferred shares less cash and cash equivalents less principal portion of TransAlta OCP restricted cash less TransAlta Renewables long-term debt and lease liabilities including current portion less tax equity financing) divided by deconsolidated comparable EBITDA (comparable EBITDA less TransAlta Renewables comparable EBITDA less TA Cogen comparable EBITDA plus dividends received from TransAlta Renewables plus dividends received from TA Cogen). The exchangeable preferred shares (see Note 25) are considered equity with dividend payments for credit purposes. The Corporation's goal is to maintain this ratio in a range of 2.5 to 3.0 times. At times, the credit ratios may be outside of the specified ranges while the Corporation executes its conversion to gas and growth strategy, but we remain focused on maintaining a strong balance sheet. 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. Ensure Sufficient Cash and Credit is Available to Fund Operations, Pay Dividends, Distribute Payments to Subsidiaries’ Non-Controlling Interests, Invest in PP&E and Make Acquisitions For the years ended Dec. 31, 2020 and 2019, cash inflows and outflows are summarized below. The Corporation manages variations in working capital using existing liquidity under credit facilities. Year ended Dec. 31 2020 2019 Increase Cash flow from operating activities 702 849 (147) Change in non-cash working capital (89) (121) 32 Cash flow from operations before changes in working capital 613 728 (115) Dividends paid on common shares (47) (45) (2) Dividends paid on preferred shares (39) (40) 1 Distributions paid to subsidiaries’ non-controlling interests (97) (106) 9 Property, plant and equipment expenditures (486) (417) (69) Inflow (outflow) (56) 120 (176) TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2020, $1.5 billion (2019 — $1.3 billion) of the Corporation’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, 2020
Related Party [Abstract]
Related Party Transactions	Related-Party Transactions Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2020, 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 Corporation and its subsidiaries have been eliminated on consolidation and are not disclosed. Associates and joint ventures have been equity accounted for by the Corporation. Transactions with Key Management Personnel TransAlta’s key management personnel include the President and 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 2020 2019 2018 Total compensation 27 30 17 Comprised of: Short-term employee benefits 12 13 11 Post-employment benefits 2 2 2 Termination benefits — 2 — Share-based payments 13 13 4

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2020
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 Corporation 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: 2021 2022 2023 2024 2025 2026 and thereafter Total Natural gas, transportation and 141 149 137 134 134 1,353 2,048 Transmission 8 8 8 5 5 1 35 Coal supply and mining 81 105 101 67 56 — 410 Long-term service agreements 31 37 22 18 10 55 173 Operating leases 4 2 2 1 1 26 36 Growth 509 411 93 — — — 1,013 TransAlta Energy Transition Bill 6 6 6 — — — 18 Total 780 718 369 225 206 1,435 3,733 A. Natural Gas, Transportation and Other Contracts The Corporation has fixed price or volume natural gas purchase and transportation contracts. In addition to the commitments shown above, upon closing the sale of the Pioneer Pipeline, a 15-year transportation agreement will provide an additional 275 TJ per day of natural gas on a firm basis by 2023, bringing the total firm natural gas transportation contracts to 400 TJ per day by 2023. This agreement would replace the Corporation's existing 15-year commitment to purchase 139 TJ per day of natural gas on the Pioneer Pipeline, which remains in place until the closing of the Transaction. Other contracts relate to commitments for goods and services. B. Transmission The Corporation has several agreements to purchase transmission network capacity in the Pacific Northwest. Provided certain conditions for delivering the service are met, the Corporation 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. In 2020, a new rail transportation service contract was entered into and pricing is reflective of current market conditions. As a result, there is an increase in expected rail transportation costs over the service period. Commitments related to mining agreements include the Corporation’s share of commitments for mining agreements related to its Sheerness joint operation and certain other mining royalty agreements. Some of these commitments have been reduced due to the accelerated plans to eliminate coal as a fuel source at the Sheerness facility by the end of 2021. D. Long-Term Service Agreements TransAlta has various service agreements in place, primarily for inspections and repairs and maintenance that may be required on natural gas facilities, coal facilities and turbines at various wind facilities. E. Operating Leases Includes lease commitments not recognized under IFRS 16 and lease commitments that have not yet commenced, mainly related to buildings, vehicles and land. Prior to the adoption of IFRS 16, operating lease expenses were recognized as incurred in the statement of earnings. During the year ended Dec. 31, 2018, $8 million was recognized as an expense in respect of operating leases. Sublease payments received during 2020 were $2 million (2019 and 2018 — were less than $1 million). No contingent rental payments were made in respect of operating leases. F. Growth Commitments for growth relate to the following projects: conversion to gas and repowering Sundance Unit 5, Kaybob cogeneration project, Windrise project and any final costs associated with the Big Level and Antrim wind projects. Refer to Note 4 for further details on these projects. 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 MOA, we have 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 part thereof would no longer be required. As of Dec. 31, 2020, the Corporation has funded approximately US$41 million of the commitment, which is recognized in other assets in the Consolidated Statements of Financial Position. H. Other A significant portion of the Corporation’s electricity and thermal production are subject to PPAs and long-term contracts. The majority of these contracts include terms and conditions customary to the industry in which the Corporation operates. The nature of commitments related to these contracts includes: electricity and thermal capacity, availability and production targets; reliability and other plant-specific performance measures; specified payments for deliveries during peak and off-peak time periods; specified prices per MWh; risk sharing of fuel costs; and retention of heat rate risk. I. 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 Corporation’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 Corporation responds as required. I. Line Loss Rule Proceeding The Corporation 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 and issue a single invoice charging or crediting market participants for the difference in losses charges. The AESO submitted a review and variance application of this decision to implement a “pay-as-you-go” invoicing scheme rather than issue a single invoice. The AUC ruled on the AESO’s request and approved a three-period invoice process (2006-2009, 2010-2013 and 2014-2016). The total liability for the loss charges was $25 million; however, due to payments made (and received) for the first two invoices, only $8 million of the total liability remains outstanding. The AESO issued the first invoice on Oct. 22, 2020 for $6 million, which was paid by Dec. 30, 2020. The second invoice was issued on Dec. 21, 2020, for $11 million. The third invoice is expected in March 2021. In November 2020, the AESO sought direction from the AUC with respect to interest payments on the loss charges and the AUC ruled in January 2021 that simple interest rather than compound interest would apply to the loss charges. II. FMG Disputes The Corporation is currently engaged in a dispute with Fortescue Metals Group Ltd. ("FMG") as a result of FMG's purported termination of the South Hedland PPA. TransAlta sued FMG, seeking payments of amounts invoiced and not paid under the South Hedland PPA, as well as a declaration that the PPA is valid and in force. FMG, on the other hand, seeks a declaration that the PPA was lawfully terminated. This matter has been rescheduled to proceed to trial beginning May 3, 2021, instead of June 15, 2020. The Corporation had a second dispute involving FMG's claims against TransAlta related to the transfer of the Solomon facility to FMG. FMG claimed certain amounts related to the condition of the facility while TransAlta claimed certain outstanding costs that should be reimbursed. The dispute was settled and discontinued in the Supreme Court of Western Australia on Sept. 9, 2020. III. Mangrove Claim On April 23, 2019, Mangrove commenced an action in the Ontario Superior Court of Justice, naming the Corporation, the incumbent members of the Board of Directors of the Corporation on such date and Brookfield BRP Holdings (Canada), as defendants. Mangrove is seeking to set aside the Brookfield Investment. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter has been rescheduled and the three-week trial will begin on April 19, 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 is scheduled to be heard on April 8, 2021. TransAlta believes 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 Generation Partnership claimed force majeure under the Keephills PPA. ENMAX, the PPA buyer under the PPA at the time, did not dispute the force majeure, but the Balancing Pool did, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The Balancing Pool argued and won in the Courts that it has a right under the PPA to commence an arbitration, independent of the PPA buyer, ENMAX. An arbitration for this dispute has commenced and is set to be heard for seven days starting Dec. 6, 2021. 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 2021 or early 2022. 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 emissions performance credits ("EPCs"), valued at approximately $17 million per year, earned by the Hydro facilities under the Carbon Competitiveness Incentive Regulation from 2018-2020. Refer to Note 2(A) and 2(F)(IV) for the accounting policies on these credits. The dispute is based on the ownership of the EPCs as a result of a change in law provision under the Hydro PPA and that TransAlta is benefiting from the purported change in law. TransAlta has not received any benefit from the EPCs and has not recognized any benefit from the EPCs within its financial statements. TransAlta believes that the Balancing Pool has no rights to these credits. An arbitration has commenced and will be likely set down for a hearing sometime in early 2022. VIII. Direct Assigned Capital Deferral Account ("DACDA") Application AltaLink Management Ltd. ("AltaLink") filed an application before the AUC to recover its 2016-2018 DACDA costs (the "Proceeding") incurred for the 240 kV line upgrades project in the Edmonton region (the “Upgrades Project”). TransAlta is a secondary applicant in the Proceeding because it owns a portion of the 1043L Line located on Enoch Cree Nation (“ECN”) Reserve that was a part of the Upgrades Project. AltaLink and TransAlta sought to have their costs ($91 million for AltaLink and $22 million for TransAlta) approved by the AUC as reasonable and prudent. The ECN and the Consumers' Coalition of Alberta are registered participants in the Proceeding. The AUC rendered its decision in the Proceeding on Dec. 10, 2020, and disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta believes that the AUC made errors by disallowing 15 per cent of its costs and therefore filed a permission to appeal application with the Court of Appeal (the “PTA”) and a review and variance application with the AUC (the “R&V”). The PTA will be adjourned until the R&V process is completed.

Segments Disclosures

Segments Disclosures	12 Months Ended
	Dec. 31, 2020
Disclosure of operating segments [abstract]
Segments Disclosures	Segment Disclosures A. Description of Reportable Segments The Corporation has eight reportable segments as described in Note 1. The following tables provides each segment's results in the format that management organizes its segments to make operating decisions and assess performance. For internal reporting purpose, the earnings information from the Corporation's investment in Skookumchuck has been presented in the Wind and Solar segment on a proportionate basis. Information on a proportionate basis reflects the Corporation'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. The table below also shows the reconciliation of the total segmented results to the statement of earnings reported under IFRS. B. Reported Segment Earnings (Loss) and Segment Assets I. Earnings Information Year ended Dec. 31, 2020 Hydro Wind and Solar (1) North American Gas (2) Australian Alberta Thermal (3) Centralia (3) Energy Corporate Total Equity accounted investments (1) IFRS Financials Revenues 152 332 217 158 619 497 122 7 2,104 (3) 2,101 Fuel, carbon 8 25 66 10 573 279 — 7 968 — 968 Gross margin 144 307 151 148 46 218 122 — 1,136 (3) 1,133 Operations, 37 53 49 32 131 60 30 80 472 — 472 Depreciation and 28 136 46 43 270 105 2 25 655 (1) 654 Asset impairment 2 — — — 75 7 — — 84 — 84 Taxes, other than 2 8 2 — 15 5 — 1 33 — 33 Net other operating — — — — (11) — — — (11) — (11) Operating income 75 110 54 73 (434) 41 90 (106) (97) (2) (99) Equity income from associate (1) — — — — — — — — — 1 1 Finance lease income — — 5 2 — — — — 7 — 7 Net interest expense (239) 1 (238) Foreign exchange 17 — 17 Gain on sale of assets 9 — 9 Earnings before (303) — (303) (1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. (2) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. (3) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. Year ended Dec. 31, 2019 Hydro Wind North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate Total Revenues 156 312 209 160 816 571 129 (6) 2,347 Fuel, carbon compliance and 7 16 74 9 570 416 — (6) 1,086 Gross margin 149 296 135 151 246 155 129 — 1,261 Operations, maintenance and 36 50 44 37 138 67 30 73 475 Depreciation and amortization 32 124 41 48 233 83 2 27 590 Asset impairment (reversal) 2 — — — 15 (10) — 18 25 Gain on termination of Keephills 3 coal rights contract (Note 4(R)) — — — — (88) — — — (88) Taxes, other than income taxes 3 8 1 — 13 3 — 1 29 Termination of Sundance B and C PPAs (Note 9) — — — — (56) — — — (56) Net other operating expense — (10) (1) — (40) — — 2 (49) Operating income (loss) 76 124 50 66 31 12 97 (121) 335 Finance lease income — — 6 — — — — — 6 Net interest expense (179) Foreign exchange loss (15) Gain on sale of assets and 46 Earnings before income taxes 193 (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. Year ended Dec. 31, 2018 Hydro Wind North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate Total Revenues 156 282 232 165 912 442 67 (7) 2,249 Fuel, carbon compliance and 6 17 96 8 666 314 — (7) 1,100 Gross margin 150 265 136 157 246 128 67 — 1,149 Operations, maintenance and 38 50 48 37 171 61 24 86 515 Depreciation and amortization 30 110 43 49 241 74 2 25 574 Asset impairment — 12 — — 38 — — 23 73 Taxes, other than income taxes 3 8 1 — 13 5 — 1 31 Termination of Sundance B and C PPAs (Note 9) — — — — (157) — — — (157) Net other operating income — (6) — — (41) — — — (47) Operating income (loss) 79 91 44 71 (19) (12) 41 (135) 160 Finance lease income — — 8 — — — — — 8 Net interest expense (250) Foreign exchange loss (15) Gain on sale of assets 1 Earnings before income taxes (96) (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. II. Selected Consolidated Statements of Financial Position Information As at Dec. 31, 2020 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total PP&E 467 2,005 382 421 2,271 260 — 16 5,822 Right-of-use assets 6 55 1 4 53 — — 22 141 Intangible assets 4 159 32 34 31 5 7 41 313 Goodwill 258 175 — — — — 30 — 463 As at Dec. 31, 2019 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total PP&E 469 1,947 392 489 2,540 352 1 17 6,207 Right-of-use assets 6 56 — 4 68 — — 12 146 Intangible assets 5 173 2 37 41 6 9 45 318 Goodwill 258 176 — — — — 30 — 464 (1) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. (2) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. III. Selected Consolidated Statements of Cash Flows Information Additions to non-current assets are as follows: Year ended Dec. 31, 2020 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total Additions to non-current assets: PP&E 22 174 39 10 200 28 — 13 486 Intangible assets — — — — 1 — — 13 14 Year ended Dec. 31, 2019 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total Additions to non-current assets: PP&E 23 229 36 6 114 8 — 1 417 Intangible assets — — — — 2 — — 12 14 Year ended Dec. 31, 2018 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total Additions to non-current assets: PP&E 16 117 21 6 101 14 — 2 277 Intangible assets — — — — 3 — — 17 20 (1) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. (2) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. 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 2020 2019 2018 Depreciation and amortization expense on the Consolidated Statements of 654 590 574 Depreciation included in fuel, carbon compliance and purchased power (Note 6) 144 119 136 Depreciation and amortization on the Consolidated Statements of Cash Flows 798 709 710 C. Geographic Information I. Revenues Year ended Dec. 31 2020 2019 2018 Canada 1,227 1,460 1,573 US 716 727 511 Australia 158 160 165 Total revenue 2,101 2,347 2,249 II. Non-Current Assets Property, plant and Right-of-use assets Intangible assets Other assets Goodwill As at Dec. 31 2020 2019 2020 2019 2020 2019 2020 2019 2020 2019 Canada 4,661 4,854 107 109 185 213 74 75 418 418 US 737 863 30 33 94 68 61 47 45 46 Australia 424 490 4 4 34 37 71 76 — — Total 5,822 6,207 141 146 313 318 206 198 463 464 D. Significant Customer During the year ended Dec. 31, 2020, no sales to any one customer was greater than 10 per cent of the Corporation’s total revenue (2019 — one customer within the Alberta Thermal and Hydro segments represented 11 per cent of total revenue).

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
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 and assets held for sale, 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 March 2, 2021.
Basis of Consolidation	Basis of Consolidation The consolidated financial statements include the accounts of the Corporation and the subsidiaries that it controls. Control exists when the Corporation 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 Corporation’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 Corporation 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 Corporation’s performance to date. The Corporation 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 Corporation’s contracts may contain more than one performance obligation. Transaction Price The Corporation 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 Corporation'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 Corporation expects to be entitled to in exchange for transferring the good or service. The Corporation 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 Corporation’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 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 Corporation’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 Corporation receives consideration before the performance obligations have been satisfied. A contract asset is recorded when the Corporation has rights to consideration for the completion of a performance obligation before it has invoiced the customer. The Corporation 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. The Corporation recognizes a significant financing component where the timing of payment from the customer differs from the Corporation’s performance under the contract and where that difference is the result of the Corporation financing the transfer of goods and services. II. Revenue from Other Sources 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 Corporation 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. 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 Corporation 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.
Foreign currency translation	Foreign Currency Translation The Corporation, its subsidiary companies and joint arrangements each determine their functional currency based on the currency of the primary economic environment in which they operate. The Corporation’s functional currency is the Canadian dollar, while the functional currencies of its subsidiary companies and joint arrangements are the Canadian, US or Australian dollar. Transactions denominated in a currency other than the functional currency of an entity are translated at the exchange rate in effect on the transaction date. The resulting exchange gains and losses are included in each entity’s net earnings in the period in which they arise. The Corporation’s foreign operations are translated to the Corporation’s presentation currency, which is the Canadian dollar, for inclusion in the consolidated financial statements. Foreign-denominated monetary and non-monetary assets and liabilities of foreign operations are translated at exchange rates in effect at the end of the reporting period, and revenue and expenses are translated at exchange rates in effect on the transaction date. The resulting translation gains and losses are included in other comprehensive income (loss) (“OCI”) with the cumulative gain or loss reported in accumulated other comprehensive income (loss) (“AOCI”). Amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in a foreign net investment as a result of a disposal, partial disposal or loss of control.
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 Corporation’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 Corporation 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 Corporation 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 Corporation has made an accounting policy choice to recognize the impacts of the tax attributes in net interest expense. The Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation’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 Corporation 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 Corporation 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 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 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.
Collateral paid and received	Collateral Paid and ReceivedThe terms and conditions of certain contracts may require the Corporation or its counterparties to provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may decrease the credit limits granted to the Corporation or its counterparties and accordingly increase the amount of collateral that may have to be provided by the Corporation or its counterparties.
Inventory	Inventory I. Fuel The Corporation’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 Corporation 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 Corporation 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 Corporation 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 Corporation’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 1-52 years Wind generation 1-29 years Gas generation 1-17 years Coal generation 1-29 years Mining property and equipment 1-9 years Capital spares and other 2-52 years TransAlta capitalizes borrowing costs on capital invested in projects under construction (see Note 2(R)). 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, carbon compliance and purchased power in the Consolidated Statements of Earnings (Loss). Amortization commences when the intangible asset is available for use and is computed on a straight-line basis over the intangible asset’s estimated useful life, except for coal rights, which are amortized using a unit-of-production basis, based on the estimated mine reserves. Estimated useful lives of intangible assets may be determined, for example, with reference to the term of the related contract or licence agreement. The estimated useful lives and amortization methods are reviewed annually with the effect of any changes being accounted for prospectively. Intangible assets consist of power sale contracts with fixed prices higher than market prices at the date of acquisition, coal rights, software and intangibles under development. Estimated remaining useful lives of intangible assets are as follows: Software 2-7 years Power sale contracts 1-20 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 Corporation 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 Corporation’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 Corporation 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 Corporation’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 “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 Corporation. 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.
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 Corporation’s CGUs or groups of CGUs that are expected to benefit from the synergies of the business combination in which the goodwill arose. To test for impairment, the recoverable amount of the CGUs or groups of CGUs to which the goodwill relates is compared to its carrying amount. 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.
Project development costs	Project Development CostsProject development costs include external, direct and incremental costs that are necessary for completing an acquisition or construction project. These costs are recognized as operating expenses until construction of a plant 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 Corporation, 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 are charged to net earnings.
Income taxes	Income TaxesThe Corporation 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 Corporation 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 BenefitsThe Corporation 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 Corporation’s defined benefit pension plans give rise to recording an additional liability, letters of credit provided by the Corporation 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 Corporation has a present obligation (legal or constructive) as a result of a past event, it is probable that the Corporation 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 Corporation 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 Corporation 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 Corporation determines the present value of the provision using the current discount rates that reflect the time value of money and associated risks. The Corporation 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(G)) 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 Corporation 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.
Share-based payments	Share-Based Payments The Corporation measures share-based awards compensation expense at grant date at fair value and recognizes the expense over the vesting period based on the Corporation’s estimate of the number of units that will eventually vest. Any award that vests in installments is accounted for as a separate award with its own distinct fair value measurement. Compensation expense associated with equity-settled and cash-settled awards are recognized within equity and liability, respectively. The liability associated with cash-settled awards is remeasured to fair value at each reporting date up to, and including, the settlement date, with changes in fair value recognized within compensation expense.
Assets Held for Sale	Assets Held for Sale Assets are classified as held for sale if their carrying amount will be recovered primarily through a sale as opposed to continued use by the Corporation. Assets classified as held for sale are measured at the lower of their carrying amount and fair value less costs of disposal. Any impairment is recognized in net earnings. Depreciation and equity accounting ceases when an asset or equity investment, respectively, is classified as held for sale. Assets classified as held for sale are reported as current assets in the Consolidated Statements of Financial Position.
Leases	Leases I. Lease Policy for 2019 and 2020 The Corporation adopted IFRS 16 Leases ("IFRS 16") with an initial adoption date of Jan. 1, 2019. As a result, in 2019, the Corporation changed its accounting policy for leases, which is outlined below. Refer to (II) below for information on the prior accounting policy. 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 Corporation 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 Corporation is the lessee, and which are not exempt as short-term or low-value leases, the Corporation: ▪ 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 Corporation 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 Corporation'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 Corporation’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 Corporation is reasonably certain to exercise that option and periods covered by an option to terminate if the Corporation 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 Corporation expects to exercise the purchase option, the related right-of-use asset is depreciated over the useful life of the underlying asset. The Corporation 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 Power purchase agreements (“PPA”) and other long-term contracts may contain, or may be considered, leases where the fulfilment 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 Corporation 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 Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the Corporation 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 Corporation 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. II. Lease Policy Prior to 2019 A lease is an arrangement whereby the lessor conveys to the lessee, in return for a payment or series of payments, the right to use an asset for an agreed period of time. PPA and other long-term contracts may contain, or may be considered, leases where the fulfilment 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 use that asset. Where the Corporation 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 Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the Corporation 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. Rental income, including contingent rent, from operating leases is recognized over the term of the arrangement and is reflected in revenue on the Consolidated Statements of Earnings (Loss). Contingent rent may arise when payments due under the contract are not fixed in amount but vary based on a future factor such as the amount of use or production. Leasing or other contractual arrangements that transfer substantially all of the risks and rewards of ownership to the Corporation are considered finance leases. A leased asset and lease obligation are recognized at the lower of the fair value or the present value of the minimum lease payments. Lease payments are apportioned between interest expense and a reduction of the lease liability. Contingent rents are charged as expenses in the periods incurred. The leased asset is depreciated over the shorter of the estimated useful life of the asset and the lease term.
Borrowing costs	Borrowing Costs The Corporation capitalizes borrowing costs that are directly attributable to, or relate to general borrowings used for, the construction of qualifying assets. Qualifying assets are assets that take a substantial period of time to prepare for their intended use and typically include generating facilities or other assets that are constructed over periods of time exceeding 12 months. Borrowing costs are considered to be directly attributable if they could have been avoided if the expenditure on the qualifying asset had not been made. Borrowing costs that are capitalized are included in the cost of the related PP&E component. Capitalization of borrowing costs ceases when substantially all the activities necessary to prepare the asset for its intended use are complete. All other borrowing costs are expensed in the period in which they are incurred.
Non-controlling interests	Non-Controlling Interests Non-controlling interests arise from business combinations in which the Corporation 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 Corporation determines on a transaction-by-transaction basis which measurement method is used. Non-controlling interests also arise from other contractual arrangements between the Corporation and other parties, whereby the other party has acquired an interest in a specified asset or operation, and the Corporation retains control. Subsequent to acquisition, the carrying amount of non-controlling interests is increased or decreased by the non-controlling interest’s share of subsequent changes in equity and payments to the non-controlling interest. Total comprehensive income 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 Corporation'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 Corporation 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 Corporation 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 Corporation’s share of the joint venture’s net earnings or loss after the date of acquisition. The impact of transactions between the Corporation and joint ventures is eliminated based on the Corporation’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.
Investment in Associate	Investments in Associates Associates are entities over which the Corporation has significant influence. Significant influence is the power to participate in financial and operating policy decisions of the entity, but is not control or joint control over the policies. Significant influence is generally present when an investor holds more than 20 per cent of the voting power of the investee. Investments in associates are accounted for using the equity method of accounting. Under the equity method, the investment is initially recognized at cost and the carrying amount is increased or decreased to recognize the Corporation’s share of the associate’s net earnings or loss after the date of acquisition. The Corporation’s share of the associate’s net earnings or loss is recognized in net earnings. Distributions received from the associate reduce the carrying amount of the investment Investments in associates are evaluated for impairment at each reporting date by first assessing whether there is objective evidence that the investment is impaired. If such objective evidence is present, an impairment charge is recognized if the investment’s recoverable amount is less than its carrying amount. The investment’s recoverable amount is determined as the higher of value in use and fair value less costs of disposal. Any impairment loss is recognized within equity income in the statement of earnings.
Government incentives	Government Incentives Government incentives are recognized when the Corporation has reasonable assurance that it will comply with the conditions associated with the incentive and that the incentive will be received. When the incentive relates to an expense item, it is recognized in net earnings over the same period in which the related costs or revenues are recognized. When the incentive relates to an asset, it is recognized as a reduction of the carrying amount of PP&E and released to earnings as a reduction in depreciation over the expected useful life of the related asset.
Earnings per share	Earnings per Share Basic earnings per share is calculated by dividing net earnings attributable to common shareholders by the weighted average number of common shares outstanding in the year. Diluted earnings per share is calculated by dividing net earnings attributable to common shareholders, adjusted for the after-tax effects of dividends, interest or other changes in net earnings that would result from potential dilutive instruments, by the weighted average number of common shares outstanding in the year, adjusted for additional common shares that would have been issued on the conversion of all potential dilutive instruments.
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. In 2019, the Corporation early-adopted amendments to IFRS 3 Business Combinations in advance of the mandatory effective date of Jan. 1, 2020. The amendments ,
Stripping costs	Stripping Costs A mine stripping activity asset is recognized when all of the following are met: i) it is probable that the future benefit associated with improved access to the coal reserves associated with the stripping activity will be realized; ii) the component of the coal reserve to which access has been improved can be identified; and iii) the costs related to the stripping activity associated with that component can be measured reliably. Costs include those directly incurred to perform the stripping activity as well as an allocation of directly attributable overheads. The resulting stripping activity asset is amortized on a unit-of-production basis over the expected useful life of the identified component that it relates to. The amortization is recognized as a component of the standard cost of coal inventory.
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 Corporation’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 Corporation’s financial position or performance. The key judgments and sources of estimation uncertainty are described below: I. COVID-19 The outbreak of the novel strain of coronavirus ("COVID-19") has resulted in governments worldwide enacting emergency measures to constrain the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods, self-isolation, physical and social distancing and the closure of non-essential businesses, have caused significant disruption to businesses globally, which has resulted in an uncertain and challenging economic environment. The duration and impact of the COVID-19 pandemic are unknown at this time. Estimates to the extent to which the COVID-19 pandemic may, directly or indirectly, impact the Corporation's operations, financial results and conditions in future periods are also subject to significant uncertainty. For a description of additional risks identified as a result of the pandemic, refer to Note 16. Actual results could differ from these 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. II. 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 Corporation evaluates the market design, transmission constraints and the contractual profile of each facility, as well as the Corporation’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 Corporation 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 2018 to 2020 is found in Notes 7, 18 and 21. III. Leases In determining whether the Corporation’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 Corporation 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 Corporation, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant and impact how the Corporation 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. IV. 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 Corporation 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 Corporation’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 Corporation’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 Corporation’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 Corporation’s tax policies. V. Financial Instruments and Derivatives The Corporation’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 Corporation’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 Corporation’s estimates of pricing and production to allow the future transaction to be fulfiled. When the Corporation enters into contracts to buy or sell non-financial items, such as certain commodities, and the contracts can be settled net in cash, the Corporation 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 Corporation'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 Corporation 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. VI. Project Development Costs Project development costs are capitalized in accordance with the accounting policy in Note 2(K). 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 Corporation, in determining the amount to be capitalized. Information on the write-off of project development costs is disclosed in Note 7. VII. Provisions for Decommissioning and Restoration Activities TransAlta recognizes provisions for decommissioning and restoration obligations as outlined in Note 2(N) and Note 23. Initial decommissioning provisions, and subsequent changes thereto, are determined using the Corporation’s best estimate of the required cash expenditures, adjusted to reflect the risks and uncertainties inherent in the timing and amount of settlement. The estimated cash expenditures are present valued using a current, risk-adjusted, market-based, pre-tax discount rate. A change in estimated cash flows, market interest rates or timing could have a material impact on the carrying amount of the provision. Information regarding significant judgments and estimates made during 2020 in respect of decommissioning and restoration provisions can be found in Note 3(A)(III) and Notes 7 and 23. VIII. 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 3(A)(III). IX. Employee Future Benefits The Corporation 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. X. Other Provisions Where necessary, the Corporation 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 Corporation’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 4, 9 and 23 with respect to other provisions. XI. 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 Corporation also considers the historical production levels and operating conditions for its variable generating assets. The Corporation’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 Corporation 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. XII. Classification of Joint Arrangements Upon entering into a joint arrangement, the Corporation 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 Corporation 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. XIII. Significant Influence

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
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 1-52 years Wind generation 1-29 years Gas generation 1-17 years Coal generation 1-29 years Mining property and equipment 1-9 years Capital spares and other 2-52 years A reconciliation of the changes in the carrying amount of PP&E is as follows: Land Coal Gas generation Renewable Mining property Assets under Capital spares and other (1) Total Cost As at Dec. 31, 2018 94 5,937 1,964 3,286 1,338 200 383 13,202 Adjustments on implementation of IFRS 16 — — — (7) (101) — — (108) Additions — — — — 407 115 522 Acquisitions (Note 4(R) and 4(T)) (2) — 300 — — — 139 — 439 Disposals (3) (2) (389) (260) — (34) — (19) (704) (Impairment) reversals (Note 7) — 448 — (2) (15) — — 431 Revisions and additions to decommissioning and restoration costs (Note 23) — (62) 11 2 26 — — (23) Retirement of assets — (158) (26) (7) (10) — — (201) Change in foreign exchange rates (1) (63) (40) (17) (3) (4) (6) (134) Transfers (4) — 103 22 319 25 (514) 16 (29) As at Dec. 31, 2019 91 6,116 1,671 3,574 1,226 228 489 13,395 Additions — — — — — 478 8 486 Acquisitions (Note 4(K)) — — 1 — — — — 1 Disposals (2) (1) — — — — (2) (5) Impairment (Note 7) (9) (69) — (2) — — (1) (81) Revisions and additions to decommissioning and restoration costs (Note 23) — 21 (11) 8 76 — — 94 Retirement of assets — (35) (12) (7) (3) — (1) (58) Change in foreign exchange rates (1) (37) 45 (14) (2) — 6 (3) Transfers (4) 17 142 (263) 33 (29) (211) (120) (431) As at Dec. 31, 2020 96 6,137 1,431 3,592 1,268 495 379 13,398 Accumulated depreciation As at Dec. 31, 2018 — 3,765 1,128 1,161 830 — 154 7,038 Adjustments on implementation of IFRS 16 — — — (3) (43) — — (46) Depreciation — 304 77 136 97 — 16 630 Retirement of assets — (158) (23) (3) (6) — — (190) Disposals (3) — (170) (255) — (14) — — (439) Impairment reversal (Note 7) — 297 — — — — — 297 Change in foreign exchange rates — (52) (16) (4) (2) — (2) (76) Transfers — 10 (11) (3) (22) — — (26) As at Dec. 31, 2019 — 3,996 900 1,284 840 — 168 7,188 Depreciation — 352 76 142 133 — 14 717 Retirement of assets — (31) (10) (6) (4) — — (51) Disposals — (1) — — — — (1) (2) Change in foreign exchange rates — (35) 18 (4) (2) — 2 (21) Transfers — — (212) — (29) — (14) (255) As at Dec. 31, 2020 — 4,281 772 1,416 938 — 169 7,576 Carrying amount As at Dec. 31, 2018 94 2,172 836 2,125 508 200 229 6,164 As at Dec. 31, 2019 91 2,120 771 2,290 386 228 321 6,207 As at Dec. 31, 2020 96 1,856 659 2,176 330 495 210 5,822 (1) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance, and the Australian gas pipeline. (2) 2019 includes $308 million related to the acquisition of the Keephills 3 facility with $300 million included in coal generation and the remainder in assets under construction. (3) In 2019, we sold the Genesee 3 facility and sold the major components of the Mississauga facility. In addition, Centralia sold boiler parts included in capital spares and other for a net loss of $17 million. The Highvale mine also sold trucks included in mining property and equipment for a net loss of $18 million. Both were recognized in other gains on the statement of earnings (loss).
Disclosure of detailed information about intangible assets	Estimated remaining useful lives of intangible assets are as follows: Software 2-7 years Power sale contracts 1-20 years

Significant and Subsequent Ev_2

Significant and Subsequent Events (Tables)	12 Months Ended
	Dec. 31, 2020
Significant Events [Abstract]
Details of business combinations	The fair values of the identifiable assets and liabilities of the acquired entity in the business combination as at the date of acquisition were: As at May 19, 2020 Fair value recognized Assets Net working capital 6 Property, plant and equipment 1 Intangible assets (1) 37 Risk management liabilities (current and long-term) (5) Decommissioning provisions (1) Total identifiable net assets at fair value 38 Cash consideration 32 Working capital consideration 6 Total purchase consideration transferred 38
Asset Acqusition	Consequently, the acquisition has been accounted for as an asset acquisition, with the following carrying amounts assigned based on relative fair values: Working capital 11 Property, plant and equipment 308 Other assets 3 Other liabilities (2) Decommissioning and other provisions (19) Total acquisition cost 301

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure of revenue from contracts with customers [Abstract]
Disaggregation Of Revenue	The majority of the Corporation'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 Corporation disaggregates into the following groups for the purpose of determining how economic factors affect the recognition of revenue. Year ended Dec. 31, 2020 Hydro Wind North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate and Other Total Revenues from contracts with 141 261 196 90 325 10 — — 1,023 Revenue from leases (3) — — 8 60 55 — — — 123 Revenue from derivatives and — (2) 4 — (12) 283 122 12 407 Government incentives 1 4 — — — — — — 5 Revenue from other (4) 10 66 9 8 251 204 — (5) 543 Total revenue 152 329 217 158 619 497 122 7 2,101 Revenues from contracts with customers Timing of revenue recognition At a point in time — 25 — — 23 10 — — 58 Over time 141 236 196 90 302 — — — 965 Total revenue from contracts 141 261 196 90 325 10 — — 1,023 (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. In addition, during the third quarter of 2020, merchant revenue within this segment was reclassified from revenue from contracts with customers to revenue from other and prior periods were adjusted. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. (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 and other miscellaneous. Year ended Dec. 31, 2019 Hydro Wind North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate and Other Total Revenues from contracts with 142 244 190 87 395 10 — — 1,068 Revenue from leases (3) — — — 65 65 — — — 130 Revenue from derivatives and — 18 2 — (17) 160 129 4 296 Government incentives — 8 — — — — — — 8 Revenue from other (4) 14 42 17 8 373 401 — (10) 845 Total revenue 156 312 209 160 816 571 129 (6) 2,347 Revenues from contracts with customers Timing of revenue recognition At a point in time — 27 — — 41 10 — — 78 Over time 142 217 190 87 354 — — — 990 Total revenue from contracts with customers 142 244 190 87 395 10 — — 1,068 (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. In addition, during the third quarter of 2020, merchant revenue within this segment was reclassified from revenue from contracts with customers to revenue from other and prior periods were adjusted. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. (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 and other miscellaneous. Year ended Dec. 31, 2018 Hydro Wind and North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate Total Revenues from contracts with 132 206 206 91 517 9 — — 1,161 Revenue from leases (3) 7 27 — 68 68 — — — 170 Revenue from derivatives and — (20) 4 — (1) 115 67 — 165 Government incentives — 16 — — — — — — 16 Revenue from other (4) 17 53 22 6 328 318 — (7) 737 Total revenue 156 282 232 165 912 442 67 (7) 2,249 Revenues from contracts with customers Timing of revenue recognition At a point in time — 18 — — 38 9 — — 65 Over time 132 188 206 91 479 — — — 1,096 Total revenue from contracts with customers 132 206 206 91 517 9 — — 1,161 (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. In addition, during the third quarter of 2020, merchant revenue within this segment was reclassified from revenue from contracts with customers to revenue from other and prior periods were adjusted. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. (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 and other miscellaneous.
Changes In Contract Liabilities	The Corporation has recognized the following revenue-related contract liabilities: Contract liabilities 2020 2019 Balance, beginning of the year 15 88 IFRS 16 transition adjustments (1) — 15 Amounts transferred to revenue included in opening balance (1) (10) Consideration received 1 5 Increases due to interest accrued and expensed during the period — 5 Contract termination associated with the purchase of Keephills 3 (Note 4(R)) — (88) Consideration paid 2 — Performance obligations satisfied (2) — Balance, end of year 15 15 Current portion 1 1 Long-term portion 14 14

Expenses by Nature (Tables)

Expenses by Nature (Tables)	12 Months Ended
	Dec. 31, 2020
Analysis of income and expense [abstract]
Expenses classified by nature	Expenses classified by nature are as follows: Year ended Dec. 31 2020 2019 2018 Fuel, carbon compliance and Operations, Fuel, carbon compliance and Operations, Fuel, carbon compliance and Operations, Fuel and carbon compliance 574 — 669 — 656 — Coal inventory writedown (Note 17) 37 — — — — — Purchased power 163 — 246 — 210 — Mine depreciation 144 — 119 — 136 — Salaries and benefits 50 235 52 228 98 245 Other operating expenses — 237 — 247 — 270 Total 968 472 1,086 475 1,100 515

Impairment of assets (Tables)

Impairment of assets (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure of impairment of assets [Abstract]
Disclosure of significant unobservable inputs used in fair value measurement of assets	The Corporation utilized the Corporation's long-range forecast and the following key assumptions in 2019 compared with 2016 assumptions, which was the most recent detailed valuation: 2019 2016 Mid-Columbia annual average power prices US$30 to US$42 per MWh US$22 to US$46 per MWh On-highway diesel fuel on coal shipments US$2.35 to US$2.40 per gallon US$1.69 to US$2.09 per gallon Discount rates 5.2 to 6.4 per cent 5.4 to 5.7 per cent

Finance Lease Receivables (Tabl

Finance Lease Receivables (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure of maturity analysis of finance lease payments receivable [abstract]
Disclosure of maturity analysis of finance lease payments receivable	Amounts receivable under the Corporation’s finance leases associated with the Poplar Creek cogeneration facility and in 2020, the Southern Cross Energy facilities are as follows: As at Dec. 31 2020 2019 Minimum Present value of Minimum Present value of Within one year 63 56 20 20 Second to fifth years inclusive 169 126 80 74 More than five years 100 82 120 97 332 264 220 191 Less: unearned finance lease income 68 — 29 — Total finance lease receivables 264 264 191 191 Included in the Consolidated Statements of Financial Position as: Current portion of finance lease receivables (Note 14) 36 15 Long-term portion of finance lease receivables 228 176 264 191

Net Other Operating Income (Tab

Net Other Operating Income (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 2018 Coal supply agreement 29 — — Alberta Off-Coal Agreement (40) (40) (40) Insurance recoveries — (10) (7) Other expenses — 1 — Net other operating income (11) (49) (47)

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2020
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 (1) 86 16 102 Equity income 1 — 1 Change in foreign exchange rates (2) (1) (3) Balance, Dec. 31, 2020 85 15 100 (1) Contributions were paid in US dollars and were US$66 million for Skookumchuck and US$12 million for EMG, including contingent consideration. Summarized financial information on the results of operations relating to the Corporation’s pro-rata interests in Skookumchuck and EMG is as follows: Year ended Dec. 31 2020 Results of operations Revenues 3 Expenses (2) Proportionate share of net earnings 1 On Nov. 25, 2020, TransAlta purchased a 49 per cent interest in Skookumchuck, a 136.8 MW wind facility located in Lewis and Thurston counties near Centralia in Washington state consisting of 38 Vestas 136 wind turbines. Summarized financial information relating to 100 per cent of Skookumchuck, including adjustments for the application of consistent accounting policies and the Corporation’s purchase price adjustments, is as follows: Year ended Dec. 31 2020 Revenues 6 Depreciation and amortization 2 Interest expense 1 Net earnings 3 Other comprehensive loss — Total comprehensive loss 3 As at Dec. 31 2020 Current assets 6 Non-current assets 382 Current liabilities (65) Non-current liabilities (150) Net assets 173 Additional items included above Cash and cash equivalents 1 Current financial liabilities (1) (27) Non-current financial liabilities (1) (147) (1) Excludes trade and other payables and provisions. A reconciliation of the carrying amount to the Corporation’s 49 per cent interest in the Skookumchuck is as follows: As at Dec. 31 2020 Net assets 173 Less: 51 per cent of Skookumchuck net assets not owned by the Corporation (88) Net investment 85
Disclosure of commitments and future payments	Skookumchuck's approximate future payments under contractual commitments are as follows: 2021 2022 2023 2024 2025 2026 and thereafter Total Long-term service agreements (1) 1 1 1 1 1 28 33 (1) Refer to Note 36 for further details on long-term service agreements. In addition to commitments disclosed elsewhere in the financial statements, the Corporation 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: 2021 2022 2023 2024 2025 2026 and thereafter Total Natural gas, transportation and 141 149 137 134 134 1,353 2,048 Transmission 8 8 8 5 5 1 35 Coal supply and mining 81 105 101 67 56 — 410 Long-term service agreements 31 37 22 18 10 55 173 Operating leases 4 2 2 1 1 26 36 Growth 509 411 93 — — — 1,013 TransAlta Energy Transition Bill 6 6 6 — — — 18 Total 780 718 369 225 206 1,435 3,733

Net Interest Expense (Tables)

Net Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2020
Analysis of income and expense [abstract]
Components of net interest expense	The components of net interest expense are as follows: Year ended Dec. 31 2020 2019 2018 Interest on debt 158 161 184 Interest on exchangeable securities (Note 25) 34 20 — Interest income (10) (13) (11) Capitalized interest (Note 18) (8) (6) (2) Loss on redemption of bonds (Note 24) — — 24 Interest on lease liabilities 8 4 3 Credit facility fees, bank charges and other interest 18 15 13 Tax shield on tax equity financing (Note 24) (1) 1 (35) — Interest on line loss rule proceeding (Note 36(I)(I)) 5 — — Other (2) 2 10 15 Accretion of provisions (Note 23) 30 23 24 Net interest expense 238 179 250 (1) 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 investment is treated as debt under IFRS and the monetization of the tax depreciation is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Taxes [Abstract]
Rate reconciliations	Rate Reconciliations Year ended Dec. 31 2020 2019 2018 Earnings (loss) before income taxes (303) 193 (96) Net earnings (loss) attributable to non-controlling interests not subject to tax 2 (26) (19) Adjusted earnings (loss) before income taxes (301) 167 (115) Statutory Canadian federal and provincial income tax rate (%) 24.5 % 26.5 % 26.8 % Expected income tax expense (recovery) (74) 44 (31) Increase (decrease) in income taxes resulting from: Differences in effective foreign tax rates 3 5 (3) Deferred income tax expense related to temporary difference on investment in 9 — — Writedown (reversal of writedown) of deferred income tax assets 8 (9) 27 Statutory and other rate differences (7) (31) — Other 11 8 1 Income tax expense (recovery) (50) 17 (6) Effective tax rate (%) 17 % 10 % 5 %
Components of income tax expense	The components of income tax expense are as follows: Year ended Dec. 31 2020 2019 2018 Current income tax expense 35 35 28 Deferred income tax expense (recovery) related to the origination and reversal of (95) 22 (61) Deferred income tax expense related to temporary difference on investment in 9 — — Deferred income tax recovery resulting from changes in tax rates or laws (1) (7) (31) — Deferred income tax expense (recovery) arising from the writedown (reversal of writedown) of deferred income tax assets (2) 8 (9) 27 Income tax expense (recovery) (50) 17 (6) Year ended Dec. 31 2020 2019 2018 Current income tax expense 35 35 28 Deferred income tax recovery (85) (18) (34) Income tax expense (recovery) (50) 17 (6) (1) In 2020 the Corporation recognized a deferred income tax recovery of $7 million (2019 —$31 million) related to a decrease in the Alberta corporate tax rate from 11 per cent to 8 per cent. The tax decrease was originally scheduled as follows: 11 per cent effective July 1, 2019, 10 per cent effective Jan. 1, 2020, 9 per cent effective Jan. 1, 2021, and 8 per cent effective Jan. 1, 2022. The Government of Alberta enacted the rate to decrease to 8 per cent effective Dec. 9, 2020.
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 2020 2019 2018 Income tax expense (recovery) related to: Net impact related to cash flow hedges (23) 6 (12) Net actuarial gains (losses) (3) (7) 5 Income tax expense reported in equity (26) (1) (7)
Significant components of deferred income tax assets (liabilities)	Significant components of the Corporation’s deferred income tax assets (liabilities) are as follows: As at Dec. 31 2020 2019 Net operating loss carryforwards (1) 469 494 Future decommissioning and restoration costs 140 122 Property, plant and equipment (717) (828) Risk management assets and liabilities, net (107) (141) Employee future benefits and compensation plans 62 56 Interest deductible in future periods 22 42 Foreign exchange differences on US-denominated debt 31 40 Other deductible temporary differences 2 4 Net deferred income tax liability, before writedown of deferred income tax assets (98) (211) Writedown of deferred income tax assets (247) (243) Net deferred income tax liability, after writedown of deferred income tax assets (345) (454) (1) Net operating losses expire between 2029 and 2039. The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows: As at Dec. 31 2020 2019 Deferred income tax assets (1) 51 18 Deferred income tax liabilities (396) (472) Net deferred income tax liability (345) (454) (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 Corporation’s long-range forecasts.

Non-Controlling Interests (Tabl

Non-Controlling Interests (Tables)	12 Months Ended
	Dec. 31, 2020
Interests In Other Entities [Abstract]
Share of ownership and equity participation in TransAlta Renewables	The Corporation’s subsidiaries and operations that have non-controlling interests are as follows: Subsidiary/Operation Non-controlling interest as at Dec. 31, 2020 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.
Subsidiaries and operations with non-controlling interests	As a result of the DRIP and the Share Offering described in Note 4(W), the Corporation’s share of ownership and equity participation in TransAlta Renewables has changed as follows: Period Ownership and voting Equity participation Aug. 1, 2017 to June 21, 2018 64.0 64.0 June 22, 2018 to July 30, 2018 61.1 61.1 July 31, 2018 to Nov. 29, 2018 61.0 61.0 Nov. 30, 2018 to Dec. 31, 2018 60.9 60.9 Jan. 1, 2019 to Mar. 31, 2019 60.8 60.8 April 1, 2019 to June 30, 2019 60.6 60.6 July 1, 2019 to Sept. 30, 2019 60.5 60.5 Oct. 1, 2019 to Dec. 31, 2019 60.4 60.4 Jan. 1, 2020 to Mar. 31, 2020 60.3 60.3 April 1, 2020 to June 30, 2020 60.2 60.2 July 1, 2020 to Dec. 31, 2020 60.1 60.1
Disclosure of interests in subsidiaries	Year ended Dec. 31 2020 2019 2018 Revenues 436 446 462 Net earnings 97 183 241 Total comprehensive income 223 138 281 Amounts attributable to the non-controlling interests: Net earnings 40 73 94 Total comprehensive income 90 56 110 Distributions paid to non-controlling interests 80 69 79 As at Dec. 31 2020 2019 Current assets 743 293 Long-term assets 2,913 3,409 Current liabilities (364) (152) Long-term liabilities (987) (1,237) Total equity (2,305) (2,313) Equity attributable to non-controlling interests (948) (941) Non-controlling interests’ share (per cent) 39.9 39.6 B. TA Cogen Year ended Dec. 31 2020 2019 2018 Results of operations Revenues 146 181 185 Net earnings (loss) (13) 43 29 Total comprehensive income (loss) (13) 43 29 Amounts attributable to the non-controlling interest: Net earnings (loss) (6) 21 14 Total comprehensive income (loss) (6) 21 14 Distributions paid to Canadian Power Holdings Inc. 17 37 86 As at Dec. 31 2020 2019 Current assets 69 41 Long-term assets 323 328 Current liabilities (78) (27) Long-term liabilities (37) (19) Total equity (277) (323) Equity attributable to Canadian Power Holdings Inc. (136) (160) Non-controlling interest share (per cent) 49.99 49.99 Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2020, 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, 2020
Subclassifications of assets, liabilities and equities [abstract]
Trade and Other Receivables	As at Dec. 31 2020 2019 Trade accounts receivable 488 399 Collateral paid (Note 16) 49 42 Current portion of finance lease receivables (Note 8) 36 15 Income taxes receivable 10 6 Trade and other receivables 583 462

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
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, 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 receivable — — 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. Carrying value as at Dec. 31, 2019 Derivatives Derivatives Amortized cost Total Financial assets Cash and cash equivalents (1) — — 411 411 Restricted cash — — 32 32 Trade and other receivables — — 462 462 Long-term portion of finance lease receivables — — 176 176 Risk management assets Current 71 95 — 166 Long-term 607 33 — 640 Other assets (Note 22) — — 47 47 Financial liabilities Accounts payable and accrued liabilities — — 413 413 Dividends payable — — 37 37 Risk management liabilities Current 1 80 — 81 Long-term 1 28 — 29 Credit facilities, long-term debt and lease liabilities (2) — — 3,212 3,212 Exchangeable securities (Note 25) — — 326 326 (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, 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 receivable — — 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. Carrying value as at Dec. 31, 2019 Derivatives Derivatives Amortized cost Total Financial assets Cash and cash equivalents (1) — — 411 411 Restricted cash — — 32 32 Trade and other receivables — — 462 462 Long-term portion of finance lease receivables — — 176 176 Risk management assets Current 71 95 — 166 Long-term 607 33 — 640 Other assets (Note 22) — — 47 47 Financial liabilities Accounts payable and accrued liabilities — — 413 413 Dividends payable — — 37 37 Risk management liabilities Current 1 80 — 81 Long-term 1 28 — 29 Credit facilities, long-term debt and lease liabilities (2) — — 3,212 3,212 Exchangeable securities (Note 25) — — 326 326 (1) Includes cash equivalents of nil. (2) Includes current portion.
Disclosure for sensitivity ranges for the base fair value	As at Dec. 31, 2020 Description Base fair value Sensitivity Valuation technique Unobservable input Range Reasonable possible change Long-term power sale – US 598 +35 Long-term price forecast Illiquid future power prices (per MWh) US$24 to US$32 Price decrease of US$3 or price increase of US$5 -59 Coal transportation – US (16) +3 Numerical derivative valuation Illiquid future power prices (per MWh) US$24 to US$32 Price decrease of US$3 or price increase of US$5 Volatility 15% to 40% 80% to 120% -5 Rail rate escalation US$21 to US$24 zero to 4% Full requirements – Eastern US 11 +3 Historical bootstrap Volume 95% to 105% -3 Cost of supply (+/-) US$1 per MWh Long-term wind energy sale –Eastern US (29) +22 Long-term price forecast Illiquid future power prices (per MWh) US$35 to US$52 Price increase or decrease of US$6 -22 Illiquid future REC prices (per unit) US$11 Price increase or decrease of US$1 Others (4) +5 -5 As at Dec. 31, 2019 Description Base fair value Sensitivity Valuation technique Unobservable input Range Reasonable possible change Long-term power sale – US 737 +46 Long-term price forecast Illiquid future power prices (per MWh) US$20 to US$28 Price decrease of US$3 or a price increase of US$9 -139 Structured products – Eastern US 7 +2 Option valuation techniques, historical bootstrap and historical price regression analysis Basis relationship 91% to 112% 4% to 6% -2 Non-standard shape factors 63% to 116% 4% to 10% Full requirements –Eastern US 10 +3 Historical bootstrap Volume 95% to 105% -3 Cost of supply (+/-) US$1 per MWh Long-term wind energy sale – Eastern US (28) +20 Long-term price forecast Illiquid future power prices (per MWh) US$38 to US$60 Price increase or decrease of US$6 -20 Illiquid future REC prices (per unit) US$9 Price increase or decrease of US$1 Others (6) +8 -8
Disclosure of risk management strategy related to hedge accounting	The following tables summarize the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification level during the years ended Dec. 31, 2020 and 2019, respectively: Year ended Dec. 31, 2020 Year ended Dec. 31, 2019 Hedge Non-hedge Total Hedge Non-hedge Total Opening balance 678 8 686 689 6 695 Changes attributable to: Market price changes on existing contracts (18) 3 (15) 77 8 85 Market price changes on new contracts — 7 7 — 14 14 Contracts settled (71) (10) (81) (57) (19) (76) Change in foreign exchange rates (16) 1 (15) (31) (1) (32) Transfers into (out of) Level III — — — — — — Net risk management assets at end of period 573 9 582 678 8 686 Additional Level III information: Gains (losses) recognized in other comprehensive income (34) — (34) 46 — 46 Total gains included in earnings before income taxes 71 11 82 57 21 78 Unrealized gains included in earnings before income — 1 1 — 2 2
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 Level I Level II Level III Total value (1) Exchangeables securities – Dec. 31, 2020 — 769 — 769 730 Long-term debt – Dec. 31, 2020 — 3,480 — 3,480 3,227 Exchangeable securities – Dec. 31, 2019 — 342 — 342 326 Long-term debt – Dec. 31, 2019 — 3,157 — 3,157 3,070 (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 2020 2019 2018 Unamortized net gain at beginning of year 9 49 105 New inception gains (losses) (1) (13) 3 (14) Change in foreign exchange rates — — 5 Amortization recorded in net earnings during the year (29) (43) (47) Unamortized net gain (loss) at end of year (2) (33) 9 49 (1) During 2020, the Corporation 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 1 forward price curve at inception of the contract.

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2020
Financial Instruments [Abstract]
Derivative Financial Instruments	Net Risk Management Assets and Liabilities Aggregate net risk management assets and (liabilities) are as follows: 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 As at Dec. 31, 2019 Cash flow Not Total Commodity risk management Current 70 15 85 Long-term 606 1 607 Net commodity risk management assets 676 16 692 Other Current — — — Long-term — 4 4 Net other risk management assets — 4 4 Total net risk management assets 676 20 696 The Corporation’s outstanding commodity derivative instruments designated as hedging instruments are as follows: As at Dec. 31 2020 2019 Type Notional Notional Notional Notional Electricity (MWh) (1) 95 — 222 — (1) Excludes the long-term power sale - US contract. For further details on this contract, refer to Note 15(B)(I)(c)(i). The Corporation’s outstanding commodity derivative instruments not designated as hedging instruments are as follows: As at Dec. 31 2020 2019 Type Notional Notional Notional Notional Electricity (MWh) 12,944 8,258 16,097 7,204 Natural gas (GJ) 23,035 177,448 38,062 55,023 Transmission (MWh) — 1,578 — 1,818 Emissions (MWh) 1,831 2,112 184 138 Emissions (tonnes) 2,160 2,365 2,436 2,446 As at Dec. 31 2020 2019 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign Exchange Forward Contracts - foreign-denominated receipts/expenditures CAD71 USD54 (2) 2021 CAD124 USD95 — 2020-2021 As at Dec. 31 2020 2019 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign exchange forward contracts – foreign-denominated receipts/expenditures AUD197 CAD181 (14) 2021-2024 AUD286 CAD266 — 2020 - 2023 USD47 CAD72 9 2021-2024 USD108 CAD139 (4) 2020 - 2023 AUD4 USD3 — 2021 CAD1 EUR1 — 2021 Foreign exchange forward contracts – foreign-denominated debt CAD191 USD150 2 2022 CAD191 USD150 6 2022
Net Arrangements	Information about the Corporation’s financial assets and liabilities that are subject to enforceable master netting arrangements or similar agreements is as follows: As at Dec. 31 2020 2019 Current Long-term Current Long-term Current Long-term Current Long-term Gross amounts recognized 120 69 (132) (104) 316 631 (191) (100) Gross amounts set-off (69) (10) 69 10 (140) (42) 140 42 Net amounts as included in the 51 59 (63) (94) 176 589 (51) (58)
Effect of Hedges	The impact of hedged items designated in hedging relationships on OCI and net earnings is: Year ended Dec. 31, 2020 Effective portion Ineffective portion Derivatives in cash Pre-tax Location of (gain) loss Pre-tax (gain) loss Location of (gain) loss Pre-tax Commodity contracts 41 Revenue (137) Revenue — Foreign exchange forwards on project hedges (1) Property, plant and equipment — Foreign exchange (gain) loss — Forward starting interest rate swaps (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 Pre-tax Location of (gain) Pre-tax Location of (gain) loss Pre-tax Commodity contracts 77 Revenue (59) Revenue — Forward starting interest rate swaps — Interest expense 6 Interest expense — OCI impact 77 OCI impact (53) Net earnings impact — Year ended Dec. 31, 2018 Effective portion Ineffective portion Derivatives in cash Pre-tax Location of (gain) loss reclassified from OCI Pre-tax Location of (gain) loss Pre-tax Commodity contracts (9) Revenue (67) Revenue — Foreign exchange forwards on US debt — Foreign exchange (gain) loss 3 Foreign exchange (gain) loss — Forward starting interest rate swaps — Interest expense 7 Interest expense — OCI impact (9) OCI impact (57) 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 Corporation’s functional currency, is outlined below. The sensitivity analysis has been prepared using management’s assessment that an average three cent (2019 — three cent, 2018 — four 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 2020 2019 2018 Currency Net earnings increase (decrease) (1) OCI gain (1),(2) Net earnings increase (1) OCI gain (1),(2) Net earnings decrease (1) OCI gain (1),(2) USD (8) 1 (18) 2 (13) — AUD (4) — (6) — (7) — Total (12) 1 (24) 2 (20) — (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 Corporation’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at Dec. 31, 2020: Investment grade (Per cent) Non-investment grade (Per cent) Total (Per cent) Total Trade and other receivables (1) 92 8 100 583 Long-term finance lease receivable 100 — 100 228 Risk management assets (1) 93 7 100 692 Loan receivable (2) — 100 100 52 Total 1,555 (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	2021 2022 2023 2024 2025 2026 and thereafter Total Accounts payable and accrued liabilities 599 — — — — — 599 Long-term debt (1) 96 626 277 119 136 2,010 3,264 Exchangeable securities (2) — — — — 750 — 750 Commodity risk management (assets) (92) (87) (131) (131) (103) 2 (542) Other risk management (assets) liabilities 14 — 1 (2) — (1) 12 Lease liabilities (3) (5) 6 5 5 5 118 134 Interest on long-term debt and lease liabilities (4) 161 153 126 119 113 893 1,565 Interest on exchangeable securities (2, 4) 53 52 53 52 — — 210 Dividends payable 59 — — — — — 59 Total 885 750 331 162 901 3,022 6,051 (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 incentive of $13 million, expected to be received in 2021. The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount, timing and uncertainty of future cash flows: Maturity 2021 2022 2023 2024 2025 2026 and thereafter Cash flow hedges (1) Foreign currency forward contracts Notional amount ($ millions) CAD/USD 54 — — — — — Average Exchange Rate CAD/USD 0.7648 — — — — — Commodity derivative instruments Electricity Notional amount (thousands MWh) 3,424 3,329 3,329 3,338 2,628 — Average Price ($ per MWh) 69.51 71.91 73.72 75.56 77.44 — (1) The interest rate swaps detailed above both settle in 2021.
Hedging Instruments	The impact of the hedging instruments on the statement of financial position is as follows: 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 As at Dec. 31, 2019 Notional amount Carrying amount Line item in the statement of financial position Change in fair Commodity price risk Cash flow hedges Physical power sales 19 MMWh 678 Risk management assets 47 Foreign currency risk Net investment hedges Foreign-denominated debt USD370 CAD483 Credit facilities, long-term debt and lease liabilities 21 The impact of the hedged items on the statement of financial position is as follows: As at Dec. 31 2020 2019 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 – Centralia (33) 417 47 527 Interest rate risk Cash flow hedges Interest expense on long-term 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 11 (21) 21 (21) (1) Included in AOCI.

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure of inventories [Abstract]
Disclosure Of The Components Of Inventories	The components of inventory are as follows: As at Dec. 31 2020 2019 Parts and materials 107 108 Coal 83 130 Deferred stripping costs 8 6 Natural gas 2 3 Purchased emission credits (1) 38 4 Total 238 251 (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: Balance, Dec. 31, 2018 242 Net addition 12 Change in foreign exchange rates (3) Balance, Dec. 31, 2019 251 Net addition 26 Writedowns (37) Change in foreign exchange rates (2) Balance, Dec. 31, 2020 238

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
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 1-52 years Wind generation 1-29 years Gas generation 1-17 years Coal generation 1-29 years Mining property and equipment 1-9 years Capital spares and other 2-52 years A reconciliation of the changes in the carrying amount of PP&E is as follows: Land Coal Gas generation Renewable Mining property Assets under Capital spares and other (1) Total Cost As at Dec. 31, 2018 94 5,937 1,964 3,286 1,338 200 383 13,202 Adjustments on implementation of IFRS 16 — — — (7) (101) — — (108) Additions — — — — 407 115 522 Acquisitions (Note 4(R) and 4(T)) (2) — 300 — — — 139 — 439 Disposals (3) (2) (389) (260) — (34) — (19) (704) (Impairment) reversals (Note 7) — 448 — (2) (15) — — 431 Revisions and additions to decommissioning and restoration costs (Note 23) — (62) 11 2 26 — — (23) Retirement of assets — (158) (26) (7) (10) — — (201) Change in foreign exchange rates (1) (63) (40) (17) (3) (4) (6) (134) Transfers (4) — 103 22 319 25 (514) 16 (29) As at Dec. 31, 2019 91 6,116 1,671 3,574 1,226 228 489 13,395 Additions — — — — — 478 8 486 Acquisitions (Note 4(K)) — — 1 — — — — 1 Disposals (2) (1) — — — — (2) (5) Impairment (Note 7) (9) (69) — (2) — — (1) (81) Revisions and additions to decommissioning and restoration costs (Note 23) — 21 (11) 8 76 — — 94 Retirement of assets — (35) (12) (7) (3) — (1) (58) Change in foreign exchange rates (1) (37) 45 (14) (2) — 6 (3) Transfers (4) 17 142 (263) 33 (29) (211) (120) (431) As at Dec. 31, 2020 96 6,137 1,431 3,592 1,268 495 379 13,398 Accumulated depreciation As at Dec. 31, 2018 — 3,765 1,128 1,161 830 — 154 7,038 Adjustments on implementation of IFRS 16 — — — (3) (43) — — (46) Depreciation — 304 77 136 97 — 16 630 Retirement of assets — (158) (23) (3) (6) — — (190) Disposals (3) — (170) (255) — (14) — — (439) Impairment reversal (Note 7) — 297 — — — — — 297 Change in foreign exchange rates — (52) (16) (4) (2) — (2) (76) Transfers — 10 (11) (3) (22) — — (26) As at Dec. 31, 2019 — 3,996 900 1,284 840 — 168 7,188 Depreciation — 352 76 142 133 — 14 717 Retirement of assets — (31) (10) (6) (4) — — (51) Disposals — (1) — — — — (1) (2) Change in foreign exchange rates — (35) 18 (4) (2) — 2 (21) Transfers — — (212) — (29) — (14) (255) As at Dec. 31, 2020 — 4,281 772 1,416 938 — 169 7,576 Carrying amount As at Dec. 31, 2018 94 2,172 836 2,125 508 200 229 6,164 As at Dec. 31, 2019 91 2,120 771 2,290 386 228 321 6,207 As at Dec. 31, 2020 96 1,856 659 2,176 330 495 210 5,822 (1) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance, and the Australian gas pipeline. (2) 2019 includes $308 million related to the acquisition of the Keephills 3 facility with $300 million included in coal generation and the remainder in assets under construction. (3) In 2019, we sold the Genesee 3 facility and sold the major components of the Mississauga facility. In addition, Centralia sold boiler parts included in capital spares and other for a net loss of $17 million. The Highvale mine also sold trucks included in mining property and equipment for a net loss of $18 million. Both were recognized in other gains on the statement of earnings (loss).

Right of Use Assets (Tables)

Right of Use Assets (Tables)	12 Months Ended
	Dec. 31, 2020
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 New leases recognized Jan. 1, 2019 29 22 1 — — 52 Adjustments on recognition (1) (1) (4) — — — (5) Transfers from PP&E, intangibles — — 3 35 — 38 As at Jan. 1, 2019 28 18 4 35 — 85 Additions 32 2 — 2 45 81 Depreciation (1) (4) (2) (11) — (18) Changes in foreign exchange rates (1) — — — — (1) Transfers — — — (1) — (1) 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

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2020
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: Coal rights Software Power Intangibles Total Cost As at Dec. 31, 2018 185 339 237 46 807 Assets transferred to right-of-use assets on implementation of IFRS 16 (Note 19) — (5) — — (5) Additions — — — 14 14 Acquisition — 1 — 15 16 Disposals (Note 4(R)) (37) (1) — — (38) Change in foreign exchange rates — (4) (1) (1) (6) Transfers 1 48 14 (63) — As at Dec. 31, 2019 149 378 250 11 788 Additions — — — 14 14 Acquisition (Note 4(K)) — — 37 — 37 Disposals — (1) — — (1) Change in foreign exchange rates — — (2) — (2) Transfers — 35 (16) (22) (3) As at Dec. 31, 2020 149 412 269 3 833 Accumulated amortization As at Dec. 31, 2018 117 221 96 — 434 Assets transferred to right-of-use assets on — (3) — — (3) Amortization 8 31 11 — 50 Disposals (Note 4(R)) (9) (1) — — (10) Change in foreign exchange rates — (1) — — (1) Transfers 1 (1) — — — As at Dec. 31, 2019 117 246 107 — 470 Amortization 8 28 15 — 51 Disposals — (1) — — (1) Transfers — (1) 1 — — As at Dec. 31, 2020 125 272 123 — 520 Carrying amount As at Dec. 31, 2018 68 118 141 46 373 As at Dec. 31, 2019 32 132 143 11 318 As at Dec. 31, 2020 24 140 146 3 313 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 2020 2019 Hydro 258 258 Wind and Solar 175 176 Energy Marketing 30 30 Total goodwill 463 464

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2020
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: Coal rights Software Power Intangibles Total Cost As at Dec. 31, 2018 185 339 237 46 807 Assets transferred to right-of-use assets on implementation of IFRS 16 (Note 19) — (5) — — (5) Additions — — — 14 14 Acquisition — 1 — 15 16 Disposals (Note 4(R)) (37) (1) — — (38) Change in foreign exchange rates — (4) (1) (1) (6) Transfers 1 48 14 (63) — As at Dec. 31, 2019 149 378 250 11 788 Additions — — — 14 14 Acquisition (Note 4(K)) — — 37 — 37 Disposals — (1) — — (1) Change in foreign exchange rates — — (2) — (2) Transfers — 35 (16) (22) (3) As at Dec. 31, 2020 149 412 269 3 833 Accumulated amortization As at Dec. 31, 2018 117 221 96 — 434 Assets transferred to right-of-use assets on — (3) — — (3) Amortization 8 31 11 — 50 Disposals (Note 4(R)) (9) (1) — — (10) Change in foreign exchange rates — (1) — — (1) Transfers 1 (1) — — — As at Dec. 31, 2019 117 246 107 — 470 Amortization 8 28 15 — 51 Disposals — (1) — — (1) Transfers — (1) 1 — — As at Dec. 31, 2020 125 272 123 — 520 Carrying amount As at Dec. 31, 2018 68 118 141 46 373 As at Dec. 31, 2019 32 132 143 11 318 As at Dec. 31, 2020 24 140 146 3 313 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 2020 2019 Hydro 258 258 Wind and Solar 175 176 Energy Marketing 30 30 Total goodwill 463 464

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure of financial assets [abstract]
Disclosure of components in other assets	The components of other assets are as follows: As at Dec. 31 2020 2019 South Hedland prepaid transmission access and distribution costs 70 67 Deferred licence fees — 9 Project development costs 25 19 Long-term prepaids and other assets 59 56 Loan receivable 52 47 Total other assets 206 198

Decommissioning and Other Pro_2

Decommissioning and Other Provisions (Tables)	12 Months Ended
	Dec. 31, 2020
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 Total Balance, Dec. 31, 2018 407 49 456 IFRS 16 transition adjustment — (2) (2) Liabilities incurred 7 7 14 Liabilities settled (34) (9) (43) Accretion 23 — 23 Acquisition of liabilities 16 3 19 Disposition of liabilities (23) (9) (32) Revisions in estimated cash flows (1) 96 7 103 Revisions in discount rates (1) 16 — 16 Reversals — (1) (1) Change in foreign exchange rates (7) — (7) 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 (2) 61 11 72 Revisions in discount rates (3) 36 — 36 Reversals — (6) (6) Change in foreign exchange rates (4) — (4) Balance, Dec. 31, 2020 608 65 673 (1) During 2019, the Corporation adjusted the Centralia mine decommissioning and restoration provision as management no longer believes that the fine coal recovery and reclamation work will occur as originally proposed. Refer to Note 3(A)(III) for further details. In addition, due to the changes in estimated useful lives, the discount rates used for the Alberta Thermal and mining operations decommissioning provisions were changed. The use of a lower inflation rate decreased the corresponding liabilities. (2) During 2020, the Corporation 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. Refer to Note 3(A)(III) for further details. This increase was partially offset by a decrease in the Sarnia decommissioning and restoration provision as a result of an updated engineering study. (3) 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, 2019 501 45 546 Current portion 36 22 58 Non-current portion 465 23 488 Balance, Dec. 31, 2020 608 65 673 Current portion 21 38 59 Non-current portion 587 27 614

Credit Facilities, Long-Term _2

Credit Facilities, Long-Term Debt and Lease Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of borrowings outstanding	The amounts outstanding are as follows: As at Dec. 31 2020 2019 Carrying Face Interest (1) Carrying Face Interest (1) Credit facilities (2) 114 114 2.7 % 220 220 3.5 % Debentures 249 251 7.1 % 647 651 5.8 % Senior notes (3) 886 894 5.4 % 905 914 5.4 % Non-recourse (4) 1,837 1,858 4.1 % 1,144 1,157 4.3 % Other (5) 141 147 7.1 % 154 162 7.1 % 3,227 3,264 3,070 3,104 Lease liabilities 134 142 3,361 3,212 Less: current portion of long-term debt (97) (494) Less: current portion of lease liabilities (8) (19) Total current long-term debt and lease liabilities (105) (513) Total credit facilities, long-term debt and lease 3,256 2,699 (1) Interest is an average rate weighted by principal amounts outstanding 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, 2020 — US$700 million (Dec. 31, 2019 — US$700 million). (4) Includes AU$800 million TEC offering. (5) Includes US$110 million at Dec. 31, 2020 (Dec. 31, 2019 — US$117 million) of tax equity financing. The Corporation's credit facilities are summarized in the table below: As at Dec. 31, 2020 Facility Utilized Available Maturity Outstanding letters of credit (1) Actual drawings TransAlta Corporation Committed syndicated bank facility (2) 1,250 379 114 757 Q2 2023 Canadian committed bilateral credit facilities (3) 240 150 — 90 Q2 2021 & 2022 TransAlta Renewables Committed credit facility (2) 700 92 — 608 Q2 2023 Total 2,190 621 114 1,455 (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, 2020, we provided cash collateral of $49 million. (2) TransAlta has letters of credit of $89 million and TransAlta Renewables has letters of credit of $92 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities. (3) One of the bilateral $80 million credit facilities has a maturity date of Q2 2021;the remaining two bilateral credit facilities has a maturity date of Q2, 2022.
Disclosure of principal repayments	2021 2022 2023 2024 2025 2026 and thereafter Total Principal repayments (1) 96 626 277 119 136 2,010 3,264 Lease liabilities (2) (5) 6 5 5 5 118 134 (1) Excludes impact of hedge accounting and derivatives. (2) Lease liabilities include a lease incentive of $13 million, expected to be received in 2021.

Exchangeable Securities (Tables

Exchangeable Securities (Tables)	12 Months Ended
	Dec. 31, 2020
Exchangeable Securities [Abstract]
Disclosure of borrowing costs	750 million Exchangeable Securities As at Dec. 31, 2020 Dec. 31, 2019 Carrying value Face value Interest Carrying value Face value Interest Exchangeable debentures – due May 1, 2039 330 350 7 % 326 350 7 % Exchangeable preferred shares (1) 400 400 7 % — — 7 % Total long term debt 730 750 326 350 (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, 2020 Dec. 31, 2019 Description Base fair value Sensitivity Base fair value Sensitivity Option to exchange – embedded derivative — nil -33 — nil -27

Defined Benefit Obligation an_2

Defined Benefit Obligation and Other Long-Term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 Defined benefit obligation (Note 31) 282 268 Long-term incentive accruals (Note 30) 4 4 Other 12 29 Total 298 301

Common Shares (Tables)

Common Shares (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 277.0 2,978 284.6 3,059 Purchased and cancelled under the NCIB (7.3) (79) (7.7) (83) Effects of share-based payment plans — (3) — — Stock options exercised 0.1 — 0.1 2 Issued and outstanding, end of year 269.8 2,896 277.0 2,978 The following are the effects of the Corporation's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2020 2019 Total shares purchased (1) 7,352,600 7,716,300 Average purchase price per share $ 8.33 $ 8.80 Total cost 61 68 Weighted average book value of shares cancelled 79 83 Amount recorded in deficit 18 15 (1) As at Dec. 31, 2020, includes 456,200 (2019 -189,900) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares. As at Dec. 31 2020 2019 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 10.2 248 10.2 248 Series B 1.8 45 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 2020 2019 2018 Net earnings (loss) attributable to common shareholders (336) 52 (248) Basic and diluted weighted average number of common shares outstanding (millions) 275 283 287 Net earnings (loss) per share attributable to common shareholders, basic and diluted (1.22) 0.18 (0.86)

Preferred Shares (Tables)

Preferred Shares (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 277.0 2,978 284.6 3,059 Purchased and cancelled under the NCIB (7.3) (79) (7.7) (83) Effects of share-based payment plans — (3) — — Stock options exercised 0.1 — 0.1 2 Issued and outstanding, end of year 269.8 2,896 277.0 2,978 The following are the effects of the Corporation's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2020 2019 Total shares purchased (1) 7,352,600 7,716,300 Average purchase price per share $ 8.33 $ 8.80 Total cost 61 68 Weighted average book value of shares cancelled 79 83 Amount recorded in deficit 18 15 (1) As at Dec. 31, 2020, includes 456,200 (2019 -189,900) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares. As at Dec. 31 2020 2019 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 10.2 248 10.2 248 Series B 1.8 45 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, 2020, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over Benchmark (per cent) Convertible to A Fixed 0.67724 March 31, 2021 2.03 B B Floating 0.73801 March 31, 2021 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 2020, 2019 and 2018: Total dividends declared Series 2020 2019 (1) 2018 A 9 5 9 B (2) 1 1 1 C 14 8 14 E 15 9 15 G 10 7 11 Total for the year 49 30 50 (1) No dividends were declared in the first quarter of 2019 as the quarterly dividend related to the period covering the first quarter of 2019 was declared in December 2018.

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure of analysis of other comprehensive income by item [abstract]
Disclosure of changes in accumulated other comprehensive income (loss)	The components of, and changes in, accumulated other comprehensive income (loss) are as follows: 2020 2019 Currency translation adjustment Opening balance, Jan. 1 (21) 17 Gains (losses) on translating net assets of foreign operations, net of reclassifications to net earnings, (11) (59) Gains (losses) on financial instruments designated as hedges of foreign operations, net of 11 21 Balance, Dec. 31 (21) (21) Cash flow hedges Opening balance, Jan. 1 527 508 Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax (1) (91) 19 Balance, Dec. 31 436 527 Employee future benefits Opening balance, Jan. 1 (55) (29) Net actuarial gains (losses) on defined benefit plans, net of tax (2) (11) (26) Balance, Dec. 31 (66) (55) Other Opening balance, Jan. 1 3 (15) Change in ownership of TransAlta Renewables — 1 Intercompany investments at FVOCI (50) 17 Balance, Dec. 31 (47) 3 Accumulated other comprehensive income 302 454 (1) Net of income tax of $23 million for the year ended Dec. 31, 2020 (2019 — $6 million). (2) Net of income tax of $3 million for the year ended Dec. 31, 2020 (2019 — $7 million).

Share-Based Payment Plans (Tabl

Share-Based Payment Plans (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020, 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 - 10.00 4.0 4.2 6.85
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, 2020, 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 - 10.00 4.0 4.2 6.85 (1) Options currently exercisable as at Dec. 31, 2020.

Employee Future Benefits (Table

Employee Future Benefits (Tables)	12 Months Ended
	Dec. 31, 2020
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, 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 Year ended Dec. 31, 2018 Registered Supplemental Other Total Current service cost 9 2 1 12 Administration expenses 1 — — 1 Interest cost on defined benefit obligation 18 3 1 22 Interest on plan assets (13) — — (13) Defined benefit expense 15 5 2 22 Defined contribution expense 10 — — 10 Net expense 25 5 2 32 The expected employer contributions for 2021 for the defined benefit pension and other post-employment benefit plans are as follows: Registered Supplemental Other Total Expected employer contributions 5 5 2 12
Defined Benefit Obligation	The status of the defined benefit pension and other post-employment benefit plans is as follows: 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) Year ended Dec. 31, 2019 Registered Supplemental Other Total Fair value of plan assets 373 13 — 386 Present value of defined benefit obligation (543) (99) (22) (664) Funded status – plan deficit (170) (86) (22) (278) Amount recognized in the consolidated financial statements: Accrued current liabilities (3) (5) (2) (10) Other long-term liabilities (167) (81) (20) (268) Total amount recognized (170) (86) (22) (278) 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, 2018 514 80 25 619 Current service cost 7 2 1 10 Interest cost 19 3 1 23 Benefits paid (51) (4) (1) (56) Curtailment (3) — — (3) Actuarial gain arising from demographic assumptions — — (2) (2) Actuarial loss arising from financial assumptions 57 9 2 68 Actuarial gain (loss) arising from experience adjustments 2 9 (4) 7 Effect of translation on US plans (2) — — (2) 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 demographic assumptions — — — — 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
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, 2018 368 13 — 381 Interest on plan assets 12 1 — 13 Net return on plan assets 40 — — 40 Contributions 6 4 1 11 Benefits paid (50) (5) (1) (56) Administration expenses (2) — — (2) Effect of translation on US plans (1) — — (1) 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 The fair value of the Corporation’s defined benefit plan assets by major category is as follows: 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 Year ended Dec. 31, 2019 Level I Level II Level III Total Equity securities Canadian — 66 — 66 US — 28 — 28 International — 102 — 102 Private — — 1 1 Bonds AAA — 40 — 40 AA — 68 — 68 A — 37 — 37 BBB 1 21 — 22 Below BBB — 3 — 3 Money market and cash and cash equivalents — 19 — 19 Total 1 384 1 386
Assumptions	Assumptions The significant actuarial assumptions used in measuring the Corporation’s defined benefit obligation for the defined benefit pension and other post-employment benefit plans are as follows: As at Dec. 31, 2020 As at Dec. 31, 2019 (per cent) Registered Supplemental Other Registered Supplemental Other Accrued benefit obligation Discount rate 2.4 2.3 2.3 3.0 3.0 3.0 Rate of compensation increase 2.9 3.0 — 2.8 3.0 — Assumed health-care cost trend rate Health-care cost escalation (1)(3) — — 6.8 — — 7.0 Dental-care cost escalation — — 4.0 — — 4.0 Benefit cost for the year Discount rate 3.0 3.0 3.0 3.9 3.8 3.9 Rate of compensation increase 2.9 3.0 — 2.5 3.0 — Assumed health-care cost trend rate Health-care cost escalation (2)(4) — — 7.1 — — 7.4 Dental-care cost escalation — — 4.0 — — 4.0 (1) 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. (2) 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. (3) 2019 Post- and pre-65 rates: decreasing gradually to 4.5% by 2030 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2027 for Canada. (4) 2019 Post- and pre-65 rates: decreasing gradually to 4.5% by 2027 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2027 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, 2020 Registered Supplemental Other Pension Other 1% decrease in the discount rate 74 17 2 3 1 1% increase in the salary scale 5 — — 4 1 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, 2020
Disclosure of interests in other entities [Abstract]
Disclosure of interests in joint arrangements	Joint arrangements at Dec. 31, 2020, included the following: Joint operations Segment Ownership (per cent) Description Sheerness Alberta Thermal 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 Pioneer Pipeline Alberta Thermal 50 Natural gas pipeline in Alberta operated by TMI Goldfields Power Australian Gas 50 Gas-fired facility in Australia operated by TransAlta Fort Saskatchewan North American Gas 60 Cogeneration facility in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta Fortescue River Australian 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 ventures 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, 2020
Disclosure of cash flow statement [Abstract]
Disclosure of non-cash operating working capital	Year ended Dec. 31 2020 2019 2018 (Use) source: Accounts receivable (79) 261 58 Prepaid expenses 2 — 19 Income taxes receivable (4) (6) — Inventory 6 (13) (21) Accounts payable, accrued liabilities and provisions 160 (130) (97) Income taxes payable 4 9 (3) Change in non-cash operating working capital 89 121 (44)
Cash flows from (used in) operating activities	Balance Dec. 31, 2019 Net cash flows New leases Dividends declared Foreign exchange impact Other Balance Dec. 31, 2020 Long-term debt and lease 3,212 133 16 — 5 (5) 3,361 Exchangeable securities 326 400 — — — 4 730 Dividends payable (common and 37 (86) — 107 — 1 59 Total liabilities from financing activities 3,575 447 16 107 5 — 4,150 Balance Dec. 31, 2018 Net cash flows New leases Tax shield on tax equity financing Dividends declared Foreign exchange impact Other Balance Dec. 31, 2019 Long-term debt and lease 3,267 (70) 133 (35) — (42) (41) 3,212 Exchangeable securities — 350 — — — — (24) 326 Dividends payable (common and 58 (85) — — 64 — — 37 Total liabilities from financing 3,325 195 133 (35) 64 (42) (65) 3,575

Capital (Tables)

Capital (Tables)	12 Months Ended
	Dec. 31, 2020
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 2020 2019 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 277.0 2,978 284.6 3,059 Purchased and cancelled under the NCIB (7.3) (79) (7.7) (83) Effects of share-based payment plans — (3) — — Stock options exercised 0.1 — 0.1 2 Issued and outstanding, end of year 269.8 2,896 277.0 2,978 B. NCIB Program Shares purchased by the Corporation 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 Corporation's purchase and cancellation of the common shares during the year: For the year ended Dec. 31 2020 2019 Total shares purchased (1) 7,352,600 7,716,300 Average purchase price per share $ 8.33 $ 8.80 Total cost 61 68 Weighted average book value of shares cancelled 79 83 Amount recorded in deficit 18 15 (1) As at Dec. 31, 2020, includes 456,200 (2019 -189,900) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date. C. Shareholder Rights Plan The Corporation 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 Corporation’s shareholders every three years for approval, and it was last approved on April 26, 2019. 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 Corporation’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 2020 2019 2018 Net earnings (loss) attributable to common shareholders (336) 52 (248) Basic and diluted weighted average number of common shares outstanding (millions) 275 283 287 Net earnings (loss) per share attributable to common shareholders, basic and diluted (1.22) 0.18 (0.86) E. Dividends On Dec. 23, 2020, the Corporation declared a quarterly dividend of $0.0450 per common share, payable on April 1, 2021. On Nov. 3, 2020, the Corporation declared a quarterly dividend of $0.0425 per common share, payable on Jan. 1, 2021. 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 2020 2019 Series Number of shares (millions) Amount Number of shares (millions) Amount Series A 10.2 248 10.2 248 Series B 1.8 45 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 G Cumulative Redeemable Rate Reset Preferred Shares Conversion On Aug. 30, 2019, the Corporation announced that, after taking into account all election notices received by the Sept. 15, 2019, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series G (the “Series G Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series H (the “Series H Shares”), there were 140,730 Series G Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series H Shares. Therefore, none of the Series G Shares were converted into Series H Shares on Sept. 30, 2019. As a result, the Series G Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series G Shares for the five-year period from and including Sept. 30, 2019, to, but excluding, Sept. 30, 2024, will be 4.988 per cent, which is equal to the five-year Government of Canada bond yield of 1.188 per cent, determined as of Aug. 30, 2019, plus 3.80 per cent, in accordance with the terms of the Series G Shares. II. Series E Cumulative Redeemable Rate Reset Preferred Shares Conversion On Sept. 17, 2017, the Corporation announced that, after taking into account all election notices received by the Sept. 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series E (the “Series E Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series F (the “Series F Shares”), there were 133,969 Series E Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series F Shares. Therefore, none of the Series E Shares were converted into Series F Shares on Sept. 30, 2017. As a result, the Series E Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series E Shares for the five-year period from and including Sept. 30, 2017, to, but excluding, Sept. 30, 2022, will be 5.194 per cent, which is equal to the five-year Government of Canada bond yield of 1.544 per cent, determined as of Aug. 31, 2017, plus 3.65 per cent, in accordance with the terms of the Series E Shares. III. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion On June 16, 2017, the Corporation announced that, after taking into account all election notices received by the June 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series C (the “Series C Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series D (the “Series D Shares”), there were 827,628 Series C Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series D Shares. Therefore, none of the Series C Shares were converted into Series D Shares on June 30, 2017. As a result, the Series C Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series C Shares for the five-year period from and including June 30, 2017, to, but excluding, June 30, 2022, will be 4.027 per cent, which is equal to the five-year Government of Canada bond yield of 0.927 per cent, determined as of May 31, 2017, plus 3.10 per cent, in accordance with the terms of the Series C Shares. IV. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion On March 17, 2016, the Corporation announced that 1,824,620 of its 12.0 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") were tendered for conversion, on a one-for-one basis, into Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares") after having taken into account all election notices. As a result of the conversion, the Corporation had 10.2 million Series A Shares and 1.8 million Series B Shares issued and outstanding at Dec. 31, 2020. The Series A Shares pay fixed cumulative preferential cash dividends on a quarterly basis for the five The Series B Shares pay quarterly floating rate cumulative preferential cash dividends for the five On March 1, 2021, the Corporation announced that it does not intend to exercise its right to redeem all or any part of the currently outstanding Series A Shares and Series B Shares. The Corporation has provided a notice to the registered shareholders of Series A Shares of the conversion right, on a one-for-one basis, into Series B Shares, and vice versa, providing Series B shareholders the right to exchange Series B Shares, on a one-for-one basis, into Series A Shares. Series A shareholders may elect to retain any or all of their current share holdings and continue to receive a fixed rate quarterly dividend. Series B shareholder may also elect to retain any or all of their current share holdings and continue to receive a floating rate quarterly dividend. After exercising conversion rights, if the balance that remains for either Series A Shares or Series B Shares is less than 1 million, that remaining balance of will automatically convert to the other Series. Shareholders' notice of intention to convert must be received by the transfer agent no later than March 16, 2021 and the conversion date will be effective March 31, 2021. The annual dividend rate for the Series A Shares for the five-year period from and including March 31, 2021, to, but excluding, March 31, 2026, will be 2.877 per cent, which is equal to the five-year Government of Canada Bond yield of 0.847 per cent, determined as of March 1, 2021, plus 2.03 per cent. The annual dividend rate for the Series B Shares for the three month floating rate period from and including March 31, 2021, to, but excluding, June 30, 2021, will be 2.103 per cent based on the most recent auction of 90-day Government of Canada Treasury Bills of 0.073 per cent plus 2.03 per cent. The Floating Quarterly Dividend Rate will be reset every quarter. V. 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 ▪ Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. ▪ Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2020, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over Benchmark (per cent) Convertible to A Fixed 0.67724 March 31, 2021 2.03 B B Floating 0.73801 March 31, 2021 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 2020, 2019 and 2018: Total dividends declared Series 2020 2019 (1) 2018 A 9 5 9 B (2) 1 1 1 C 14 8 14 E 15 9 15 G 10 7 11 Total for the year 49 30 50 (1) No dividends were declared in the first quarter of 2019 as the quarterly dividend related to the period covering the first quarter of 2019 was declared in December 2018. (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. 23, 2020, the Corporation declared a quarterly dividend of $0.16931 per share on the Series A preferred shares, $0.13186 per share on the Series B preferred shares, $0.25169 per share on the Series C preferred shares, $0.32463 per share on the Series E preferred shares, and $0.31175 per share on the Series G preferred shares, all payable on March 31, 2021. TransAlta’s capital is comprised of the following: As at Dec. 31 2020 2019 Increase/ Long-term debt (1) 3,361 3,212 149 Exchangeable securities 730 326 404 Equity Common shares 2,896 2,978 (82) Preferred shares 942 942 — Contributed surplus 38 42 (4) Deficit (1,826) (1,455) (371) Accumulated other comprehensive income 302 454 (152) Non-controlling interests 1,084 1,101 (17) Less: available cash and cash equivalents (2) (703) (411) (292) Less: principal portion of restricted cash on TransAlta OCP bonds (3) (11) (10) (1) Less: fair value asset of hedging instruments on long-term debt (4) (2) (7) 5 Total capital 6,811 7,172 (361) (1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt. (2) The Corporation 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 Corporation includes the principal portion of restricted cash on TransAlta OCP bonds because this cash is restricted specifically to repay outstanding debt. (4) The Corporation 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 investment grade credit rating	The Corporation has an investment-grade credit rating from DBRS (stable outlook). During 2020, Moody's reaffirmed its issuer rating of Ba1 with a stable outlook; DBRS reaffirmed the Corporation’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 Corporation’s Unsecured Debt rating and Issuer Rating of BB+ with stable outlook. The Corporation remains focused on strengthening its financial position and cash flow coverage ratios. Credit ratings provide information relating to the Corporation's financing costs, liquidity and operations and affect the Corporation's ability to obtain short-term and long-term financing and/or the cost of such financing. Key rating agencies assess TransAlta’s credit rating using a variety of methodologies, including financial ratios. The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and ratios are not defined under IFRS and may not be comparable to those used by other entities or by rating agencies. These ratios are summarized in the table below: As at Dec. 31 2020 2019 Target Funds from operations before interest to adjusted interest coverage (times) 4.2 4.5 4 to 5 Adjusted funds from operations to adjusted net debt (%) 18.3 19.0 20 to 25 Adjusted net debt to adjusted comparable earnings before interest, taxes, depreciation and amortization (times) 3.9 3.9 3.0 to 3.5 Deconsolidated net debt to deconsolidated comparable EBITDA (times) 4.6 4.2 2.5 to 3.0
Disclosure of cash flow statement	For the years ended Dec. 31, 2020 and 2019, cash inflows and outflows are summarized below. The Corporation manages variations in working capital using existing liquidity under credit facilities. Year ended Dec. 31 2020 2019 Increase Cash flow from operating activities 702 849 (147) Change in non-cash working capital (89) (121) 32 Cash flow from operations before changes in working capital 613 728 (115) Dividends paid on common shares (47) (45) (2) Dividends paid on preferred shares (39) (40) 1 Distributions paid to subsidiaries’ non-controlling interests (97) (106) 9 Property, plant and equipment expenditures (486) (417) (69) Inflow (outflow) (56) 120 (176)

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2020
Related Party [Abstract]
Disclosure of interests in subsidiaries	Year ended Dec. 31 2020 2019 2018 Revenues 436 446 462 Net earnings 97 183 241 Total comprehensive income 223 138 281 Amounts attributable to the non-controlling interests: Net earnings 40 73 94 Total comprehensive income 90 56 110 Distributions paid to non-controlling interests 80 69 79 As at Dec. 31 2020 2019 Current assets 743 293 Long-term assets 2,913 3,409 Current liabilities (364) (152) Long-term liabilities (987) (1,237) Total equity (2,305) (2,313) Equity attributable to non-controlling interests (948) (941) Non-controlling interests’ share (per cent) 39.9 39.6 B. TA Cogen Year ended Dec. 31 2020 2019 2018 Results of operations Revenues 146 181 185 Net earnings (loss) (13) 43 29 Total comprehensive income (loss) (13) 43 29 Amounts attributable to the non-controlling interest: Net earnings (loss) (6) 21 14 Total comprehensive income (loss) (6) 21 14 Distributions paid to Canadian Power Holdings Inc. 17 37 86 As at Dec. 31 2020 2019 Current assets 69 41 Long-term assets 323 328 Current liabilities (78) (27) Long-term liabilities (37) (19) Total equity (277) (323) Equity attributable to Canadian Power Holdings Inc. (136) (160) Non-controlling interest share (per cent) 49.99 49.99 Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2020, 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 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 2020 2019 2018 Total compensation 27 30 17 Comprised of: Short-term employee benefits 12 13 11 Post-employment benefits 2 2 2 Termination benefits — 2 — Share-based payments 13 13 4

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure of other provisions, contingent liabilities and contingent assets [Abstract]
Disclosure of commitments and future payments	Skookumchuck's approximate future payments under contractual commitments are as follows: 2021 2022 2023 2024 2025 2026 and thereafter Total Long-term service agreements (1) 1 1 1 1 1 28 33 (1) Refer to Note 36 for further details on long-term service agreements. In addition to commitments disclosed elsewhere in the financial statements, the Corporation 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: 2021 2022 2023 2024 2025 2026 and thereafter Total Natural gas, transportation and 141 149 137 134 134 1,353 2,048 Transmission 8 8 8 5 5 1 35 Coal supply and mining 81 105 101 67 56 — 410 Long-term service agreements 31 37 22 18 10 55 173 Operating leases 4 2 2 1 1 26 36 Growth 509 411 93 — — — 1,013 TransAlta Energy Transition Bill 6 6 6 — — — 18 Total 780 718 369 225 206 1,435 3,733

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2020
Disclosure of operating segments [abstract]
Disclosure of operating segments	Earnings Information Year ended Dec. 31, 2020 Hydro Wind and Solar (1) North American Gas (2) Australian Alberta Thermal (3) Centralia (3) Energy Corporate Total Equity accounted investments (1) IFRS Financials Revenues 152 332 217 158 619 497 122 7 2,104 (3) 2,101 Fuel, carbon 8 25 66 10 573 279 — 7 968 — 968 Gross margin 144 307 151 148 46 218 122 — 1,136 (3) 1,133 Operations, 37 53 49 32 131 60 30 80 472 — 472 Depreciation and 28 136 46 43 270 105 2 25 655 (1) 654 Asset impairment 2 — — — 75 7 — — 84 — 84 Taxes, other than 2 8 2 — 15 5 — 1 33 — 33 Net other operating — — — — (11) — — — (11) — (11) Operating income 75 110 54 73 (434) 41 90 (106) (97) (2) (99) Equity income from associate (1) — — — — — — — — — 1 1 Finance lease income — — 5 2 — — — — 7 — 7 Net interest expense (239) 1 (238) Foreign exchange 17 — 17 Gain on sale of assets 9 — 9 Earnings before (303) — (303) (1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. (2) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. (3) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. Year ended Dec. 31, 2019 Hydro Wind North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate Total Revenues 156 312 209 160 816 571 129 (6) 2,347 Fuel, carbon compliance and 7 16 74 9 570 416 — (6) 1,086 Gross margin 149 296 135 151 246 155 129 — 1,261 Operations, maintenance and 36 50 44 37 138 67 30 73 475 Depreciation and amortization 32 124 41 48 233 83 2 27 590 Asset impairment (reversal) 2 — — — 15 (10) — 18 25 Gain on termination of Keephills 3 coal rights contract (Note 4(R)) — — — — (88) — — — (88) Taxes, other than income taxes 3 8 1 — 13 3 — 1 29 Termination of Sundance B and C PPAs (Note 9) — — — — (56) — — — (56) Net other operating expense — (10) (1) — (40) — — 2 (49) Operating income (loss) 76 124 50 66 31 12 97 (121) 335 Finance lease income — — 6 — — — — — 6 Net interest expense (179) Foreign exchange loss (15) Gain on sale of assets and 46 Earnings before income taxes 193 (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020. Year ended Dec. 31, 2018 Hydro Wind North American Gas (1) Australian Alberta Thermal (2) Centralia (2) Energy Corporate Total Revenues 156 282 232 165 912 442 67 (7) 2,249 Fuel, carbon compliance and 6 17 96 8 666 314 — (7) 1,100 Gross margin 150 265 136 157 246 128 67 — 1,149 Operations, maintenance and 38 50 48 37 171 61 24 86 515 Depreciation and amortization 30 110 43 49 241 74 2 25 574 Asset impairment — 12 — — 38 — — 23 73 Taxes, other than income taxes 3 8 1 — 13 5 — 1 31 Termination of Sundance B and C PPAs (Note 9) — — — — (157) — — — (157) Net other operating income — (6) — — (41) — — — (47) Operating income (loss) 79 91 44 71 (19) (12) 41 (135) 160 Finance lease income — — 8 — — — — — 8 Net interest expense (250) Foreign exchange loss (15) Gain on sale of assets 1 Earnings before income taxes (96) (1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. (2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
Disclosure of selected consolidated statements of financial position information	Selected Consolidated Statements of Financial Position Information As at Dec. 31, 2020 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total PP&E 467 2,005 382 421 2,271 260 — 16 5,822 Right-of-use assets 6 55 1 4 53 — — 22 141 Intangible assets 4 159 32 34 31 5 7 41 313 Goodwill 258 175 — — — — 30 — 463 As at Dec. 31, 2019 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total PP&E 469 1,947 392 489 2,540 352 1 17 6,207 Right-of-use assets 6 56 — 4 68 — — 12 146 Intangible assets 5 173 2 37 41 6 9 45 318 Goodwill 258 176 — — — — 30 — 464 (1) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
Disclosure of components in other non-current assets	Additions to non-current assets are as follows: Year ended Dec. 31, 2020 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total Additions to non-current assets: PP&E 22 174 39 10 200 28 — 13 486 Intangible assets — — — — 1 — — 13 14 Year ended Dec. 31, 2019 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total Additions to non-current assets: PP&E 23 229 36 6 114 8 — 1 417 Intangible assets — — — — 2 — — 12 14 Year ended Dec. 31, 2018 Hydro Wind North American Gas (2) Australian Alberta Thermal (1) Centralia (1) Energy Corporate Total Additions to non-current assets: PP&E 16 117 21 6 101 14 — 2 277 Intangible assets — — — — 3 — — 17 20 (1) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
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 2020 2019 2018 Depreciation and amortization expense on the Consolidated Statements of 654 590 574 Depreciation included in fuel, carbon compliance and purchased power (Note 6) 144 119 136 Depreciation and amortization on the Consolidated Statements of Cash Flows 798 709 710
Disclosure of geographical areas	Revenues Year ended Dec. 31 2020 2019 2018 Canada 1,227 1,460 1,573 US 716 727 511 Australia 158 160 165 Total revenue 2,101 2,347 2,249 II. Non-Current Assets Property, plant and Right-of-use assets Intangible assets Other assets Goodwill As at Dec. 31 2020 2019 2020 2019 2020 2019 2020 2019 2020 2019 Canada 4,661 4,854 107 109 185 213 74 75 418 418 US 737 863 30 33 94 68 61 47 45 46 Australia 424 490 4 4 34 37 71 76 — — Total 5,822 6,207 141 146 313 318 206 198 463 464

Corporate Information (Details)

Corporate Information (Details)	Dec. 31, 2020segment
Disclosure of operating segments [line items]
Number of segments	8
Generation Segments [Member]
Disclosure of operating segments [line items]
Number of segments	6

Significant Accounting Polici_4

Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2020
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	1 year
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	52 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	1 year
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	29 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	1 year
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	17 years
Coal generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	1 year
Coal generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	29 years
Mining property and equipment | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	1 year
Mining property and equipment | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Useful life measured as period of time, property, plant and equipment	9 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	52 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	20 years

Accounting Changes - Narrative

Accounting Changes - Narrative (Details) - CAD ($) $ in Millions	3 Months Ended			6 Months Ended		12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2020	Jun. 30, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of changes in accounting estimates [line items]
Assets				$ 9,747		$ 9,747	$ 9,508
Depreciation and amortization						$ 654	590	$ 574
Impairment loss	$ 70
Coal generation | Maximum
Disclosure of changes in accounting estimates [line items]
Useful life measured as period of time, property, plant and equipment						29 years
Coal generation | Minimum
Disclosure of changes in accounting estimates [line items]
Useful life measured as period of time, property, plant and equipment						1 year
Wind and Solar
Disclosure of changes in accounting estimates [line items]
Useful life measured as period of time, property, plant and equipment					30 years
Wind and Solar | Maximum
Disclosure of changes in accounting estimates [line items]
Useful life measured as period of time, property, plant and equipment		15 years
Wind and Solar | Minimum
Disclosure of changes in accounting estimates [line items]
Useful life measured as period of time, property, plant and equipment		10 years
Change in Useful Lives Estimate | Sheerness
Disclosure of changes in accounting estimates [line items]
Depreciation and amortization							(8)
Change in Useful Lives Estimate | Coal generation
Disclosure of changes in accounting estimates [line items]
Depreciation and amortization							16
Change in Useful Lives Estimate | Wind and Solar
Disclosure of changes in accounting estimates [line items]
Depreciation and amortization							11
Decommissioning and restoration | Centralia Coal Mine
Disclosure of changes in accounting estimates [line items]
Provision for decommissioning, restoration and rehabilitation costs							141
Impairment loss							$ 141
Alberta Mine | Mining assets | Gross carrying amount
Disclosure of changes in accounting estimates [line items]
Assets				373		$ 373
Alberta Mine | Change in Useful Lives Estimate
Disclosure of changes in accounting estimates [line items]
Depreciation and amortization								$ 38
Alberta Mine | Change in Useful Lives Estimate | Mining assets
Disclosure of changes in accounting estimates [line items]
Depreciation and amortization				15
Alberta Mine | Decommissioning and restoration
Disclosure of changes in accounting estimates [line items]
Provision for decommissioning, restoration and rehabilitation costs	75
Sundance Unit 2
Disclosure of changes in accounting estimates [line items]
Impairment loss			$ 38
Sundance Unit 2 | Change in Useful Lives Estimate
Disclosure of changes in accounting estimates [line items]
Impairment loss			$ 38
Sundance Unit 3 | Change in Useful Lives Estimate
Disclosure of changes in accounting estimates [line items]
Impairment loss	$ 70
Sarnia | Decommissioning and restoration
Disclosure of changes in accounting estimates [line items]
Provision for decommissioning, restoration and rehabilitation costs				$ 15		$ 15

Significant and Subsequent Ev_3

Significant and Subsequent Events - Clean Energy Investment Plan (Details) t in Millions, MWh in Millions, $ in Millions	6 Months Ended	12 Months Ended
	Dec. 31, 2020CAD ($)projecttMW	Dec. 31, 2020CAD ($)projectMWhtMW	Dec. 31, 2019CAD ($)t	Dec. 31, 2018CAD ($)
Investment [Line Items]
Property, plant and equipment expenditures		$ 486	$ 417	$ 277
Assets	$ 9,747	9,747	$ 9,508
Inventory write-down		$ 37
Coal inventory, number | t	1	1	2.1
Coal inventory, increase due to mining | MWh		2.3
Coal inventory, decrease due to consumption | t		3.5
Depreciation and amortization		$ 654	$ 590	574
Inventory write-down		$ 37
Gross carrying amount
Investment [Line Items]
Property, plant and equipment expenditures			$ 417
Sundance Unit 5
Investment [Line Items]
Capacity of facility (in megawatts) | MW	730	730
Sundance Unit 5 | Minimum
Investment [Line Items]
Payments for development project expenditure		$ 800
Sundance Unit 5 | Maximum
Investment [Line Items]
Payments for development project expenditure		$ 825
Keephills Unit 1
Investment [Line Items]
Capacity of facility (in megawatts) | MW	70	70
Sundance Unit 4
Investment [Line Items]
Capacity of facility (in megawatts) | MW	113	113
Clean Energy Investment Plan | ALBERTA
Investment [Line Items]
Number of wind projects | project	1	1
Clean Energy Investment Plan | US
Investment [Line Items]
Number of wind projects | project	3	3
Clean Energy Investment Plan | Maximum
Investment [Line Items]
Payments for development project expenditure		$ 35
Alberta Mine | Change in Useful Lives Estimate
Investment [Line Items]
Depreciation and amortization				$ 38
Alberta Mine | Mining assets
Investment [Line Items]
Inventory write-down	$ 37
Inventory write-down	37
Alberta Mine | Mining assets | Change in Useful Lives Estimate
Investment [Line Items]
Depreciation and amortization	15
Alberta Mine | Mining assets | Gross carrying amount
Investment [Line Items]
Assets	$ 373	$ 373

Significant and Subsequent Ev_4

Significant and Subsequent Events - Pioneer Pipeline and Skookumchuck Wind Project (Details) $ in Millions, $ in Millions	Nov. 25, 2020CAD ($)MW	Nov. 25, 2020USD ($)	Oct. 01, 2020CAD ($)	Apr. 12, 2019	Dec. 17, 2018MMcf	Dec. 31, 2020CAD ($)J	Dec. 31, 2020terajoule	Nov. 01, 2019MMcf
Investment [Line Items]
Long-term firm natural gas delivery transportation, amount transferred per day						400	400
SP Skookumchuck Investment, LLC
Investment [Line Items]
Other cash payments to acquire interests in joint ventures, classified as investing activities						$ 86
NOVA Gas Transmission Ltd.
Investment [Line Items]
Long-term firm natural gas delivery transportation, amount transferred per day						351	275
Tidewater
Investment [Line Items]
Long-term firm natural gas delivery transportation, amount transferred per day						139	139
Pioneer Pipeline
Investment [Line Items]
Future option to acquire pipeline, ownership percentage					50.00%
Pioneer Pipeline | Tidewater
Investment [Line Items]
Proportion of ownership interest in joint operation					50.00%
Take or pay agreement, term						15 years
Natural gas pipeline capacity (mmcf) | MMcf					50			130
Payments for development project expenditure						$ 83
Pioneer Pipeline | Tidewater | Discontinued operations
Investment [Line Items]
Proceeds from sale of assets held for sale			$ 255
Skookumchuck
Investment [Line Items]
Proportion of ownership interest in joint operation	49.00%	49.00%		49.00%
Other cash payments to acquire interests in joint ventures, classified as investing activities	$ 86	$ 66
Capacity of facility (in megawatts) | MW	136.8
Investments in joint ventures	$ 163
Value of equity consideration received	$ 77	$ 59

Significant and Subsequent Ev_5

Significant and Subsequent Events - Asset Acquisitions (Details) - Keephills 3 - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Oct. 01, 2019
Investment [Line Items]
Working capital		$ 11
Asset Acquisition, Asset, Property, Plant And Equipment		308
Property, plant and equipment	$ 308
Other assets		3
Other liabilities		(2)
Decommissioning and other provisions		(19)
Total acquisition cost		$ 301

Significant and Subsequent Ev_6

Significant and Subsequent Events Information relating to business combination (Details) - Contracted Cogeneration Asset in Michigan $ in Millions	May 19, 2020CAD ($)
Disclosure of detailed information about business combination [line items]
Net working capital	$ 6
Property, plant and equipment	1
Intangible assets	37
Risk management liabilities (current and long-term)	(5)
Decommissioning provisions	(1)
Total identifiable net assets at fair value	38
Cash consideration	32
Total purchase consideration transferred	$ 38

Significant and Subsequent Ev_7

Significant and Subsequent Events - Other Disclosures (Details) $ / shares in Units, $ in Millions, $ in Millions, $ in Millions	Nov. 30, 2020	Oct. 30, 2020CAD ($)	Oct. 22, 2020CAD ($)	Oct. 22, 2020AUD ($)MW	May 19, 2020USD ($)MW	Oct. 01, 2019MW	May 22, 2019CAD ($)	May 01, 2019CAD ($)	Mar. 28, 2019CAD ($)	Mar. 28, 2019USD ($)	Mar. 22, 2019CAD ($)	Dec. 17, 2018aMW	Oct. 19, 2018MW	Jul. 20, 2018CAD ($)	Jun. 22, 2018CAD ($)$ / sharesshares	May 31, 2018CAD ($)MW	Feb. 20, 2018MW	Apr. 30, 2021CAD ($)	Dec. 31, 2018CAD ($)$ / sharesshares	Jul. 30, 2018	Sep. 30, 2020CAD ($)	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019CAD ($)$ / sharesshares	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Nov. 29, 2018	Dec. 31, 2020CAD ($)$ / sharesMWshares	Apr. 30, 2020shares	Jun. 21, 2018	May 28, 2021shares	Dec. 31, 2020CAD ($)$ / sharesMWshares	Dec. 31, 2019CAD ($)$ / sharesshares	Dec. 31, 2019USD ($)	Dec. 31, 2018CAD ($)$ / sharesshares	May 01, 2021	Jan. 08, 2021shares	Jan. 01, 2021CAD ($)	Dec. 31, 2020USD ($)MWshares	Dec. 23, 2020MW	Dec. 01, 2020MW	May 26, 2020shares	Dec. 31, 2019USD ($)shares	Aug. 26, 2019CAD ($)	May 27, 2019shares	Aug. 02, 2018	Jun. 28, 2018CAD ($)	Jun. 28, 2018USD ($)	Mar. 29, 2018CAD ($)	Mar. 09, 2018shares
Investment [Line Items]
Cash flows used in obtaining control of subsidiaries or other businesses, classified as investing activities																																	$ 32	$ 117		$ 30
Bonds issued				$ 800										$ 345
Interest rate				4.07%										4.509%
Impairment loss																					$ 70
Impairment loss, net of tax																					$ 52
Percentage of public float of common shares making up stock purchase agreement, shares authorized																																											7.02%
Gains on disposals of investments																								$ 88									0	88		0
Issued preferred capital																																																$ 33	$ 25
Receivables due from associates																													$ (98)				(98)							$ (72)
Transfer of equity from non-controlling interests																$ 1
Net proceeds on sale of non-controlling interest in subsidiary																																	0	0		144
Alberta off-coal agreement, annual cash payments, gross														$ 40																			40	40		40
Alberta off-coal agreement, annual cash payments, net														$ 37
Finance lease receivables																								191					264				264	191
Payments to acquire or redeem entity's shares																																	$ 57	68		23
Shares issued | shares																																	15,068,900
Forecast
Investment [Line Items]
Canada emergency wage subsidy, estimated value to be received, amount																																							$ 8
Power Purchase Arrangement
Investment [Line Items]
Balancing pool compensation estimate, termination of contractual arrangement																																																		$ 157
Termination of contractual arrangement, awarded amount																																													$ 56
Investment Agreement
Investment [Line Items]
Borrowings, annual fee payable								$ 1.5
Borrowings, annual fee payable, term								6 years
Share repurchases, period																																	3 years
NCIB Program
Investment [Line Items]
Issued capital																			$ 23					$ 68					$ 61				$ 61	$ 68		$ 23
Stock purchase agreement, number of shares authorized | shares																																											14,000,000			14,000,000					14,000,000
Stock purchase agreement, maximum shares purchase for a single trading day | shares																																228,157
Stock purchase agreement, percentage of average daily trading volume on the toronto stock exchange																														25.00%
Stock purchase agreement, Toronto Stock Exchange, twenty-five percent of daily trading volume | shares																														912,630
Number of shares issued and fully paid | shares																			3,264,500					7,716,300					7,352,600				7,352,600	7,716,300		3,264,500				7,352,600				7,716,300
Par value per share | $ / shares																			$ 7.02					$ 8.80					$ 8.33				$ 8.33	$ 8.80		$ 7.02
Percentage of issued and outstanding common shares making up stock purchase agreement, shares authorized																																														4.92%					4.86%
Payments to acquire or redeem entity's shares																																	$ 129
TransAlta Renewables Inc.
Investment [Line Items]
Proceeds from redemption of intercompany securities			$ 480	$ 515
Interest rate				4.32%
Amount receivable from employees				$ 200
Brookfield Renewable Partners
Investment [Line Items]
Number of shares in entity held by entity or by its subsidiaries or associates | shares																																						33,845,685
Number of shares in entity held by entity or by its subsidiaries or associates, expressed as a percentage of issued and outstanding common shares																																						12.40%
Brookfield Renewable Partners | Forecast
Investment [Line Items]
Proportion of ownership interests held by non-controlling interests																																					9.00%
Brookfield Renewable Partners | Investment Agreement
Investment [Line Items]
Interest rate								7.00%
Proceeds on sale of an organizational unit											$ 750
Other cash receipts from sales of equity or debt instruments of other entities, classified as investing activities		$ 400						$ 350
Borrowing costs incurred							$ 7.5
Commitment fee								$ 15
Percentage of total investment that makes up transaction costs											3.00%
Maximum | Investment Agreement
Investment [Line Items]
Issued capital											$ 250
WindCharger Battery Storage Project
Investment [Line Items]
Capacity of facility (in megawatts) | MW																													20				20							20
Proportion of ownership interest in joint operation																																	50.00%
Payments for development project expenditure																																	$ 14
Capacity of nameplate | MW																																	10
Windrise Wind Facility
Investment [Line Items]
Capacity of facility (in megawatts) | MW																																									207
Skookumchuck
Investment [Line Items]
Capacity of facility (in megawatts) | MW																																									137
Ada Cogeneration Facility
Investment [Line Items]
Capacity of facility (in megawatts) | MW																																									29
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
Centralia Unit 1
Investment [Line Items]
Capacity of facility (in megawatts) | MW																													1,340				1,340							1,340
Plant In Alberta
Investment [Line Items]
Capacity of facility (in megawatts) | MW						40
Kent Hills 3 Wind Project
Investment [Line Items]
Increase in contractual power capacity (in megawatts) | MW													167
Lakeswind
Investment [Line Items]
Borrowing costs incurred																																	$ 22	$ 23
Impairment loss																																				$ 12
Lakeswind | Property, plant and equipment
Investment [Line Items]
Impairment loss																																				11
Lakeswind | Intangible assets
Investment [Line Items]
Impairment loss																																				$ 1
Windrise
Investment [Line Items]
Capacity of facility (in megawatts) | MW												207
Renewable electricity support agreement, term												20 years
Area of land used for agriculture | a												11,000
Capital expenditure, per cent complete																													78.00%				78.00%							78.00%
Windrise | Minimum
Investment [Line Items]
Payments for development project expenditure																																	$ 270
Windrise | Maximum
Investment [Line Items]
Payments for development project expenditure																																	285
US Wind Projects
Investment [Line Items]
Notes and debentures issued																								$ 142					$ 72				72	142						$ 52				$ 105
Issued preferred capital																								78					$ 92				92	$ 78						$ 72				$ 59
EMG International, LLC
Investment [Line Items]
Equity participation percentage	30.00%
Genesee Unit 3
Investment [Line Items]
Capacity of facility (in megawatts) | MW						(466)
Proportion of ownership interest in joint operation						50.00%
Cash transferred																																	10
Payments from changes in ownership interests in subsidiaries that do not result in loss of control																																	1
Consideration received																								$ 77
Genesee Unit 3 | Capital Power
Investment [Line Items]
Equity participation percentage						100.00%
Keephills 3
Investment [Line Items]
Capacity of facility (in megawatts) | MW						463
Proportion of ownership interest in joint operation						50.00%																												50.00%	50.00%
Equity participation percentage						100.00%
US Wind Projects - Big Level
Investment [Line Items]
Capacity of facility (in megawatts) | MW																	90
Payments for development project expenditure									$ 7	$ 5
Borrowing costs incurred																																	$ 112	$ 122
Term of power purchase arrangement																	15 years
Value of equity consideration received																																			$ 85
US Wind Projects - Antrim
Investment [Line Items]
Capacity of facility (in megawatts) | MW																	29
Consideration received									(24)
Term of power purchase arrangement																	20 years
Loans and receivables									41
Investment property under construction or development									50
Intangible assets under development									$ 15
Value of equity consideration received																																			$ 41
TransAlta Renewables Inc.
Investment [Line Items]
Par value per share | $ / shares															$ 12.65
Equity participation percentage															61.00%
Number of shares issued | shares															11,860,000
Gross proceeds from changes in ownership interests in subsidiaries that do not result in loss of control															$ 150
Net proceeds on sale of non-controlling interest in subsidiary															$ 144
Number of shares outstanding | shares															161,000,000
TransAlta Renewables Inc. | Three Renewable Assets
Investment [Line Items]
Consideration received																(166)
Value of equity consideration received																62
Portion of consideration paid (received) consisting of cash and cash equivalents																$ 104
TransAlta Renewables Inc. | Kent Breeze
Investment [Line Items]
Capacity of facility (in megawatts) | MW																20
TransAlta Renewables Inc. | Lakeswind Solar Projects
Investment [Line Items]
Capacity of facility (in megawatts) | MW																21
TransAlta Renewables Inc. | Lakeswind Wind Farm
Investment [Line Items]
Capacity of facility (in megawatts) | MW																50
Kent Hills Wind L.P.
Investment [Line Items]
Interest rate																													4.55%				4.55%							4.55%
Proportion of ownership interests held by non-controlling interests																																	17.00%
TransAlta Renewables Inc.
Investment [Line Items]
Equity participation percentage																			60.90%	61.10%		60.20%	60.30%	60.40%	60.50%	60.60%	60.80%	61.00%	60.10%		64.00%
Proportion of ownership interests held by non-controlling interests																																	39.90%	39.60%	39.60%
TransAlta Renewables Inc. | Windrise Wind Facility
Investment [Line Items]
Percentage of voting equity interests acquired																																									100.00%
TransAlta Renewables Inc. | Windrise Wind Facility | Forecast
Investment [Line Items]
Consideration received																		$ 439
TransAlta Renewables Inc. | Skookumchuck
Investment [Line Items]
Percentage of voting equity interests acquired																																									49.00%
TransAlta Renewables Inc. | Ada Cogeneration Facility
Investment [Line Items]
Percentage of voting equity interests acquired																																									100.00%
Southern Cross Energy | BHP Billiton Nickel West Pty Ltd.
Investment [Line Items]
Capacity of facility (in megawatts) | MW				245
Battery supported solar photovoltaic farm | MW																																										18.5
Finance lease receivables																													$ 89				$ 89
Gains (losses) on disposals of non-current assets																																	12
Gain (loss) of derecognised financial assets at date of transfer																																	$ (77)
Debentures
Investment [Line Items]
Interest rate														6.40%																																	6.40%
Debentures | Minimum
Investment [Line Items]
Interest rate																													6.90%				6.90%							6.90%
Debentures | Maximum
Investment [Line Items]
Interest rate																													7.30%				7.30%							7.30%
6.65% Senior notes, due May 2018
Investment [Line Items]
Interest rate																			6.65%																	6.65%

Revenue (Details)

Revenue (Details) - CAD ($) $ in Millions	Oct. 01, 2019	Dec. 31, 2020	Dec. 31, 2019
Disclosure of disaggregation of revenue from contracts with customers [line items]
Performance obligations satisfied		$ 2	$ 0
Canadian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		13
Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		2,594
Alberta Thermal
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		31
Wind and Solar
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		13
Later than one year | Hydro
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		8
Second to fifth years inclusive | Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Performance obligations satisfied		$ 203
Genesee 3
Disclosure of disaggregation of revenue from contracts with customers [line items]
Ownership percentage sold			50.00%
Minimum
Disclosure of disaggregation of revenue from contracts with customers [line items]
Contracts for sale of byproducts of coal combustion, term		1 year
Minimum | Canadian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Performance obligations satisfied		$ 4
Minimum | Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Performance obligations satisfied		100
Minimum | Wind and Solar
Disclosure of disaggregation of revenue from contracts with customers [line items]
Performance obligations satisfied		2
Minimum | More than five years
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		2
Minimum | 2023 | Alberta Thermal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		5
Minimum | Annually thereafter | Alberta Thermal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		$ 40
Maximum
Disclosure of disaggregation of revenue from contracts with customers [line items]
Contracts for sale of byproducts of coal combustion, term		3 years
Maximum | Canadian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Performance obligations satisfied		$ 5
Maximum | Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Performance obligations satisfied		126
Maximum | Wind and Solar
Disclosure of disaggregation of revenue from contracts with customers [line items]
Performance obligations satisfied		5
Maximum | More than five years
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		3
Maximum | 2023 | Alberta Thermal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		10
Maximum | Annually thereafter | Alberta Thermal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations		$ 45
Keephills 3
Disclosure of disaggregation of revenue from contracts with customers [line items]
Proportion of ownership interest in joint operation	50.00%		50.00%

Revenue Disaggregation of Reven

Revenue Disaggregation of Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	$ 2,101	$ 2,347	$ 2,249
At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	58	78	65
Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	965	990	1,096
Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	1,023	1,068	1,161
Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	123	130	170
Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	407	296	165
Government incentives
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	5	8	16
Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	543	845	737
Hydro | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	152	156	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	141	142	132
Hydro | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	141	142	132
Hydro | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	7
Hydro | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Hydro | Operating segments | Government incentives
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	1	0	0
Hydro | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	10	14	17
Wind and Solar | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	329	312	282
Wind and Solar | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	25	27	18
Wind and Solar | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	236	217	188
Wind and Solar | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	261	244	206
Wind and Solar | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	27
Wind and Solar | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	(2)	18	(20)
Wind and Solar | Operating segments | Government incentives
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	4	8	16
Wind and Solar | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	66	42	53
North American Gas | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	217	209	232
North American Gas | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
North American Gas | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	196	190	206
North American Gas | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	196	190	206
North American Gas | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	8	0	0
North American Gas | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	4	2	4
North American Gas | Operating segments | Government incentives
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
North American Gas | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	9	17	22
Australian Gas | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	158	160	165
Australian Gas | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Australian Gas | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	90	87	91
Australian Gas | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	90	87	91
Australian Gas | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	60	65	68
Australian Gas | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Australian Gas | Operating segments | Government incentives
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Australian Gas | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	8	8	6
Alberta Thermal | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	619	816	912
Alberta Thermal | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	23	41	38
Alberta Thermal | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	302	354	479
Alberta Thermal | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	325	395	517
Alberta Thermal | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	55	65	68
Alberta Thermal | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	(12)	(17)	(1)
Alberta Thermal | Operating segments | Government incentives
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Alberta Thermal | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	251	373	328
Centralia | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	497	571	442
Centralia | Operating segments | At a point in time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	10	10	9
Centralia | Operating segments | Over time
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Centralia | Operating segments | Contract With Customers
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	10	10	9
Centralia | Operating segments | Lease Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Centralia | Operating segments | Derivatives Income
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	283	160	115
Centralia | Operating segments | Government incentives
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Centralia | Operating segments | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	204	401	318
Energy Marketing | Operating segments
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	122	129	67
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 | 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	122	129	67
Energy Marketing | Operating segments | Government incentives
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Energy Marketing | Operating segments | Other
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	7	(6)	(7)
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 | 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	12	4	0
Corporate and Other | Government incentives
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	0	0	0
Corporate and Other | Other
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenues	$ (5)	$ (10)	$ (7)

Revenue Contract Balances (Deta

Revenue Contract Balances (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)
Changes in Contract Liabilities [Roll Forward]
Consideration paid	$ 2	$ 0
Performance obligations satisfied	(2)	0
Current contract liabilities	1	1
Non-current contract liabilities	14	14
IFRS 16
Changes in Contract Liabilities [Roll Forward]
Contract liabilities at beginning of period	15	88
IFRS 16 transition adjustments	0	15
Amounts transferred to revenue included in opening balance	(1)	(10)
Consideration received	1	5
Increases due to interest accrued and expensed during the period	0	5
Contract termination associated with the purchase of Keephills 3 (Note 4(R))	0	(88)
Contract liabilities at end of period	$ 15	$ 15

Expenses by Nature - Expenses C

Expenses by Nature - Expenses Classified by Nature (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of products and services [line items]
Mine depreciation	$ 144	$ 119	$ 136
Salaries and benefits	24	28	32
Other operating expenses	0	1	0
Total	968	1,086	1,100
Total	472	475	515
Fuel, carbon compliance and purchased power
Disclosure of products and services [line items]
Fuel and carbon compliance	574	669	656
Coal inventory writedown (Note 17)	37	0	0
Purchased power	163	246	210
Mine depreciation	144	119	136
Salaries and benefits	50	52	98
Other operating expenses	0	0	0
Total	968	1,086	1,100
Operations, maintenance and administration
Disclosure of products and services [line items]
Fuel and carbon compliance	0	0	0
Coal inventory writedown (Note 17)	0	0	0
Purchased power	0	0	0
Mine depreciation	0	0	0
Salaries and benefits	235	228	245
Other operating expenses	237	247	270
Total	$ 472	$ 475	$ 515

Asset Impairment Charges and _2

Asset Impairment Charges and Reversals (Details) $ in Millions, $ in Millions	3 Months Ended		12 Months Ended
	Sep. 30, 2020CAD ($)	Sep. 30, 2018CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2012CAD ($)	Jun. 28, 2018
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss	$ 70
Write-downs (reversals of write-downs) of property, plant and equipment			$ 0		$ 18	$ 23
Gross carrying amount
Disclosure of impairment loss recognised or reversed [line items]
Write-downs (reversals of write-downs) of property, plant and equipment			81		(431)
Disposal groups classified as held for sale
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss					15
Sundance Unit 2
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss		$ 38
Lakeswind
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss						12
Lakeswind | Discount rates
Disclosure of impairment loss recognised or reversed [line items]
Significant unobservable input, assets								0.07
Property, plant and equipment | Centralia Thermal Facility
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss							$ 347
Provision for decommissioning, restoration and rehabilitation costs					141
Reversal of impairment loss					151
Property, plant and equipment | Lakeswind
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss						11
Property, plant and equipment | Sundance Unit 3
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss	70
Property, plant and equipment | BC Hydro Facility
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss	$ 2
Property, plant and equipment | Centralia mine and Sundance Unit 1
Disclosure of impairment loss recognised or reversed [line items]
Provision for decommissioning, restoration and rehabilitation costs			3
Land | Gross carrying amount
Disclosure of impairment loss recognised or reversed [line items]
Write-downs (reversals of write-downs) of property, plant and equipment			9		$ 0
Land | Gross carrying amount | Centralia Segment
Disclosure of impairment loss recognised or reversed [line items]
Impairment charges			$ (9)	$ (7)
Intangible assets | Lakeswind
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss						$ 1

Asset Impairment Charges and _3

Asset Impairment Charges and Reversals - Significant Inputs (Details)	12 Months Ended
	Dec. 31, 2019uSDPricePerGallonuSDPerMega-wattHour	Dec. 31, 2016uSDPricePerGallonuSDPerMega-wattHour
Maximum | Mid-Columbia annual average power prices
Disclosure of impairment loss recognised or reversed [line items]
Significant unobservable input, price per megawatt hour | uSDPerMega-wattHour	42	46
Maximum | On-highway diesel fuel on coal shipments
Disclosure of impairment loss recognised or reversed [line items]
Significant unobservable input, fuel price per gallon | uSDPricePerGallon	2.40	2.09
Maximum | Discount rates
Disclosure of impairment loss recognised or reversed [line items]
Significant unobservable input, assets	0.064	0.057
Minimum | Mid-Columbia annual average power prices
Disclosure of impairment loss recognised or reversed [line items]
Significant unobservable input, price per megawatt hour | uSDPerMega-wattHour	30	22
Minimum | On-highway diesel fuel on coal shipments
Disclosure of impairment loss recognised or reversed [line items]
Significant unobservable input, fuel price per gallon | uSDPricePerGallon	2.35	1.69
Minimum | Discount rates
Disclosure of impairment loss recognised or reversed [line items]
Significant unobservable input, assets	0.052	0.054

Finance Lease Receivables (Deta

Finance Lease Receivables (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Disclosure of recognised finance lease as assets by lessee [line items]
Undiscounted finance lease payments to be received	$ 332	$ 220
Undiscounted finance lease payments to be received, at present value	264	191
Less: unearned finance lease income	68	29
Less: unearned finance lease income, present value	0	0
Total finance lease receivables	264	191
Current finance lease receivables	36	15
Long-term portion of finance lease receivable	228	176
2021
Disclosure of recognised finance lease as assets by lessee [line items]
Undiscounted finance lease payments to be received	63	20
Undiscounted finance lease payments to be received, at present value	56	20
Second to fifth years inclusive
Disclosure of recognised finance lease as assets by lessee [line items]
Undiscounted finance lease payments to be received	169	80
Undiscounted finance lease payments to be received, at present value	126	74
More than five years
Disclosure of recognised finance lease as assets by lessee [line items]
Undiscounted finance lease payments to be received	100	120
Undiscounted finance lease payments to be received, at present value	$ 82	$ 97

Net Other Operating Income - Di

Net Other Operating Income - Disclosure of components of net other operating (income) losses (Details) - CAD ($) $ in Millions	Jul. 20, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Analysis of income and expenses [Line Items]
Coal supply agreement		$ 29	$ 0	$ 0
Alberta Off-Coal Agreement	$ (40)	(40)	(40)	(40)
Insurance recoveries		0	(10)	(7)
Other operating expenses		0	1	0
Net other operating income		$ (11)	$ (49)	$ (47)

Net Other Operating Income (Det

Net Other Operating Income (Details) - CAD ($) $ in Millions	Jul. 20, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of types of insurance contracts [line items]
Onerous contracts provision		$ 29
Alberta off-coal agreement, annual cash payments, gross	$ 40	40	$ 40	$ 40
Alberta off-coal agreement, annual cash payments, net	$ 37
Insurance recoveries		$ 0	$ 10	7
Alberta Thermal | Equipment Repair [Member]
Disclosure of types of insurance contracts [line items]
Insurance recoveries				1
Wyoming Wind [Member]
Disclosure of types of insurance contracts [line items]
Insurance recoveries				$ 6

Investments - Change in investm

Investments - Change in investments (Details) $ in Millions, $ in Millions	Nov. 30, 2020USD ($)	Nov. 25, 2020CAD ($)	Nov. 25, 2020USD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Change In Investments [Roll Forward]
Equity income				$ 1	$ 0	$ 0
Change in foreign exchange rates				17	(15)	$ (15)
Consolidated structured entities [member]
Change In Investments [Roll Forward]
Balance, Dec. 31, 2019				0
Contributions				102
Equity income				1
Change in foreign exchange rates				(3)
Balance, Dec. 31, 2020				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]
Balance, Dec. 31, 2019				0
Contributions				86
Equity income				1
Change in foreign exchange rates				(2)
Balance, Dec. 31, 2020				85	0
EMG International, LLC
Change In Investments [Roll Forward]
Balance, Dec. 31, 2019				0
Contributions				16
Equity income				0
Change in foreign exchange rates				(1)
Balance, Dec. 31, 2020				$ 15	$ 0

Investments - Results of operat

Investments - Results of operations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of subsidiaries [line items]
Revenues	$ 2,101	$ 2,347	$ 2,249
Equity income (Note 10)	1	$ 0	$ 0
Consolidated structured entities [member]
Disclosure of subsidiaries [line items]
Revenues	3
Operating expense	(2)
Equity income (Note 10)	$ 1

Investments - Summarized financ

Investments - Summarized financial information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of subsidiaries [line items]
Revenues	$ 2,101	$ 2,347	$ 2,249
Depreciation and amortization	654	590	574
Net interest expense	(238)	(179)	(250)
Net earnings (loss)	(253)	176	(90)
Other comprehensive income	(102)	(45)	4
Total comprehensive income (loss)	(355)	131	(86)
Current liabilities	(935)	(1,117)
Assets	9,747	9,508
Cash and cash equivalents	703	$ 411	$ 89	$ 314
SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Revenues	6
Depreciation and amortization	2
Net interest expense	1
Net earnings (loss)	3
Other comprehensive income	0
Total comprehensive income (loss)	3
Current assets	6
Long-term assets	382
Current liabilities	(65)
Long-term liabilities	(150)
Assets	173
Cash and cash equivalents	1
Current financial liabilities	(27)
Non-current financial liabilities	$ (147)

Investments - Summarized Intere

Investments - Summarized Interest (Details) - CAD ($) $ in Millions	Nov. 25, 2020	Apr. 12, 2019	Dec. 31, 2020	Dec. 31, 2019
Disclosure of subsidiaries [line items]
Assets			$ 9,747	$ 9,508
Non-controlling interests			1,084	1,101
Skookumchuck
Disclosure of subsidiaries [line items]
Proportion of ownership interest in joint operation	49.00%	49.00%
Skookumchuck | Entities Other Than Transalta Corporation
Disclosure of subsidiaries [line items]
Proportion of ownership interest in joint operation		51.00%
SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Assets			173
Non-controlling interests			(88)
Investments in associates accounted for using equity method			$ 85	$ 0

Investments - Future payments u

Investments - Future payments under contractual commitments (Details) $ in Millions	Dec. 31, 2020CAD ($)
Disclosure of subsidiaries [line items]
Long-term service agreements	$ 173
SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Long-term service agreements	33
2021
Disclosure of subsidiaries [line items]
Long-term service agreements	31
2021 | SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Long-term service agreements	1
2022
Disclosure of subsidiaries [line items]
Long-term service agreements	37
2022 | SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Long-term service agreements	1
2023
Disclosure of subsidiaries [line items]
Long-term service agreements	22
2023 | SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Long-term service agreements	1
2024
Disclosure of subsidiaries [line items]
Long-term service agreements	18
2024 | SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Long-term service agreements	1
2025
Disclosure of subsidiaries [line items]
Long-term service agreements	10
2025 | SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Long-term service agreements	1
2026
Disclosure of subsidiaries [line items]
Long-term service agreements	55
2026 | SP Skookumchuck Investment, LLC
Disclosure of subsidiaries [line items]
Long-term service agreements	$ 28

Net Interest Expense (Details)

Net Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Analysis of income and expenses [Line Items]
Interest on debt	$ 158	$ 161	$ 184
Interest on exchangeable securities	34	20	0
Interest income	(10)	(13)	(11)
Capitalized interest	(8)	(6)	(2)
Loss on redemption of bonds (Note 24)	0	0	24
Interest expense on lease liabilities	8	4	3
Credit facility fees, bank charges and other interest	18	15	13
Tax shield on tax equity financing	1	(35)	0
Interest on Line Loss Rule Proceeding	5	0	0
Other	2	10	15
Accretion of provisions	30	23	24
Net interest expense	238	179	250
Project level financing that is no longer practicable
Analysis of income and expenses [Line Items]
Net interest expense			(5)
IFRS 15
Analysis of income and expenses [Line Items]
Net interest expense	$ 0	$ (5)	$ (7)

Income Taxes - Rate Reconciliat

Income Taxes - Rate Reconciliations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Taxes [Abstract]
Earnings (loss) before income taxes	$ (303)	$ 193	$ (96)
Net earnings (loss) attributable to non-controlling interests not subject to tax	2	(26)	(19)
Adjusted earnings (loss) before income taxes	$ (301)	$ 167	$ (115)
Statutory Canadian federal and provincial income tax rate	24.50%	26.50%	26.80%
Expected income tax expense (recovery)	$ (74)	$ 44	$ (31)
Increase (decrease) in income taxes resulting from:
Differences in effective foreign tax rates	3	5	(3)
Deferred income tax expense related to temporary difference on investment in subsidiaries	9	0	0
Writedown (reversal of writedown) of deferred income tax assets	8	(9)	27
Statutory and other rate differences	(7)	(31)	0
Other	11	8	1
Income tax expense (recovery)	$ (50)	$ 17	$ (6)
Effective tax rate	17.00%	10.00%	5.00%

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - CAD ($) $ in Millions	Jan. 01, 2022	Jan. 01, 2021	Dec. 09, 2020	Jan. 01, 2020	Jul. 01, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disposal Groups, Including Discontinued Operations [Line Items]
Current income tax expense						$ 35	$ 35	$ 28
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences						(95)	22	(61)
Deferred income tax expense related to temporary difference on investment in subsidiary						9	0	0
Deferred income tax expense resulting from changes in tax rates or laws expense (recovery)						(7)	(31)	0
Writedown (reversal of writedown) of deferred income tax assets						8	(9)	27
Current income tax expense						35	35	28
Deferred income tax recovery						(85)	(18)	(34)
Income tax expense (recovery)						$ (50)	$ 17	$ (6)
Corporate tax rate						24.50%	26.50%	26.80%
ALBERTA
Disposal Groups, Including Discontinued Operations [Line Items]
Corporate tax rate		9.00%	8.00%	10.00%	11.00%	8.00%	11.00%
ALBERTA | Forecast
Disposal Groups, Including Discontinued Operations [Line Items]
Corporate tax rate	8.00%

Income Taxes - Aggregate Curren

Income Taxes - Aggregate Current and Deferred Income Tax Charged to Equity (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Taxes [Abstract]
Net impact related to cash flow hedges	$ (23)	$ 6	$ (12)
Net actuarial gains (losses)	(3)	(7)	5
Income tax expense reported in equity	$ (26)	$ (1)	$ (7)

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Income Tax Assets (Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Writedown of deferred income tax assets	$ (51)	$ (18)
Net deferred tax liabilities	(345)	(454)
Gross carrying amount | Net operating loss carryforwards(1)
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	469	494
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)	140	122
Gross carrying amount | Property, plant and equipment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	(717)	(828)
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)	(107)	(141)
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)	62	56
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)	22	42
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)	31	40
Gross carrying amount | Other deductible temporary differences
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	2	4
Accumulated impairment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	(98)	(211)
Writedown of deferred income tax assets	247	243
Net deferred tax liabilities	$ (345)	$ (454)

Income Taxes - Deferred Income

Income Taxes - Deferred Income Tax Liability Presentation (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Abstract]
Deferred income tax assets	$ 51	$ 18
Deferred tax liabilities	(396)	(472)
Net deferred tax liabilities	$ (345)	$ (454)

Income Taxes - Contingencies (D

Income Taxes - Contingencies (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Uncertain tax positions
Disclosure of contingent liabilities [line items]
Provision for uncertain tax positions	$ 0	$ 1

Non-Controlling Interests - Sub

Non-Controlling Interests - Subsidiaries and Operations with Non-Controlling Interests (Details) - MW

Oct. 19, 2018

Dec. 31, 2018

Jul. 30, 2018

Jun. 30, 2020

Mar. 31, 2020

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Nov. 29, 2018

Dec. 31, 2020

Jun. 21, 2018

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%

39.60%

Proportion of equity participation in subsidiary

60.90%

61.10%

60.20%

60.30%

60.40%

60.50%

60.60%

60.80%

61.00%

60.10%

64.00%

TransAlta Renewables Inc. | Kent Hills wind farm

Disclosure of subsidiaries [line items]

Proportion of ownership interests held by non-controlling interests

17.00%

Capacity of facility (in megawatts)

167

167

Kent Hills 3 Wind Project

Disclosure of subsidiaries [line items]

Increase in contractual power capacity (in megawatts)

167

Non-Controlling Interests - Sha

Non-Controlling Interests - Share of Ownership and Equity Participation in TransAlta Renewables (Details) - TransAlta Renewables Inc.	1 Months Ended		3 Months Ended						4 Months Ended	6 Months Ended	11 Months Ended
	Dec. 31, 2018	Jul. 30, 2018	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Nov. 29, 2018	Dec. 31, 2020	Jun. 21, 2018
Disclosure of subsidiaries [line items]
Equity participation percentage	60.90%	61.10%	60.20%	60.30%	60.40%	60.50%	60.60%	60.80%	61.00%	60.10%	64.00%
Proportion of equity participation in subsidiary	60.90%	61.10%	60.20%	60.30%	60.40%	60.50%	60.60%	60.80%	61.00%	60.10%	64.00%

Non-Controlling Interests - Ear

Non-Controlling Interests - Earnings of Subsidiaries with Non-Controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of subsidiaries [line items]
Revenues	$ 2,101	$ 2,347	$ 2,249
Net earnings (loss)	(253)	176	(90)
Total comprehensive income (loss)	(355)	131	(86)
Amounts attributable to the non-controlling interests:
Net earnings (loss)	34	94	108
Total comprehensive income (loss)	84	77	124
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Revenues	436	446	462
Net earnings (loss)	97	183	241
Total comprehensive income (loss)	223	138	281
Amounts attributable to the non-controlling interests:
Net earnings (loss)	40	73	94
Total comprehensive income (loss)	90	56	110
Distributions paid to Canadian Power Holdings Inc.	80	69	79
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Revenues	146	181	185
Net earnings (loss)	(13)	43	29
Total comprehensive income (loss)	(13)	43	29
Amounts attributable to the non-controlling interests:
Net earnings (loss)	(6)	21	14
Total comprehensive income (loss)	(6)	21	14
Distributions paid to Canadian Power Holdings Inc.	$ 17	$ 37	$ 86

Non-Controlling Interests - Fin

Non-Controlling Interests - Financial Position of Non-Controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of subsidiaries [line items]
Current assets	$ 1,902	$ 1,341
Current liabilities	(935)	(1,117)
Total equity	3,436	4,062	$ 4,134
Non-controlling interests	1,084	1,101
TransAlta Renewables Inc.
Disclosure of subsidiaries [line items]
Current assets	743	293
Long-term assets	2,913	3,409
Current liabilities	(364)	(152)
Long-term liabilities	(987)	(1,237)
Total equity	(2,305)	(2,313)
Non-controlling interests	$ (948)	$ (941)
Ownership and voting rights percentage	39.90%	39.60%
TransAlta Cogeneration, L.P.
Disclosure of subsidiaries [line items]
Current assets	$ 69	$ 41
Long-term assets	323	328
Current liabilities	(78)	(27)
Long-term liabilities	(37)	(19)
Total equity	(277)	(323)
Non-controlling interests	$ (136)	$ (160)
Ownership and voting rights percentage	49.99%	49.99%
TransAlta Cogeneration, L.P. | Coal facility
Disclosure of subsidiaries [line items]
Ownership and voting rights percentage	50.00%

Trade and Other Receivables (De

Trade and Other Receivables (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Trade accounts receivable	$ 488	$ 399
Current non-cash assets pledged as collateral for which transferee has right by contract or custom to sell or repledge collateral	49	42
(Note 8)	36	15
Income taxes receivable	10	6
Trade and other receivables	$ 583	$ 462

Financial Instruments - Carryin

Financial Instruments - Carrying amounts and classifications of financial assets and liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Disclosure of detailed information about financial instruments [line items]
Cash equivalents	$ 0	$ 0
Financial liabilities	3,361	3,212
Accounts payable and accrued liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	599	413
Accounts payable and accrued liabilities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	599	413
Dividends payable
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	59	37
Dividends payable | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	59	37
Credit facilities, long-term debt and lease liabilities(2)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,361	3,212
Credit facilities, long-term debt and lease liabilities(2) | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,361	3,212
Exchangeable securities (Note 25)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	730	326
Exchangeable securities (Note 25) | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	730	326
Within one year | Risk management liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	94	81
Within one year | Derivatives | Risk management liabilities | Trading securities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	84	80
Within one year | Derivatives | Risk management liabilities | Hedging Liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	10	1
Later than one year | Risk management liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	68	29
Later than one year | Derivatives | Risk management liabilities | Trading securities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	68	28
Later than one year | Derivatives | Risk management liabilities | Hedging Liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	0	1
Cash and cash equivalents
Disclosure of detailed information about financial instruments [line items]
Financial assets	703	411
Cash and cash equivalents | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	703	411
Restricted cash
Disclosure of detailed information about financial instruments [line items]
Financial assets	71	32
Restricted cash | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	71	32
Trade and other receivables
Disclosure of detailed information about financial instruments [line items]
Financial assets	583	462
Trade and other receivables | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	583	462
Long-term portion of finance lease receivable
Disclosure of detailed information about financial instruments [line items]
Financial assets	228	176
Long-term portion of finance lease receivable | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	228	176
Risk management assets | Within one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	171	166
Risk management assets | Later than one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	521	640
Risk management assets | Hedging Asset | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	102	71
Risk management assets | Hedging Asset | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	471	607
Risk management assets | Trading securities | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	69	95
Risk management assets | Trading securities | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	50	33
Other assets
Disclosure of detailed information about financial instruments [line items]
Financial assets	52	47
Other assets | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	$ 52	$ 47

Financial Instruments - Sensiti

Financial Instruments - Sensitivity ranges for the base fair values (Details)	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Long-term power sale – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	$ 598,000,000		$ 737,000,000
Coal transportation – US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	(16,000,000)
Structured products – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value			7,000,000
Full requirements – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	11,000,000		10,000,000
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
Long-term wind energy sale –Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	(29,000,000)
Long-term wind energy sale –Eastern US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value			(28,000,000)
Other
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	(4,000,000)		(6,000,000)
Fixed-price contracts | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh						$ 1
Increase (decrease) in derivative future power prices, reasonable possible		(1)
Forward contract | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh						$ 6
Increase (decrease) in derivative future power prices, reasonable possible		(6)
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	59,000,000		139,000,000
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	5,000,000
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]
Future power price ranges per MWh					$ 24
Rail rate escalation	$ 21
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]
Significant unobservable inputs, derivative asset	0.15				0.15
Increase (decrease) in significant unobservable inputs, derivative asset	0.80				0.80
Minimum | Structured products – 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			$ 2,000,000
Basis relationship, percent			91.00%	91.00%
Non-standard shape factors, percent			63.00%	63.00%
Sensitivity analysis in derivative, basis relationship, percent			4.00%	4.00%
Sensitivity analysis in derivative, non-standard shape factors, percent			4.00%	4.00%
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	$ 3,000,000		$ 3,000,000
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	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	$ 22,000,000
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			$ 20,000,000
Minimum | Other
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		8,000,000
Minimum | Fixed-price contracts | Long-term contracts | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh					$ 24	$ 20
Minimum | Forward contract | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh					35	$ 38
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	35,000,000		46,000,000
Increase (decrease) in derivative future power prices, reasonable possible		5		$ 9
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		$ 5
Maximum | Coal transportation – US | Long-term contracts | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh					$ 32
Rail rate escalation	$ 24
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]
Significant unobservable inputs, derivative asset	0.40				0.40
Increase (decrease) in significant unobservable inputs, derivative asset	1.20				1.20
Maximum | Structured products – 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			$ 2,000,000
Basis relationship, percent			112.00%	112.00%
Non-standard shape factors, percent			116.00%	116.00%
Sensitivity analysis in derivative, basis relationship, percent			6.00%	6.00%
Sensitivity analysis in derivative, non-standard shape factors, percent			10.00%	10.00%
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	$ 3,000,000		$ 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	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	$ 22,000,000
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			$ 20,000,000
Maximum | Other
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		$ 8,000,000
Maximum | Fixed-price contracts | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh					$ 11	$ 9
Maximum | Fixed-price contracts | Long-term contracts | US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh					32	28
Maximum | Forward contract | Long-term contracts | Level III
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Future power price ranges per MWh					$ 52	$ 60

Financial Instruments (Details)

Financial Instruments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)MW	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2020USD ($)MW	Dec. 31, 2019USD ($)	Dec. 31, 2018CAD ($)
Disclosure of detailed information about financial instruments [line items]
Risk management assets	$ 171		$ 166
Decrease in base fair value	14
Decrease in sensitivity values	$ 1
Fixed-price contracts | Minimum
Disclosure of detailed information about financial instruments [line items]
Long-term fixed price power sale contract, delivery volume | MW	300			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			380
Structured products – Eastern US | Minimum
Disclosure of detailed information about financial instruments [line items]
Basis relationship, percent			91.00%
Non-standard shape factors, percent			63.00%
Sensitivity analysis in derivative, basis relationship, percent			4.00%
Sensitivity analysis in derivative, non-standard shape factors, percent			4.00%
Structured products – Eastern US | Maximum
Disclosure of detailed information about financial instruments [line items]
Basis relationship, percent			112.00%
Non-standard shape factors, percent			116.00%
Sensitivity analysis in derivative, basis relationship, percent			6.00%
Sensitivity analysis in derivative, non-standard shape factors, percent			10.00%
Long-term contracts | US | Fixed-price contracts | Minimum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh				$ 24	$ 20
Long-term contracts | US | Fixed-price contracts | Maximum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh				32	28
Level III | Long-term contracts | Fixed-price contracts
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh					1
Increase (decrease) in derivative forward power prices, reasonable possible		$ (1)
Level III | Long-term contracts | Fixed-price contracts | Maximum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh				11	9
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)
Level III | Long-term contracts | Forward contract | Minimum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh				35	38
Level III | Long-term contracts | Forward contract | Maximum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh				$ 52	$ 60
Recurring fair value measurement | Level I
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	$ (13)		$ (3)
Recurring fair value measurement | Level III
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	$ 582		$ 686			$ 695

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of risk management strategy related to hedge accounting [line items]
Change in foreign exchange rates	$ 17	$ (15)	$ (15)
Gains (losses) recognized in other comprehensive income	(141)	(53)	(57)
Gains (losses) on cash flow hedges, before tax	28	77	(9)
Other
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic		4
Commodity risk management
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic		692
Recurring fair value measurement | Level I
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	(13)	(3)
Recurring fair value measurement | Level II
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	(27)	9
Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	582	686	695
Market price changes	(81)	(76)
Change in foreign exchange rates	(15)	(32)
Transfers into Level 3 of fair value hierarchy, assets	0	0
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	(12)	4
Non-recurring fair value measurement [member] | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Gains (losses) recognized in other comprehensive income	(34)	46
Gains (losses) on cash flow hedges, before tax	82	78
Unrealized gains included in earnings before income taxes relating to met assets held	1	2
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	573	678	689
Market price changes	(71)	(57)
Change in foreign exchange rates	(16)	(31)
Transfers into Level 3 of fair value hierarchy, assets	0	0
Fair value hedges [member] | Non-recurring fair value measurement [member] | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Gains (losses) recognized in other comprehensive income	(34)	46
Gains (losses) on cash flow hedges, before tax	71	57
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	9	8	$ 6
Market price changes	(10)	(19)
Change in foreign exchange rates	1	(1)
Transfers into Level 3 of fair value hierarchy, assets	0	0
Non-Hedges | Non-recurring fair value measurement [member] | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Gains (losses) recognized in other comprehensive income	0	0
Gains (losses) on cash flow hedges, before tax	11	21
Unrealized gains included in earnings before income taxes relating to met assets held	1	2
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	(15)	85
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	(18)	77
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	3	8
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	7	14
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	$ 7	$ 14

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, 2020	Dec. 31, 2019
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	$ 3,361	$ 3,212
Financial liabilities	3,361	3,212
Long-term debt
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,227	3,070
Financial liabilities	3,227	3,070
Exchangeable securities (Note 25)
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	730	326
Financial liabilities	730	326
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	3,480	3,157
Financial liabilities	3,480	3,157
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	769	342
Financial liabilities	769	342
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
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
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	3,480	3,157
Financial liabilities	3,480	3,157
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	769	342
Financial liabilities	769	342
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
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 liabilities	$ 0	$ 0

Financial Instruments - Incepti

Financial Instruments - Inception Gains And Losses (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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 at beginning of year	$ 9	$ 49	$ 105
New inception gains (losses)(1)	(13)	3	(14)
Change in foreign exchange rates	0	0	5
Amortization recorded in net earnings during the year	(29)	(43)	(47)
Unamortized net gain (loss) at end of year(2)	$ (33)	$ 9	$ 49

Risk Management Activities - Ad

Risk Management Activities - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
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	$ 49,000,000	$ 42,000,000
Financial assets pledged as collateral for liabilities or contingent liabilities	0	3,000,000
Derivative, contingent feature, additional collateral requirement	85,000,000	$ 51,000,000
Asset-backed debt instruments held	631,000,000
Debt instruments held	$ 1,000,000,000
Borrowings subject to floating interest rates	7.00%	11.00%		7.00%	11.00%
Sensitivity analysis used by management for the foreign exchange differences from functional currency	$ 0.03	$ 0.03	$ 0.04
Borrowings	$ 3,361,000,000	3,212,000,000
Bond, interest rate	5.75%
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%
Change in foreign exchange rates	$ 0	0	5,000,000
Maximum exposure to credit risk	22,000,000	5,000,000
Other comprehensive income that will be reclassified to profit or loss, net of tax	(90,000,000)	(19,000,000)	(11,000,000)
Gains (losses) on change in fair value of derivatives	43,000,000	33,000,000	(29,000,000)
Gains on change in fair value of derivatives	11,000,000	24,000,000	3,000,000
Unrealised loss on change in fair value of derivatives	2,000,000
Unrealised gains on change in fair value of derivatives		6,000,000	4,000,000
Net realized gains on change in fair value of derivatives	13,000,000	18,000,000
Net realized losses on change in fair value of derivatives			1,000,000
Unrealized pre-tax gains (losses)	1,000,000	1,000,000	4,000,000
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	72,000,000
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
Bond, forward yield	1.20%
Bond Lock Agreement [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount	$ 75,000,000
Commodity Price Risk - Proprietary Trading [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	1,000,000	1,000,000	2,000,000
Commodity Price Risk - Generation [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	12,000,000	25,000,000	18,000,000
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	15,000,000	8,000,000	$ 13,000,000
Interest rate risk | Interest Rate Exposure [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Borrowings	$ 150,000,000
Interest rate risk | Interest rate swap
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount				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%
Letter of credit
Disclosure of nature and extent of risks arising from financial instruments [line items]
Collateral posted on derivative liabilities	$ 163,000,000	$ 112,000,000

Risk Management Activities - Ne

Risk Management Activities - Net Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		$ 692
Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		4
Current | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	$ 90	85
Current | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	(13)	0
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	452	607
Long-term | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	1	4
Financial Assets
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	530	696
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	542
Financial Assets | Other
Disclosure of nature and extent of risks arising from financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	(12)
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		676
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		0
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	101	70
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	(9)	0
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	471	606
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	563	676
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	572
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	(9)
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	(33)
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		16
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	(19)	1
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	(11)
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	(30)
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		4
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		0
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		4
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		15
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	(4)
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	1
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		$ 20
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	$ (3)

Risk Management Activities - _2

Risk Management Activities - Netting Arrangements (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current
Disclosure of offsetting of financial assets [line items]
Gross financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	$ (132)	$ (191)
Gross financial assets set off against financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	69	140
Net financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	(63)	(51)
Long-term
Disclosure of offsetting of financial assets [line items]
Gross financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	(104)	(100)
Gross financial assets set off against financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	10	42
Net financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	(94)	(58)
Current
Disclosure of offsetting of financial assets [line items]
Gross financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	120	316
Gross financial liabilities set off against financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	(69)	(140)
Net financial assets subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	51	176
Long-term
Disclosure of offsetting of financial assets [line items]
Gross financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	69	631
Gross financial liabilities set off against financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	(10)	(42)
Net financial assets subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	$ 59	$ 589

Risk Management Activities - Ou

Risk Management Activities - Outstanding commodity derivative instruments designated as hedging instruments (Details) - Electricity - Cash flow hedges - Commodity risk management - MWh	Dec. 31, 2020	Dec. 31, 2019
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	95,000	222,000
Notional amount purchased	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, 2020MWhJt	Dec. 31, 2019MWhJt
Electricity
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	12,944,000	16,097,000
Notional amount purchased	8,258,000	7,204,000
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	23,035,000	38,062,000
Notional amount purchased | J	177,448,000	55,023,000
Transmission
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	0	0
Notional amount purchased	1,578,000	1,818,000
Emissions
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	1,831,000	184,000
Notional amount purchased	2,112,000	138,000
Notional amount sold | t	2,160,000	2,436,000
Notional amount purchased | t	2,365,000	2,446,000

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	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)
Disclosure of information about terms and conditions of hedging instruments and how they affect future cash flows [line items]
Notional amount sold	$ 71		$ 124
Derivative, notional amount purchased		$ 54		$ 95
Financial liabilities, at fair value	$ (2)
Financial assets, at fair value			$ 0

Risk Management Activities - No

Risk Management Activities - Non-Hedges (Details) € in Millions, $ in Millions, $ in Millions, $ in Millions	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2020AUD ($)	Dec. 31, 2020EUR (€)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019AUD ($)
Disclosure of detailed information about hedges [line items]
Hedging instrument, assets	$ 2				$ 7
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 receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2020-2023, 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, 2020-2023, Contract Two
Disclosure of detailed information about hedges [line items]
Hedging instrument, liabilities					(4)
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	2				6
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
Australia, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2020-2023, Contract One
Disclosure of detailed information about hedges [line items]
Notional amount sold							$ 286
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 receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2020-2023, Contract One
Disclosure of detailed information about hedges [line items]
Derivative, notional amount purchased					266
Canada, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2020-2023, Contract Two
Disclosure of detailed information about hedges [line items]
Derivative, notional amount purchased					139
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
Derivative, notional amount purchased		$ 150				$ 150
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 receipts/expenditures | Discontinued Hedge Positions | Currency risk | Maturity, 2020-2023, Contract Two
Disclosure of detailed information about hedges [line items]
Notional amount sold						$ 108
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of credit risk exposure [line items]
Sensitivity analysis, Net earnings increase (decrease)	$ (12)	$ (24)	$ (20)
Sensitivity analysis, OCI gain	1	2	0
U.S. Dollars
Disclosure of credit risk exposure [line items]
Sensitivity analysis, Net earnings increase (decrease)	(8)	(18)	(13)
Sensitivity analysis, OCI gain	1	2	0
Australia, Dollars
Disclosure of credit risk exposure [line items]
Sensitivity analysis, Net earnings increase (decrease)	(4)	(6)	(7)
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, 2020	Dec. 31, 2019
Disclosure of credit risk exposure [line items]
Maximum exposure to credit risk	$ 22	$ 5
Credit risk
Disclosure of credit risk exposure [line items]
Maximum exposure to credit risk	1,555
Credit risk | Trade and other receivables
Disclosure of credit risk exposure [line items]
Maximum exposure to credit risk	$ 583
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 [Member] | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	92.00%
Trade and other receivables | Non-Investment Grade [Member] | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	8.00%
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	$ 228
Long-term portion of finance lease receivable | Investment Grade [Member] | 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 [Member] | 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	$ 692
Risk management assets | Investment Grade [Member] | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	93.00%
Risk management assets | Non-Investment Grade [Member] | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	7.00%
Amortized cost | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Maximum exposure to credit risk	$ 52
Amortized cost | Investment Grade [Member] | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	0.00%
Amortized cost | Non-Investment Grade [Member] | Credit risk
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%

Risk Management Activities - _3

Risk Management Activities - Maturity Analysis of Financial Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	$ 599	$ 413
Borrowings	3,361	3,212
Exchangeable securities	730	326
Dividends payable	59	$ 37
Liabilities	6,051
Within one year
Disclosure of maturity analysis for derivative financial liabilities [line items]
Liabilities	885
Lease commitments for short-term leases for which recognition exemption has been used	13
2022
Disclosure of maturity analysis for derivative financial liabilities [line items]
Liabilities	750
2023
Disclosure of maturity analysis for derivative financial liabilities [line items]
Liabilities	331
2024
Disclosure of maturity analysis for derivative financial liabilities [line items]
Liabilities	162
2025
Disclosure of maturity analysis for derivative financial liabilities [line items]
Liabilities	901
More than five years
Disclosure of maturity analysis for derivative financial liabilities [line items]
Liabilities	3,022
Gross carrying amount
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	599
Borrowings	3,264
Exchangeable securities	750
Derivative financial assets	(12)
Lease liabilities	134
Interest expense on borrowings	1,565
Dividends payable	59
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	210
Gross carrying amount | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	(542)
Gross carrying amount | Within one year
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	599
Borrowings	96
Exchangeable securities	0
Derivative financial assets	(14)
Lease liabilities	(5)
Interest expense on borrowings	161
Dividends payable	59
Gross carrying amount | Within one year | 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 | Within one year | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	(92)
Gross carrying amount | 2022
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	626
Exchangeable securities	0
Derivative financial assets	0
Lease liabilities	6
Interest expense on borrowings	153
Dividends payable	0
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	52
Gross carrying amount | 2022 | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	(87)
Gross carrying amount | 2023
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	277
Exchangeable securities	0
Derivative financial assets	(1)
Lease liabilities	5
Interest expense on borrowings	126
Dividends payable	0
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	(131)
Gross carrying amount | 2024
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	119
Exchangeable securities	0
Derivative financial liabilities	(2)
Lease liabilities	5
Interest expense on borrowings	119
Dividends payable	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	52
Gross carrying amount | 2024 | Commodity risk management
Disclosure of maturity analysis for derivative financial liabilities [line items]
Derivative financial liabilities	(131)
Gross carrying amount | 2025
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	136
Exchangeable securities	750
Derivative financial assets	0
Lease liabilities	5
Interest expense on borrowings	113
Dividends payable	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	(103)
Gross carrying amount | More than five years
Disclosure of maturity analysis for derivative financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	2,010
Exchangeable securities	0
Derivative financial liabilities	(1)
Lease liabilities	118
Interest expense on borrowings	893
Dividends payable	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 assets	$ (2)

Risk Management Activities - _4

Risk Management Activities - Maturity of Non-Hedges (Details) - 12 months ended Dec. 31, 2020 - Non-Hedges - Commodity risk management	CAD ($)$ / $	cADPerMegawattHour
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Within one year
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 54,000,000
Average foreign exchange rate | $ / $	0.7648
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | 2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 0
Average foreign exchange rate | $ / $	0
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | 2023
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 0
Average foreign exchange rate | $ / $	0
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | 2024
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 0
Average foreign exchange rate | $ / $	0
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | 2025
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 0
Average foreign exchange rate | $ / $	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
Average foreign exchange rate | $ / $	0
Electricity | Within one year
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 3,424,000
Average power prices | cADPerMegawattHour		cADPerMegawattHour 69.51
Electricity | 2022
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	3,329,000
Average power prices | cADPerMegawattHour		71.91
Electricity | 2023
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	3,329,000
Average power prices | cADPerMegawattHour		73.72
Electricity | 2024
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	3,338,000
Average power prices | cADPerMegawattHour		75.56
Electricity | 2025
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	2,628,000
Average power prices | cADPerMegawattHour		77.44
Electricity | More than five years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Notional amount	$ 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, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2020USD ($)MWh	Dec. 31, 2020CAD ($)MWh	Dec. 31, 2019USD ($)MWh	Dec. 31, 2019CAD ($)MWh
Disclosure of detailed information about hedging instruments [line items]
Hedging instrument, assets				$ 2		$ 7
Physical power sales | Cash flow hedges | Commodity risk management
Disclosure of detailed information about hedging instruments [line items]
Notional amount purchased | MWh			16	16	19	19
Hedging instrument, assets				$ 573		$ 678
Gain (loss) on hedge ineffectiveness	$ (33)	$ 47
Interest rate swap | Cash flow hedges | Interest rate risk | U.S. Dollars
Disclosure of detailed information about hedging instruments [line items]
Notional amount			$ 150
Gain (loss) on hedge ineffectiveness	3
Hedging instrument, liabilities				(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				$ 472		$ 483
Gain (loss) on hedge ineffectiveness	$ 11	$ 21
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) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about hedging instruments [line items]
Accumulated other comprehensive income	$ 302	$ 454
Reserve of exchange differences on translation
Disclosure of detailed information about hedging instruments [line items]
Accumulated other comprehensive income	(21)	(21)	$ 17
Physical power sales | Cash flow hedges | Commodity risk management
Disclosure of detailed information about hedging instruments [line items]
Gain (loss) on hedge ineffectiveness	(33)	47
Reserve of cash flow hedges	417	527
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	7	0
Reserve of cash flow hedges	19	0
Foreign-denominated debt | Net Investment Hedge | Currency risk
Disclosure of detailed information about hedging instruments [line items]
Gain (loss) on hedge ineffectiveness	$ 11	$ 21

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) on cash flow hedges, before tax	$ 28	$ 77	$ (9)
Gains (losses) recognized in other comprehensive income	(141)	(53)	(57)
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	41	77	(9)
Commodity contracts | Revenue
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) recognized in other comprehensive income	(137)	(59)	(67)
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	(1)
Foreign exchange forwards on project hedges | Property, plant and equipment
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) recognized in other comprehensive income	0
Gain (loss) on hedge ineffectiveness recognised in profit or loss	0
Foreign exchange forwards on US debt
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) on cash flow hedges, before tax			0
Foreign exchange forwards on US debt | Foreign exchange (gain) loss
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) recognized in other comprehensive income			3
Gain (loss) on hedge ineffectiveness recognised in profit or loss			0
Forward starting interest rate swaps
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) on cash flow hedges, before tax	(12)	0	0
Forward starting interest rate swaps | Interest expense
Disclosure of detailed information about hedging instruments [line items]
Gains (losses) recognized in other comprehensive income	(4)	6	7
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of inventories [Abstract]
Parts and materials	$ 107	$ 108
Coal	83	130
Deferred stripping costs	8	6
Natural gas	2	3
Purchased emission credits	38	4
Inventories	$ 238	$ 251	$ 242

Inventory Change in Inventory (

Inventory Change in Inventory (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Disclosure of inventories [Abstract]
Inventories at the beginning of the period	$ 251	$ 242
Net addition		12
Change in foreign exchange rates	(2)	(3)
Writedowns	37
Net addition	26
Inventories at the end of the period	$ 238	$ 251

Inventory (Details)

Inventory (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)emissionCredit	Dec. 31, 2019CAD ($)emissionCredit
Disclosure of inventories [Abstract]
Inventory write-down | $	$ 37
Additions to emission credits | emissionCredit	1,434,761	388,155
Purchased emission credits | $	$ 38	$ 4
Inventory, emission credits | emissionCredit	502,653	411,115

Property, Plant, and Equipmen_2

Property, Plant, and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about property, plant and equipment [line items]
Gains (losses) on disposals of property, plant and equipment		$ (17)
Property, plant and equipment expenditures	$ 486	417	$ 277
Interest costs capitalised	$ 8	$ 6	$ 2
Capitalisation rate of borrowing costs eligible for capitalisation	6.00%	5.90%
Windrise Wind Facility
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures	$ 156
WindCharger Battery Storage Project
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures	6
Kaybob Cogeneration Facility
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures	31
Centralia Coal Mine
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures	17
Pioneer Pipeline
Disclosure of detailed information about property, plant and equipment [line items]
Other cash and cash equivalents		$ 15
Genesee Unit 3
Disclosure of detailed information about property, plant and equipment [line items]
Additions		5
Keephills 3
Disclosure of detailed information about property, plant and equipment [line items]
Additions		308
Coal generation | Keephills 3
Disclosure of detailed information about property, plant and equipment [line items]
Additions		300
Mining property and equipment
Disclosure of detailed information about property, plant and equipment [line items]
Gains (losses) on disposals of property, plant and equipment		(18)
Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions	486	522
Property, plant and equipment expenditures		417
Gross carrying amount | US Wind Projects
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures		169
Gross carrying amount | Pioneer Pipeline
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures		100
Gross carrying amount | Coal generation
Disclosure of detailed information about property, plant and equipment [line items]
Additions	0	0
Gross carrying amount | Mining property and equipment
Disclosure of detailed information about property, plant and equipment [line items]
Additions	0	0
Gross carrying amount | Gas generation
Disclosure of detailed information about property, plant and equipment [line items]
Additions	0	$ 0
Property, plant and equipment expenditures	$ 93

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	$ 6,207	$ 6,164
(Impairment) reversals (Note 7)	0	(18)	$ (23)
Property, plant and equipment, end of the period	5,822	6,207	6,164
Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	13,395	13,202
Additions	486	522
Acquisitions	1	439
Disposals	(5)	(704)
(Impairment) reversals (Note 7)	(81)	431
Retirement of assets	(58)	(201)
Change in foreign exchange rates	(3)	(134)
Transfers	(431)	(29)
Property, plant and equipment, end of the period	13,398	13,395	13,202
Gross carrying amount | IFRS 16
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		108
Property, plant and equipment, end of the period			108
Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(7,188)	(7,038)
Disposals	2	439
(Impairment) reversals (Note 7)		(297)
Retirement of assets	51	190
Change in foreign exchange rates	(21)	(76)
Transfers	(255)	(26)
Depreciation	(717)	(630)
Property, plant and equipment, end of the period	(7,576)	(7,188)	(7,038)
Accumulated depreciation | IFRS 16
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(46)
Property, plant and equipment, end of the period			(46)
Land
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	91	94
Property, plant and equipment, end of the period	96	91	94
Land | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	91	94
Additions	0	0
Acquisitions	0	0
Disposals	(2)	(2)
(Impairment) reversals (Note 7)	(9)	0
Retirement of assets	0	0
Change in foreign exchange rates	(1)	(1)
Transfers	17	0
Property, plant and equipment, end of the period	96	91	94
Land | Gross carrying amount | IFRS 16
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			0
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	0	0
(Impairment) reversals (Note 7)		0
Retirement of assets	0	0
Change in foreign exchange rates	0	0
Transfers	0	0
Depreciation	0	0
Property, plant and equipment, end of the period	0	0	0
Land | Accumulated depreciation | IFRS 16
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			0
Coal generation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	2,120	2,172
Property, plant and equipment, end of the period	1,856	2,120	2,172
Coal generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	6,116	5,937
Additions	0	0
Acquisitions	0	300
Disposals	(1)	(389)
(Impairment) reversals (Note 7)	(69)	448
Retirement of assets	(35)	(158)
Change in foreign exchange rates	(37)	(63)
Transfers	142	103
Property, plant and equipment, end of the period	6,137	6,116	5,937
Coal generation | Gross carrying amount | IFRS 16
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			0
Coal generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(3,996)	(3,765)
Disposals	1	170
(Impairment) reversals (Note 7)		(297)
Retirement of assets	31	158
Change in foreign exchange rates	(35)	(52)
Transfers	0	10
Depreciation	(352)	(304)
Property, plant and equipment, end of the period	(4,281)	(3,996)	(3,765)
Coal generation | Accumulated depreciation | IFRS 16
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			0
Gas generation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	771	836
Property, plant and equipment, end of the period	659	771	836
Gas generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	1,671	1,964
Additions	0	0
Acquisitions	1	0
Disposals	0	(260)
(Impairment) reversals (Note 7)	0	0
Retirement of assets	(12)	(26)
Change in foreign exchange rates	45	(40)
Transfers	(263)	22
Property, plant and equipment, end of the period	1,431	1,671	1,964
Gas generation | Gross carrying amount | IFRS 16
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			0
Gas generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(900)	(1,128)
Disposals	0	255
(Impairment) reversals (Note 7)		0
Retirement of assets	10	23
Change in foreign exchange rates	18	(16)
Transfers	(212)	(11)
Depreciation	(76)	(77)
Property, plant and equipment, end of the period	(772)	(900)	(1,128)
Gas generation | Accumulated depreciation | IFRS 16
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			0
Renewable generation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	2,290	2,125
Property, plant and equipment, end of the period	2,176	2,290	2,125
Renewable generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	3,574	3,286
Additions	0
Acquisitions	0	0
Disposals	0	0
(Impairment) reversals (Note 7)	(2)	(2)
Retirement of assets	(7)	(7)
Change in foreign exchange rates	(14)	(17)
Transfers	33	319
Property, plant and equipment, end of the period	3,592	3,574	3,286
Renewable generation | Gross carrying amount | IFRS 16
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		7
Property, plant and equipment, end of the period			7
Renewable generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(1,284)	(1,161)
Disposals	0	0
(Impairment) reversals (Note 7)		0
Retirement of assets	6	3
Change in foreign exchange rates	(4)	(4)
Transfers	0	(3)
Depreciation	(142)	(136)
Property, plant and equipment, end of the period	(1,416)	(1,284)	(1,161)
Renewable generation | Accumulated depreciation | IFRS 16
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(3)
Property, plant and equipment, end of the period			(3)
Mining property and equipment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	386	508
Property, plant and equipment, end of the period	330	386	508
Mining property and equipment | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	1,226	1,338
Additions	0	0
Acquisitions	0	0
Disposals	0	(34)
(Impairment) reversals (Note 7)	0	(15)
Retirement of assets	(3)	(10)
Change in foreign exchange rates	(2)	(3)
Transfers	(29)	25
Property, plant and equipment, end of the period	1,268	1,226	1,338
Mining property and equipment | Gross carrying amount | IFRS 16
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		101
Property, plant and equipment, end of the period			101
Mining property and equipment | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(840)	(830)
Disposals	0	14
(Impairment) reversals (Note 7)		0
Retirement of assets	4	6
Change in foreign exchange rates	(2)	(2)
Transfers	(29)	(22)
Depreciation	(133)	(97)
Property, plant and equipment, end of the period	(938)	(840)	(830)
Mining property and equipment | Accumulated depreciation | IFRS 16
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period		(43)
Property, plant and equipment, end of the period			(43)
Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	228	200
Property, plant and equipment, end of the period	495	228	200
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	228	200
Additions	478	407
Acquisitions	0	139
Disposals	0	0
(Impairment) reversals (Note 7)	0	0
Retirement of assets	0	0
Change in foreign exchange rates	0	(4)
Transfers	(211)	(514)
Property, plant and equipment, end of the period	495	228	200
Assets under construction | Gross carrying amount | IFRS 16
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			0
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	0	0
(Impairment) reversals (Note 7)		0
Retirement of assets	0	0
Change in foreign exchange rates	0	0
Transfers	0	0
Depreciation	0	0
Property, plant and equipment, end of the period	0	0	0
Assets under construction | Accumulated depreciation | IFRS 16
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			0
Capital spares and other
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	321	229
Property, plant and equipment, end of the period	210	321	229
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	489	383
Additions	8	115
Acquisitions	0	0
Disposals	(2)	(19)
(Impairment) reversals (Note 7)	(1)	0
Retirement of assets	(1)	0
Change in foreign exchange rates	6	(6)
Transfers	(120)	16
Property, plant and equipment, end of the period	379	489	383
Capital spares and other | Gross carrying amount | IFRS 16
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			0
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	(168)	(154)
Disposals	1	0
(Impairment) reversals (Note 7)		0
Retirement of assets	0	0
Change in foreign exchange rates	2	(2)
Transfers	(14)	0
Depreciation	(14)	(16)
Property, plant and equipment, end of the period	(169)	(168)	(154)
Capital spares and other | Accumulated depreciation | IFRS 16
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			$ 0
Decommissioning and restoration | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Revisions and additions to decommissioning and restoration costs (Note 23)	94	(23)
Decommissioning and restoration | Land | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Revisions and additions to decommissioning and restoration costs (Note 23)	0	0
Decommissioning and restoration | Coal generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Revisions and additions to decommissioning and restoration costs (Note 23)	21	(62)
Decommissioning and restoration | Gas generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Revisions and additions to decommissioning and restoration costs (Note 23)	(11)	11
Decommissioning and restoration | Renewable generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Revisions and additions to decommissioning and restoration costs (Note 23)	8	2
Decommissioning and restoration | Mining property and equipment | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Revisions and additions to decommissioning and restoration costs (Note 23)	76	26
Decommissioning and restoration | Assets under construction | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Revisions and additions to decommissioning and restoration costs (Note 23)	0	0
Decommissioning and restoration | Capital spares and other | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Revisions and additions to decommissioning and restoration costs (Note 23)	$ 0	$ 0

Right of Use Assets - Reconcili

Right of Use Assets - Reconciliation of changes of the right of use assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	$ 146	$ 52
Transfers to right-of-use assets		(1)
Additions to right-of-use assets	16	81
Depreciation, right-of-use assets	(21)	(18)
Changes in foreign exchange rates		(1)
Right-of-use assets, ending balance	141	146	$ 52
Land
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	58	29
Transfers to right-of-use assets		0
Additions to right-of-use assets	3	32
Depreciation, right-of-use assets	(3)	(1)
Changes in foreign exchange rates		(1)
Right-of-use assets, ending balance	58	58	29
Buildings
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	16	22
Transfers to right-of-use assets		0
Additions to right-of-use assets	13	2
Depreciation, right-of-use assets	(5)	(4)
Changes in foreign exchange rates		0
Right-of-use assets, ending balance	24	16	22
Vehicles
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	2	1
Transfers to right-of-use assets		0
Additions to right-of-use assets	0	0
Depreciation, right-of-use assets	(1)	(2)
Changes in foreign exchange rates		0
Right-of-use assets, ending balance	1	2	1
Equipment
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	25	0
Transfers to right-of-use assets		(1)
Additions to right-of-use assets	0	2
Depreciation, right-of-use assets	(9)	(11)
Changes in foreign exchange rates		0
Right-of-use assets, ending balance	16	25	0
Pipeline
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance	45	0
Transfers to right-of-use assets		0
Additions to right-of-use assets	0	45
Depreciation, right-of-use assets	(3)	0
Changes in foreign exchange rates		0
Right-of-use assets, ending balance	$ 42	45	0
IFRS 16
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		85
Adjustments on recognition			(5)
Transfers to right-of-use assets			(38)
Right-of-use assets, ending balance			85
IFRS 16 | Land
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		28
Adjustments on recognition			(1)
Transfers to right-of-use assets			0
Right-of-use assets, ending balance			28
IFRS 16 | Buildings
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		18
Adjustments on recognition			(4)
Transfers to right-of-use assets			0
Right-of-use assets, ending balance			18
IFRS 16 | Vehicles
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		4
Adjustments on recognition			0
Transfers to right-of-use assets			(3)
Right-of-use assets, ending balance			4
IFRS 16 | Equipment
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		35
Adjustments on recognition			0
Transfers to right-of-use assets			(35)
Right-of-use assets, ending balance			35
IFRS 16 | Pipeline
Right-Of-Use Assets [Roll Forward]
Right-of-use assets, beginning balance		$ 0
Adjustments on recognition			0
Transfers to right-of-use assets			0
Right-of-use assets, ending balance			$ 0

Right of Use Assets - Narrative

Right of Use Assets - Narrative (Details) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2019contractRenewal	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of quantitative information about right-of-use assets [line items]
Contract for transporting natural gas, initial term	15 years
Number of contract renewals | contractRenewal	8
Renewal period	24 months
Right-of-use assets		$ 141	$ 146	$ 52
Payments of lease liabilities, classified as financing activities		33	25
Interest expense on lease liabilities		8	4	3
Repayments of principal on lease liabilities		25	21
Expense relating to short-term leases for which recognition exemption has been used		0	2
Expense relating to leases of low-value assets for which recognition exemption has been used		0	1
Expense relating to variable lease payments not included in measurement of lease liabilities		$ 7	6
Pioneer Pipeline | Alberta Thermal
Disclosure of quantitative information about right-of-use assets [line items]
Proportion of ownership interest in joint operation		50.00%
IFRS 16
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets				$ 85
IFRS 16 | Wind Farms
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets			31
Lease liabilities			$ 31

Intangible Assets (Details)

Intangible Assets (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Impairment loss	$ 70
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		$ 318	$ 373
Ending balance		313	318	$ 373
Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		788	807
Additions		14	14
Acquisition		37	16
Disposals (Note 4(R))			(38)
Change in foreign exchange rates		(2)	(6)
Transfers		(3)	0
Disposals		(1)
Ending balance		833	788	807
Gross carrying amount | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			5
Ending balance				5
Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		(470)	(434)
Disposals (Note 4(R))			10
Change in foreign exchange rates			(1)
Transfers		0	0
Disposals		1
Amortization		51	50
Ending balance		(520)	(470)	(434)
Accumulated amortization | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			(3)
Ending balance				(3)
Coal rights
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		32	68
Ending balance		24	32	68
Coal rights | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		149	185
Additions		0	0
Acquisition		0	0
Disposals (Note 4(R))			(37)
Change in foreign exchange rates		0	0
Transfers		0	1
Disposals		0
Ending balance		149	149	185
Coal rights | Gross carrying amount | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			0
Ending balance				0
Coal rights | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		(117)	(117)
Disposals (Note 4(R))			9
Change in foreign exchange rates			0
Transfers		0	1
Disposals		0
Amortization		8	8
Ending balance		(125)	(117)	(117)
Coal rights | Accumulated amortization | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			0
Ending balance				0
Software and other
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		132	118
Ending balance		140	132	118
Software and other | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		378	339
Additions		0	0
Acquisition		0	1
Disposals (Note 4(R))			(1)
Change in foreign exchange rates		0	(4)
Transfers		35	48
Disposals		(1)
Ending balance		412	378	339
Software and other | Gross carrying amount | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			5
Ending balance				5
Software and other | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		(246)	(221)
Disposals (Note 4(R))			1
Change in foreign exchange rates			(1)
Transfers		(1)	(1)
Disposals		1
Amortization		28	31
Ending balance		(272)	(246)	(221)
Software and other | Accumulated amortization | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			(3)
Ending balance				(3)
Power sale contracts
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		143	141
Ending balance		146	143	141
Power sale contracts | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		250	237
Additions		0	0
Acquisition		37	0
Disposals (Note 4(R))			0
Change in foreign exchange rates		(2)	(1)
Transfers		(16)	14
Disposals		0
Ending balance		269	250	237
Power sale contracts | Gross carrying amount | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			0
Ending balance				0
Power sale contracts | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		(107)	(96)
Disposals (Note 4(R))			0
Change in foreign exchange rates			0
Transfers		1	0
Disposals		0
Amortization		15	11
Ending balance		(123)	(107)	(96)
Power sale contracts | Accumulated amortization | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			0
Ending balance				0
Intangibles under development
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		11	46
Ending balance		3	11	46
Intangibles under development | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		11	46
Additions		14	14
Acquisition		0	15
Disposals (Note 4(R))			0
Change in foreign exchange rates		0	(1)
Transfers		22	(63)
Disposals		0
Ending balance		3	11	46
Intangibles under development | Gross carrying amount | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			0
Ending balance				0
Intangibles under development | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		0	0
Disposals (Note 4(R))			0
Change in foreign exchange rates			0
Transfers		0	0
Disposals		0
Amortization		0	0
Ending balance		$ 0	0	0
Intangibles under development | Accumulated amortization | IFRS 16
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance			$ 0
Ending balance				0
Lakeswind
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Impairment loss				12
Lakeswind | Intangible assets
Disclosure of reconciliation of changes in intangible assets and goodwill [line items]
Impairment loss				$ 1

Goodwill (Details)

Goodwill (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)cADPerMegawattHour	Dec. 31, 2019CAD ($)cADPerMegawattHour
Disclosure of detailed information about intangible assets [line items]
Goodwill	$ 463	$ 464
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	176
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	6	5
Discount rate used to calculate goodwill impairment	4.80%	3.60%
Maximum
Disclosure of detailed information about intangible assets [line items]
Electricity prices | cADPerMegawattHour	160	183
Discount rate used to calculate goodwill impairment	6.30%	7.00%

Other Assets (Details)

Other Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Disclosure of financial assets [abstract]
South Hedland prepaid transmission access and distribution costs	$ 70	$ 67
Deferred licence fees	0	9
Project development costs	25	19
Long-term prepaids and other assets	59	56
Loan receivable		47
Total other assets	$ 206	$ 198

Other Assets Narrative (Details

Other Assets Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Oct. 22, 2020	Dec. 31, 2019	Jul. 20, 2018
Disclosure of joint operations [line items]
Loan receivable			$ 47
Interest rate		4.07%		4.509%
Kent Hills Wind L.P.
Disclosure of joint operations [line items]
Loan receivable	$ 52		$ 47
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, 2020	Dec. 31, 2019
Reconciliation of changes in other provisions [abstract]
Balance	$ 546	$ 456
Liabilities incurred	35	14
Liabilities settled	(37)	(43)
Accretion	(30)	23
Acquisition of liabilities	1	19
Disposition of liabilities		(32)
Revisions in estimated cash flows	72	103
Revisions in discount rates	36	16
Reversals	(6)	(1)
Change in foreign exchange rates	(4)	(7)
Balance	$ 673	546
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%)
IFRS 16
Reconciliation of changes in other provisions [abstract]
Balance		2
Decommissioning and restoration
Reconciliation of changes in other provisions [abstract]
Balance	$ 501	407
Liabilities incurred	1	7
Liabilities settled	(18)	(34)
Accretion	(30)	23
Acquisition of liabilities	1	16
Disposition of liabilities		(23)
Revisions in estimated cash flows	61	96
Revisions in discount rates	36	16
Reversals	0	0
Change in foreign exchange rates	(4)	(7)
Balance	608	501
Decommissioning and restoration | IFRS 16
Reconciliation of changes in other provisions [abstract]
Balance		0
Other
Reconciliation of changes in other provisions [abstract]
Balance	45	49
Liabilities incurred	34	7
Liabilities settled	(19)	(9)
Accretion	0	0
Acquisition of liabilities	0	3
Disposition of liabilities		(9)
Revisions in estimated cash flows	11	7
Revisions in discount rates	0	0
Reversals	(6)	(1)
Change in foreign exchange rates	0	0
Balance	$ 65	45
Other | IFRS 16
Reconciliation of changes in other provisions [abstract]
Balance		$ 2

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of other provisions [line items]
Balance	$ 673	$ 546	$ 456
Current portion	59	58
Non-current portion	614	488
Decommissioning and restoration
Disclosure of other provisions [line items]
Balance	608	501	407
Current portion	21	36
Non-current portion	587	465
Other
Disclosure of other provisions [line items]
Balance	65	45	$ 49
Current portion	38	22
Non-current portion	$ 27	$ 23

Decommissioning and Other Pro_5

Decommissioning and Other Provisions - Decommissioning and Restoration (Details) $ in Millions, $ in Millions	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)
Disclosure of detailed information about borrowings [line items]
Undiscounted cash flows required for future removal of facilities	$ 1,400
Onerous contracts provision	29
Centralia Coal Mine | Surety Bonds
Disclosure of detailed information about borrowings [line items]
Bonds issued		$ 147		$ 147
Alberta Mine | Letters Of Credit [Member]
Disclosure of detailed information about borrowings [line items]
Bonds issued	$ 131		$ 128

Credit Facilities, Long-Term _3

Credit Facilities, Long-Term Debt and Lease Liabilities - Amounts Outstanding (Details) $ in Millions, $ in Millions, $ in Millions	Dec. 31, 2020CAD ($)	Dec. 31, 2020USD ($)	Oct. 22, 2020AUD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Aug. 02, 2018CAD ($)	Jul. 20, 2018
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 3,361			$ 3,212
Interest rate			4.07%				4.509%
Less: current portion of long-term debt	(97)			(494)
Less: current portion of lease liabilities	(8)			(19)
Total current long-term debt and lease liabilities	(105)			(513)
Credit facilities, long-term debt, and finance lease obligations	3,256			2,699
All Borrowings Except Finance Lease Obligations
Disclosure of detailed information about borrowings [line items]
Carrying value	3,227			3,070
Notional amount	3,264			3,104
Credit facilities
Disclosure of detailed information about borrowings [line items]
Carrying value	114			220
Notional amount	114			220
Debentures
Disclosure of detailed information about borrowings [line items]
Carrying value	249			647		$ 400
Notional amount	251			651
Interest rate						6.40%	6.40%
Senior notes
Disclosure of detailed information about borrowings [line items]
Carrying value	886			905
Notional amount	894			914
Senior notes | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 700			$ 700
Non-recourse
Disclosure of detailed information about borrowings [line items]
Carrying value	1,837			1,144
Notional amount	1,858			1,157
Other
Disclosure of detailed information about borrowings [line items]
Carrying value	141			154
Notional amount	147			162
Other | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 110			$ 117
Finance lease obligation
Disclosure of detailed information about borrowings [line items]
Carrying value	$ 134			$ 142
Senior Secured Note Maturing June 2042
Disclosure of detailed information about borrowings [line items]
Carrying value			$ 800
Interest rate			4.07%
Weighted average | Credit facilities
Disclosure of detailed information about borrowings [line items]
Interest rate	2.70%	2.70%		3.50%	3.50%
Weighted average | Debentures
Disclosure of detailed information about borrowings [line items]
Interest rate	7.10%	7.10%		5.80%	5.80%
Weighted average | Senior notes
Disclosure of detailed information about borrowings [line items]
Interest rate	5.40%	5.40%		5.40%	5.40%
Weighted average | Non-recourse
Disclosure of detailed information about borrowings [line items]
Interest rate	4.10%	4.10%		4.30%	4.30%
Weighted average | Other
Disclosure of detailed information about borrowings [line items]
Interest rate	7.10%	7.10%		7.10%	7.10%

Credit Facilities, Long-Term _4

Credit Facilities, Long-Term Debt and Lease Liabilities - Credit facilities summarized (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Disclosure of detailed information about borrowings [line items]
Facility size	$ 2,190
Outstanding letters of credit	621
Borrowings	3,361	$ 3,212
Available capacity	1,455
Financial assets pledged as collateral for liabilities or contingent liabilities	0	3
TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Financial assets pledged as collateral for liabilities or contingent liabilities	49
Revolving committed syndicated bank facility
Disclosure of detailed information about borrowings [line items]
Facility size	1,250
Outstanding letters of credit	379
Borrowings	114
Available capacity	757
Canadian committed bilateral credit facilities
Disclosure of detailed information about borrowings [line items]
Facility size	240
Outstanding letters of credit	150
Borrowings	0
Available capacity	90
Committed Credit Facility | TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Facility size	700
Outstanding letters of credit	92
Borrowings	0
Available capacity	608
Credit facilities
Disclosure of detailed information about borrowings [line items]
Borrowings	114	$ 220
Letter of credit
Disclosure of detailed information about borrowings [line items]
Debt instruments issued	89
Letter of credit | TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Debt instruments issued	92
Bilateral Credit Facility | Later than six months and not later than one year
Disclosure of detailed information about borrowings [line items]
Borrowings	$ 80

Credit Facilities, Long-Term _5

Credit Facilities, Long-Term Debt and Lease Liabilities - Credit Facilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about borrowings [line items]
Cash and cash equivalents	$ 411	$ 703	$ 89	$ 314
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	1,950	1,950
TransAlta Renewables Inc. | Syndicated Bank Credit Facility
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	700
Line of credit facility, increase (decrease)	200
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)	$ 17	17
Restricted cash and cash equivalents, principal amount		$ 11

Credit Facilities, Long-Term _6

Credit Facilities, Long-Term Debt and Lease Liabilities - Debentures (Details) - CAD ($) $ in Millions	Nov. 25, 2020	Aug. 02, 2018	Dec. 31, 2020	Oct. 22, 2020	Dec. 31, 2019	Jul. 20, 2018
Disclosure of detailed information about borrowings [line items]
Interest rate				4.07%		4.509%
Borrowings			$ 3,361		$ 3,212
Debentures
Disclosure of detailed information about borrowings [line items]
Interest rate		6.40%				6.40%
Borrowings		$ 400	$ 249		$ 647
Redemption of noncurrent borrowings		425
Redemption of prepayment premium recognized in net interest expense		19
Accrued and unpaid interest		$ 6
Debentures | Minimum
Disclosure of detailed information about borrowings [line items]
Interest rate			6.90%
Debentures | Maximum
Disclosure of detailed information about borrowings [line items]
Interest rate			7.30%
Medium Term Notes
Disclosure of detailed information about borrowings [line items]
Interest rate	5.00%
Borrowings, Redemption	$ 400

Credit Facilities, Long-Term _7

Credit Facilities, Long-Term Debt and Lease Liabilities - Senior Notes (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2020CAD ($)	Oct. 22, 2020	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Jul. 20, 2018
Disclosure of detailed information about borrowings [line items]
Interest rate					4.07%			4.509%
Borrowings				$ 3,361			$ 3,212
Long-term debt | Net investment hedges
Disclosure of detailed information about borrowings [line items]
Notional amount			$ 370			$ 370
Senior notes | Minimum
Disclosure of detailed information about borrowings [line items]
Interest rate			4.50%	4.50%
Senior notes | Maximum
Disclosure of detailed information about borrowings [line items]
Interest rate			6.50%	6.50%
6.65% Senior notes, due May 2018
Disclosure of detailed information about borrowings [line items]
Interest rate	6.65%
Borrowings	$ 500
Redemption of noncurrent borrowings	$ 516	$ 617
Redemption of prepayment premium recognized in net interest expense		5
Accrued and unpaid interest		$ 14

Credit Facilities, Long-Term _8

Credit Facilities, Long-Term Debt and Lease Liabilities - Non-Recourse Debt (Details) $ in Millions, $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2020CAD ($)	Oct. 22, 2020AUD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Jul. 20, 2018
Disclosure of detailed information about borrowings [line items]
Interest rate			4.07%			4.509%
Borrowings		$ 3,361		$ 3,212
Non-Recourse Variable Rate Debt | Minimum
Disclosure of detailed information about borrowings [line items]
Interest rate		2.95%
Non-Recourse Variable Rate Debt | Maximum
Disclosure of detailed information about borrowings [line items]
Interest rate		4.51%
Senior Secured Note Maturing June 2042
Disclosure of detailed information about borrowings [line items]
Interest rate			4.07%
Borrowings			$ 800
Non-Recourse Bonds
Disclosure of detailed information about borrowings [line items]
Interest rate					4.509%
Redemption of noncurrent borrowings	$ 25
Non-Recourse Bonds | TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Notional amount					$ 345

Credit Facilities, Long-Term _9

Credit Facilities, Long-Term Debt and Lease Liabilities - Other (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Oct. 22, 2020	Jul. 20, 2018
Disclosure of detailed information about borrowings [line items]
Interest rate				4.07%	4.509%
US Wind Projects - Big Level
Disclosure of detailed information about borrowings [line items]
Borrowing costs incurred	$ 112	$ 122
Tax equity funding			$ 85
Lakeswind
Disclosure of detailed information about borrowings [line items]
Borrowing costs incurred	$ 22	23
US Wind Projects - Antrim
Disclosure of detailed information about borrowings [line items]
Tax equity funding			$ 41
Accelerated tax depreciation		$ 35
Other | 5.9% Unsecured Commercial Loan Obligation due 2023
Disclosure of detailed information about borrowings [line items]
Interest rate		5.90%	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 ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020AUD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of detailed information about borrowings [line items]
Other borrowings		$ 730		$ 326
PP&E		5,822		6,207	$ 6,164
Intangible assets		313		318	373
Alberta Off-Coal Agreement	$ 40	40		40	$ 40
Alberta off-coal agreement, annual cash payments, net	$ 37
US Wind Projects - Big Level
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)		9		15
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)		17		17
TEC
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)		45		0
Renewable generation facilities
Disclosure of detailed information about borrowings [line items]
PP&E		1,277		967
Intangible assets		88		63
Non-recourse debt
Disclosure of detailed information about borrowings [line items]
Other borrowings		1,800		1,100
Restricted cash (Note 22)		73		42
Non-recourse debt | Secured by first rate ranking charge over subsidiaries
Disclosure of detailed information about borrowings [line items]
Notional amount		1,441		719
Non-recourse debt | Secured by equity interests of the issuer
Disclosure of detailed information about borrowings [line items]
Notional amount		111		119
Restricted Use Debt
Disclosure of detailed information about borrowings [line items]
Proceeds from issue of bonds, notes and debentures			$ 7
Secured Debt | TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 285		$ 305

Credit Facilities, Long-Term_11

Credit Facilities, Long-Term Debt and Lease Liabilities - Principal Repayments (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Disclosure of detailed information about borrowings [line items]
Borrowings	$ 3,361	$ 3,212
2021
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	3,264
Lease liabilities	134
Gross carrying amount | 2021
Disclosure of detailed information about borrowings [line items]
Borrowings	96
Lease liabilities	(5)
Gross carrying amount | 2022
Disclosure of detailed information about borrowings [line items]
Borrowings	626
Lease liabilities	6
Gross carrying amount | 2023
Disclosure of detailed information about borrowings [line items]
Borrowings	277
Lease liabilities	5
Gross carrying amount | 2024
Disclosure of detailed information about borrowings [line items]
Borrowings	119
Lease liabilities	5
Gross carrying amount | 2025
Disclosure of detailed information about borrowings [line items]
Borrowings	136
Lease liabilities	5
Gross carrying amount | 2026
Disclosure of detailed information about borrowings [line items]
Borrowings	2,010
Lease liabilities	$ 118

Credit Facilities, Long-Term_12

Credit Facilities, Long-Term Debt and Lease Liabilities - Letters of Credit (Details) - CAD ($)	Dec. 31, 2020	Dec. 31, 2019
Letter of credit
Disclosure of detailed information about borrowings [line items]
Exposure to credit risk on loan commitments and financial guarantee contracts	$ 621,000,000	$ 690,000,000
Amount exercised under letters of credit	0	$ 0
Committed bilateral credit facilities
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	240,000,000
Uncommitted demand letter facility
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	100,000,000
Uncommitted demand letter facility | TransAlta Renewables Inc.
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit	$ 100,000,000

Exchangeable Securities (Detail

Exchangeable Securities (Details) - CAD ($) $ / shares in Units, $ in Millions	Oct. 30, 2020	May 25, 2019	May 22, 2019	May 01, 2019	Dec. 31, 2020	Dec. 31, 2018	Oct. 22, 2020	Dec. 31, 2019	Jul. 20, 2018
Disclosure of detailed information about borrowings [line items]
Minimum proceeds for each redemption of exchangeable securities						$ 100
Interest rate							4.07%		4.509%
Investment Agreement | Discount rates
Disclosure of detailed information about borrowings [line items]
Percentage of reasonably possible increase in unobservable input, liabilities					1.00%
Investment Agreement | Brookfield Renewable Partners
Disclosure of detailed information about borrowings [line items]
Proceeds on sale of an organizational unit		$ 750	$ 750
Other cash receipts from sales of equity or debt instruments of other entities, classified as investing activities	$ 400			$ 350
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]
Equity participation percentage					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]
Equity participation percentage					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]
Equity participation percentage					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]
Equity participation percentage					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%

Exchangeable Securities - Sched

Exchangeable Securities - Schedule of Exchangeable Securities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Oct. 22, 2020	Dec. 31, 2019	May 01, 2019	Jul. 20, 2018
Disclosure of detailed information about borrowings [line items]
Interest rate		4.07%			4.509%
Credit facilities, long-term debt, and finance lease obligations	$ 3,256		$ 2,699
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		$ 0
Credit facilities, long-term debt, and finance lease obligations	750		350
Gross carrying amount | 7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of detailed information about borrowings [line items]
Notes and debentures issued	330		326
Exchangeable Preferred Shares	400		0
Credit facilities, long-term debt, and finance lease obligations	$ 730		$ 326

Exchangeable Securities - Optio

Exchangeable Securities - Option To Exchange (Details) - Option to exchange - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
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	$ (33)	$ (27)

Defined Benefit Obligation an_3

Defined Benefit Obligation and Other Long-Term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Defined benefit obligation (Note 28)	$ 282	$ 268
Long-term incentive accruals (Note 27)	4	4
Other	12	29
Total	$ 298	$ 301

Common Shares - Issued and Outs

Common Shares - Issued and Outstanding (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Disclosure of classes of share capital [line items]
Proceeds from exercise of options	$ 0	$ 2
Common shares
Shares issued	15,068,900
Dilutive effect of share options on number of ordinary shares	100,000	100,000
Common shares
Disclosure of classes of share capital [line items]
Issued and outstanding, end of year	$ 2,978	$ 3,059
Proceeds from issuing shares	(79)	(83)
Effects of share-based payment plans	(3)	0
Issued and outstanding, end of year	$ 2,896	$ 2,978
Common shares
Issued and outstanding, beginning of year	277,000,000	284,600,000
Shares issued	(7,300,000)	(7,700,000)
Issued and outstanding, end of year	269,800,000	277,000,000

Common Shares - The effects of

Common Shares - The effects of the Corporation's purchase and cancellation of the common shares (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)$ / sharesshares	Dec. 31, 2019CAD ($)$ / sharesshares	Dec. 31, 2018CAD ($)$ / sharesshares
Disclosure of classes of share capital [line items]
Deficit	$ (1,826)	$ (1,455)
Number of shares issued and fully paid that were not cancelled due to timing differences between the transaction date and settlement date | shares	456,200	189,900
NCIB Program
Disclosure of classes of share capital [line items]
Number of shares issued and fully paid | shares	7,352,600	7,716,300	3,264,500
Par value per share | $ / shares	$ 8.33	$ 8.80	$ 7.02
Issued capital	$ 61	$ 68	$ 23
Weighted average share price	79	83
Deficit	$ 18	$ 15
Par value per share | $ / shares	$ 8.33	$ 8.80	$ 7.02
Common shares
Disclosure of classes of share capital [line items]
Issued capital	$ 2,896	$ 2,978	$ 3,059

Common Shares - Shareholder Rig

Common Shares - Shareholder Rights Plan (Details)	12 Months Ended
	Dec. 31, 2020
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 Millions, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share Capital, Reserves And Other Equity Interest [Abstract]
Net earnings (loss) attributable to common shareholders	$ (336)	$ 52	$ (248)
Basic and diluted weighted average number of common shares outstanding (millions)	275	283	287
Net earnings (loss) per share attributable to common shareholders, basic and diluted (in CAD per share)	$ (1.22)	$ 0.18	$ (0.86)

Common Shares - Dividends (Deta

Common Shares - Dividends (Details) - $ / shares	Dec. 23, 2020	Nov. 03, 2020
Share Capital, Reserves And Other Equity Interest [Abstract]
Dividends declared per share	$ 0.0450	$ 0.0425

Preferred Shares - Issued and O

Preferred Shares - Issued and Outstanding (Details) - CAD ($) shares in Thousands, $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Mar. 17, 2016
Preferred Shares
Disclosure of classes of share capital [line items]
Number of shares outstanding	38,600	38,600
Number of shares issued and outstanding	38,600	38,600
Issued capital (Note 25)	$ 942	$ 942
Series A
Disclosure of classes of share capital [line items]
Number of shares outstanding	10,200	10,200	12,000
Number of shares issued and outstanding	10,200	10,200
Issued capital (Note 25)	$ 248	$ 248
Series B
Disclosure of classes of share capital [line items]
Number of shares outstanding	1,800	1,800
Number of shares issued and outstanding	1,800	1,800
Issued capital (Note 25)	$ 45	$ 45
Series C
Disclosure of classes of share capital [line items]
Number of shares outstanding	11,000	11,000
Number of shares issued and outstanding	11,000	11,000
Issued capital (Note 25)	$ 269	$ 269
Series E
Disclosure of classes of share capital [line items]
Number of shares outstanding	9,000	9,000
Number of shares issued and outstanding	9,000	9,000
Issued capital (Note 25)	$ 219	$ 219
Series G
Disclosure of classes of share capital [line items]
Number of shares outstanding	6,600	6,600
Number of shares issued and outstanding	6,600	6,600
Issued capital (Note 25)	$ 161	$ 161

Preferred Shares - Series Cumul

Preferred Shares - Series Cumulative Redeemable Rate Reset Preferred Shares Conversion (Details) - $ / shares	Mar. 01, 2021	Dec. 23, 2020	Nov. 03, 2020	Sep. 17, 2017	Jun. 16, 2017	Dec. 31, 2020	Dec. 31, 2019	Aug. 30, 2019	Mar. 17, 2016
Disclosure of classes of share capital [line items]
Remaining balance threshold for conversion to other series (in shares)	1,000,000
Dividends declared per share		$ 0.0450	$ 0.0425
Series G
Disclosure of classes of share capital [line items]
Convertible Preferred Shares , Threshold For Required Shares Conversion				1,000,000,000,000
Convertible preferred shares tendered for conversion								140,730
Annualized fixed dividend rate						4.988%
Bond yield						1.188%
Dividend rate on preference shares, spread						3.80%
Number of shares outstanding						6,600,000	6,600,000
Dividends declared per share		0.31175
Series E
Disclosure of classes of share capital [line items]
Convertible Preferred Shares , Threshold For Required Shares Conversion				1,000,000,000,000
Convertible preferred shares tendered for conversion				133,969
Annualized fixed dividend rate						5.194%
Bond yield						1.544%
Bond yield, period						5 years
Dividend rate on preference shares, spread						3.65%
Number of shares outstanding						9,000,000	9,000,000
Dividends declared per share		0.32463
Series C
Disclosure of classes of share capital [line items]
Convertible Preferred Shares , Threshold For Required Shares Conversion					1,000,000,000,000
Convertible preferred shares tendered for conversion					827,628
Annualized fixed dividend rate						4.027%
Bond yield						0.927%
Bond yield, period						5 years
Dividend rate on preference shares, spread						3.10%
Number of shares outstanding						11,000,000	11,000,000
Dividends declared per share		0.25169
Series A
Disclosure of classes of share capital [line items]
Annualized fixed dividend rate						2.709%
Bond yield	0.847%
Bond yield, period	5 years
Dividend rate on preference shares, spread	2.03%
Number of shares converted into other classes of shares									1,824,620
Number of shares outstanding						10,200,000	10,200,000		12,000,000
Payment period for cumulative preferential cash dividends						5 years
Dividends declared per share		0.16931
Series A | Later than four years and not later than five years
Disclosure of classes of share capital [line items]
Annualized fixed dividend rate	2.877%
Series B
Disclosure of classes of share capital [line items]
Annualized fixed dividend rate						2.03%
Bond yield	0.073%
Dividend rate on preference shares, spread	2.03%					2.03%
Number of shares outstanding						1,800,000	1,800,000
Payment period for cumulative preferential cash dividends						5 years
Dividends declared per share		$ 0.13186
Series B | Later than four years and not later than five years
Disclosure of classes of share capital [line items]
Annualized fixed dividend rate	2.103%

Preferred Shares - Preferred Sh

Preferred Shares - Preferred Share Series Information (Details) - Preferred Shares	12 Months Ended
	Dec. 31, 2020$ / 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, 2020$ / shares
Series A
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 0.67724
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	$ 0.73801
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	Mar. 01, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Series A
Disclosure of classes of share capital [line items]
Dividends declared		$ 9	$ 5	$ 9
Dividend rate on preference shares, spread	2.03%
Series B
Disclosure of classes of share capital [line items]
Dividends declared		$ 1	1	1
Dividend rate on preference shares, spread	2.03%	2.03%
Series C
Disclosure of classes of share capital [line items]
Dividends declared		$ 14	8	14
Dividend rate on preference shares, spread		3.10%
Series E
Disclosure of classes of share capital [line items]
Dividends declared		$ 15	9	15
Dividend rate on preference shares, spread		3.65%
Series G
Disclosure of classes of share capital [line items]
Dividends declared		$ 10	7	11
Dividend rate on preference shares, spread		3.80%
Preferred Shares
Disclosure of classes of share capital [line items]
Dividends declared		$ 49	$ 30	$ 50

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020		Dec. 31, 2019	Dec. 31, 2018
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		$ 454
Currency translation adjustment
Losses on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax				$ 38
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax		11		21	$ (41)
Cash flow hedges
Gains (losses) on derivatives designated as cash flow hedges, net of tax	[1]	20		61	(8)
Other
Intercompany FVOCI investments		0		0
Accumulated other comprehensive income, end of the period		302		454
Net impact related to cash flow hedges		(23)		6	(12)
Income tax relating to net actuarial gains (losses)		3		7	(5)
Reserve of exchange differences on translation
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(21)		17
Currency translation adjustment
Losses on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		(11)		(59)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax		11		21
Other
Accumulated other comprehensive income, end of the period		(21)		(21)	17
Reserve of cash flow hedges
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		527		508
Cash flow hedges
Gains (losses) on derivatives designated as cash flow hedges, net of tax		(91)		19
Other
Accumulated other comprehensive income, end of the period		436		527	508
Net impact related to cash flow hedges		23		6
Reserve of remeasurements of defined benefit plans
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(55)		(29)
Employee future benefits
Net actuarial gains (losses) on defined benefit plans, net of tax		(11)		(26)
Other
Accumulated other comprehensive income, end of the period		(66)		(55)	(29)
Income tax relating to net actuarial gains (losses)		(3)		(7)
Other reserves
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		3		(15)
Other
Change in ownership of TransAlta Renewables		0		1
Intercompany FVOCI investments		(50)	[2]	17
Accumulated other comprehensive income, end of the period		$ (47)		$ 3	$ (15)
[1]	Net of income tax expense of $8 million for the year ended Dec. 31, 2020 (2019 —$16 million expense, 2018 — $1 million recovery).
[2]	Refer to Note 29 for details on components of, and changes in, accumulated other comprehensive income (loss).

Share-Based Payment Plans (Deta

Share-Based Payment Plans (Details) $ / shares in Units, shares in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)shares	Dec. 31, 2019CAD ($)shares$ / shares	Dec. 31, 2018CAD ($)shares	Feb. 29, 2016shares
Disclosure of terms and conditions of share-based payment arrangement [line items]
Expense from cash-settled share-based payment transactions in which goods or services received did not qualify for recognition as assets		$ 25,000,000
Expense from equity-settled share-based payment transactions in which goods or services received did not qualify for recognition as assets		24,000,000
Cumulative change in compensation expense		1,000,000
Executive officers
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of share options granted (in shares) | shares	0.7
Weighted average exercise price of share options granted in share-based payment arrangement	$ 9.17	$ 5.65	$ 7.45
PSUs and RSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Performance period	3 years
Vesting period	3 years
Par value per share | $ / shares		$ 8.29
Compensation expense (reversal)	$ 15,000,000	$ 19,000,000	8,000,000
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)	$ 1,000,000	2,000,000	0
Stock Options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of shares authorized (in shares) | shares				16.5
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	$ 1,000,000	$ 1,000,000
Number of share options granted (in shares) | shares		1.4	0.7

Share-Based Payment Plans - Sto

Share-Based Payment Plans - Stock Options (Details) - 5.00 - 10.00 shares in Millions	12 Months Ended
	Dec. 31, 2020sharesCAD ($)
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Number of options (in shares) | shares	4
Weighted average remaining contractual life (in years)	4 years 2 months 12 days
Weighted average exercise price (in dollars per share)	$ 6.85
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)	$ 10

Employee Future Benefits (Detai

Employee Future Benefits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020CAD ($)age	Dec. 31, 2020CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of defined benefit plans [line items]
Administration expenses		$ 1			$ 2	$ 1
Weighted average duration of defined benefit obligation	14 years 4 months 24 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			2	1
Registered | Letter of credit
Disclosure of defined benefit plans [line items]
Letter of credit, posted	$ 89	89	$ 89	$ 89
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	65
Administration expenses		$ 0			$ 0	$ 0

Employee Future Benefits - Cost

Employee Future Benefits - Costs Recognized (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	$ 8	$ 10	$ 12
Administration expenses	1	2	1
Defined benefit expense	15	19	22
Defined contribution expense	9	9	10
Net expense	24	28	32
Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	20	23	22
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	(12)	(13)	(13)
Curtailment and amendment gain	(2)	(3)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	5	7	9
Administration expenses	1	2	1
Defined benefit expense	9	13	15
Defined contribution expense	9	9	10
Net expense	18	22	25
Registered | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	5	7
Interest cost	16	19	18
Curtailment and amendment gain	(2)	(3)
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	(11)	(12)	(13)
Curtailment and amendment gain	(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	5
Defined contribution expense	0	0	0
Net expense	4	4	5
Supplemental Pension Plan | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	2	2
Interest cost	3	3	3
Curtailment and amendment gain	0	0
Supplemental Pension Plan | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	(1)	(1)	0
Curtailment and amendment gain	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	2	2	2
Defined contribution expense	0	0	0
Net expense	2	2	2
Other | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	1	1
Interest cost	1	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

Employee Future Benefits - Stat

Employee Future Benefits - Status of Plans (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	$ (294)	$ (278)
Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(12)	(10)
Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(282)	(268)
Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	381	386	$ 381
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(675)	(664)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(175)	(170)
Registered | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(5)	(3)
Registered | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(170)	(167)
Registered | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	367	373	368
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(542)	(543)	(514)
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(95)	(86)
Supplemental Pension Plan | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(5)	(5)
Supplemental Pension Plan | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(90)	(81)
Supplemental Pension Plan | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	14	13	13
Supplemental Pension Plan | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(109)	(99)	(80)
Other
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(24)	(22)
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)	(22)	(20)
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)	$ (24)	$ (22)	$ (25)

Employee Future Benefits - Fair

Employee Future Benefits - Fair Value of Plan Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	$ (278)
Administration expenses	(1)	$ (2)	$ (1)
Net asset, ending of period	(294)	(278)
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	386	381
Interest on plan assets	12	13	13
Net return on plan assets	24	40
Contributions	13	11
Benefits paid	(51)	(56)
Effect of translation on US plans	(2)	(1)
Net asset, ending of period	381	386	381
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(170)
Administration expenses	(1)	(2)	(1)
Net asset, ending of period	(175)	(170)
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	373	368
Interest on plan assets	11	12	13
Net return on plan assets	25	40
Contributions	6	6
Benefits paid	(45)	(50)
Effect of translation on US plans	(2)	(1)
Net asset, ending of period	367	373	368
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(86)
Administration expenses	0	0	0
Net asset, ending of period	(95)	(86)
Supplemental Pension Plan | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	13	13
Interest on plan assets	1	1	0
Net return on plan assets	(1)	0
Contributions	6	4
Benefits paid	(5)	(5)
Effect of translation on US plans	0	0
Net asset, ending of period	14	13	13
Other
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(22)
Administration expenses	0	0	0
Net asset, ending of period	(24)	(22)
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	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, 2020	Dec. 31, 2019
Disclosure of fair value of plan assets [line items]
Money market and cash and cash equivalents	$ 19	$ 19
Total	381	386
Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	64	66
US
Disclosure of fair value of plan assets [line items]
Equity securities	30	28
International
Disclosure of fair value of plan assets [line items]
Equity securities	103	102
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	36	40
AA
Disclosure of fair value of plan assets [line items]
Bonds	67	68
A
Disclosure of fair value of plan assets [line items]
Bonds	34	37
BBB
Disclosure of fair value of plan assets [line items]
Bonds	23	22
Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	4	3
Level I
Disclosure of fair value of plan assets [line items]
Money market and cash and cash equivalents	0	0
Total	1	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	0	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	19	19
Total	379	384
Level II | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	64	66
Level II | US
Disclosure of fair value of plan assets [line items]
Equity securities	30	28
Level II | International
Disclosure of fair value of plan assets [line items]
Equity securities	103	102
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	36	40
Level II | AA
Disclosure of fair value of plan assets [line items]
Bonds	67	68
Level II | A
Disclosure of fair value of plan assets [line items]
Bonds	34	37
Level II | BBB
Disclosure of fair value of plan assets [line items]
Bonds	22	21
Level II | Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	4	3
Level III
Disclosure of fair value of plan assets [line items]
Money market and cash and cash equivalents	0	0
Total	1	1
Level III | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	0	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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	$ 278
Current service cost	8	$ 10	$ 12
Actuarial gain arising from demographic assumptions	(11)	(26)
Defined benefit obligation, ending of period	294	278
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	664
Interest cost	20	23	22
Defined benefit obligation, ending of period	675	664
Registered
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	170
Current service cost	5	7	9
Defined benefit obligation, ending of period	175	170
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	543	514
Current service cost	5	7
Interest cost	16	19	18
Benefits paid	(45)	(51)
Curtailment and amendment gain	(2)	(3)
Actuarial gain arising from demographic assumptions	0	0
Actuarial loss arising from financial assumptions	43	57
Actuarial gain (loss) arising from experience adjustments	(17)	2
Effect of translation on US plans	(1)	(2)
Defined benefit obligation, ending of period	542	543	514
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	86
Current service cost	2	2	2
Defined benefit obligation, ending of period	95	86
Supplemental Pension Plan | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	99	80
Current service cost	2	2
Interest cost	3	3	3
Benefits paid	(5)	(4)
Curtailment and amendment gain	0	0
Actuarial gain arising from demographic assumptions	0	0
Actuarial loss arising from financial assumptions	10	9
Actuarial gain (loss) arising from experience adjustments	0	9
Effect of translation on US plans	0	0
Defined benefit obligation, ending of period	109	99	80
Other
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	22
Current service cost	1	1	1
Defined benefit obligation, ending of period	24	22
Other | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	22	25
Current service cost	1	1
Interest cost	1	1	1
Benefits paid	(1)	(1)
Curtailment and amendment gain	0	0
Actuarial gain arising from demographic assumptions	0	(2)
Actuarial loss arising from financial assumptions	2	2
Actuarial gain (loss) arising from experience adjustments	0	(4)
Effect of translation on US plans	(1)	0
Defined benefit obligation, ending of period	24	22	25
Total | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	664	619
Current service cost	8	10
Interest cost	20	23
Benefits paid	(51)	(56)
Curtailment and amendment gain	(2)	(3)
Actuarial gain arising from demographic assumptions	0	(2)
Actuarial loss arising from financial assumptions	55	68
Actuarial gain (loss) arising from experience adjustments	(17)	7
Effect of translation on US plans	(2)	(2)
Defined benefit obligation, ending of period	$ 675	$ 664	$ 619

Employee Future Benefits - Cont

Employee Future Benefits - Contributions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020CAD ($)
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	5
Other
Disclosure of defined benefit plans [line items]
Expected employer contributions	2
Total
Disclosure of defined benefit plans [line items]
Expected employer contributions	$ 12

Employee Future Benefits - Assu

Employee Future Benefits - Assumptions (Details)	12 Months Ended
	Dec. 31, 2020age	Dec. 31, 2020	Dec. 31, 2019
Other, through 2027
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	65
Percentage of reasonably possible decrease in actuarial assumption	0.30%	0.30%
Other, through 2026
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	4.50%	4.50%	4.50%
Maximum age disabled and retired members eligible for benefits		65
Percentage of reasonably possible decrease in actuarial assumption	0.30%	0.30%	0.30%
Other, through 2026 | Canada
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	4.50%	4.50%	4.50%
Other, through 2024
Assumed health-care cost trend rate
Maximum age disabled and retired members eligible for benefits		65
Other, through 2024 | Canada
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)			4.50%
Other, through 2024 | 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	2.40%	2.40%	3.00%
Rate of compensation increase	2.90%	2.90%	2.80%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	0.00%	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%	0.00%
Accrued Benefit Obligation | Supplemental Pension Plan
Disclosure of defined benefit plans [line items]
Discount rate	2.30%	2.30%	3.00%
Rate of compensation increase	3.00%	3.00%	3.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	0.00%	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%	0.00%
Accrued Benefit Obligation | Other, through 2027
Disclosure of defined benefit plans [line items]
Discount rate	2.30%	2.30%	3.00%
Rate of compensation increase	0.00%	0.00%	0.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	6.80%	6.80%	7.00%
Dental-care cost escalation	4.00%	4.00%	4.00%
Other, through 2027 | Registered
Disclosure of defined benefit plans [line items]
Discount rate	3.00%	3.00%	3.90%
Rate of compensation increase	2.90%	2.90%	2.50%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	0.00%	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%	0.00%
Other, through 2027 | Supplemental Pension Plan
Disclosure of defined benefit plans [line items]
Discount rate	3.00%	3.00%	3.80%
Rate of compensation increase	3.00%	3.00%	3.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	0.00%	0.00%	0.00%
Dental-care cost escalation	0.00%	0.00%	0.00%
Other, through 2027 | Other, through 2027
Disclosure of defined benefit plans [line items]
Discount rate	3.00%	3.00%	3.90%
Rate of compensation increase	0.00%	0.00%	0.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	7.10%	7.10%	7.40%
Dental-care cost escalation	4.00%	4.00%	4.00%

Employee Future Benefits - Sens

Employee Future Benefits - Sensitivity Analysis (Details) $ in Millions	Dec. 31, 2020CAD ($)
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	$ 74
Registered Pension Plan | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	5
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	4
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	17
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	1
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, 2020
Wind and Solar | Skookumchuck
Disclosure of joint operations [line items]
Proportion of ownership interest in joint venture	49.00%
Sheerness | Alberta Thermal
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Pioneer Pipeline | Alberta Thermal
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 | North American Gas
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	60.00%
Fortescue River Gas Pipeline | Australian 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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of cash flow statement [Abstract]
Accounts receivable	$ (79)	$ 261	$ 58
Prepaid expenses	2	0	19
Income taxes receivable	(4)	(6)	0
Inventory	6	(13)	(21)
Accounts payable, accrued liabilities and provisions	160	(130)	(97)
Income taxes payable	4	9	(3)
Change in non-cash operating working capital	$ 89	$ 121	$ (44)

Cash Flow Information Changes i

Cash Flow Information Changes in Liabilities from Financing Activities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	$ 3,575	$ 3,325
Net cash flows	447	195
New leases	16	133
Tax shield on tax equity financing		(35)
Dividends declared	107	64
Foreign exchange impact	5	(42)
Other	0	(65)
Balance at end of the period	4,150	3,575
Long-term debt and lease obligations
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	3,212	3,267
Net cash flows	133	(70)
New leases	16	133
Tax shield on tax equity financing		(35)
Dividends declared	0	0
Foreign exchange impact	5	(42)
Other	(5)	(41)
Balance at end of the period	3,361	3,212
Exchangeable securities (Note 25)
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	326	0
Net cash flows	400	350
New leases	0	0
Tax shield on tax equity financing		0
Dividends declared	0	0
Foreign exchange impact	0	0
Other	4	(24)
Balance at end of the period	730	326
Dividends payable (common and preferred)
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	37	58
Net cash flows	(86)	(85)
New leases	0	0
Tax shield on tax equity financing		0
Dividends declared	107	64
Foreign exchange impact	0	0
Other	1	0
Balance at end of the period	$ 59	$ 37

Capital Disclosure of component

Capital Disclosure of components of capital (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of components of capital [Line Items]
Long-term debt		$ 3,361	$ 3,212
Increase (decrease) in financial liabilities		149
Exchangeable securities		730	326
Increase (decrease) in exchangeable securities		404
Equity		3,436	4,062	$ 4,134
Cash and cash equivalents		(703)	(411)	(89)	$ (314)
Increase (decrease) in cash and cash equivalents		(292)	(322)	225
Current restricted cash and cash equivalents		(71)	(32)
Fair value asset of hedging instruments on long-term debt		(2)	(7)
Increase (decrease) in hedging instruments, liabilities		5
Total capital		6,811	7,172
Increase (decrease) in capital		(361)
Common shares
Disclosure of components of capital [Line Items]
Equity		2,896	2,978
Increase (decrease) in equity		(82)
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		38	42	11
Increase (decrease) in equity		(4)
Deficit
Disclosure of components of capital [Line Items]
Equity		(1,826)	(1,455)	(1,496)
Increase (decrease) in equity		(371)
Accumulated other comprehensive income
Disclosure of components of capital [Line Items]
Equity	[1]	302	454	481
Increase (decrease) in equity		(152)
Non-controlling interests
Disclosure of components of capital [Line Items]
Equity		1,084	1,101	$ 1,137
Increase (decrease) in equity		(17)
TransAlta OCP
Disclosure of components of capital [Line Items]
Current restricted cash and cash equivalents		(11)	$ (10)
Increase (decrease) in restricted cash and cash equivalents		$ (1)
[1]	Refer to Note 29 for details on components of, and changes in, accumulated other comprehensive income (loss).

Capital Disclosure of investmen

Capital Disclosure of investment grade credit rating (Details)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Investment [Line Items]
Comparable funds from operations to adjusted interest coverage, actual	4.2	4.5
Adjusted comparable funds from operations to adjusted net debt, actual	18.30%	19.00%
Adjusted net debt to comparable earnings before interest, taxes, depreciation, and amortization, actual	3.9	3.9
Deconsolidated net debt to deconsolidated comparable EBITDA, actual	460.00%	420.00%
Percentage of dividends added to comparable FFO before Interest to adjusted interest coverage	50.00%
Percentage of preferred shares added to net debt in Adjusted Comparable FFO to Adjusted Net Debt	50.00%
Percentage of preferred shares added to net debt in Adjusted Comparable Funds From EBITDA to Adjusted Net Debt Ratio	50.00%
Minimum
Investment [Line Items]
Range of times to maintain percentage of dividends added to comparable FFO before Interest to adjusted interest coverage, as a multiple	4
Percentage of preferred dividends deducted from Adjusted Comparable Funds From Operations to Adjusted Net Debt Ratio, Range to Maintain	2000.00%
Percentage of preferred shares added to net debt in Adjusted Comparable Funds From Operations to Adjusted Net Debt Ratio, Range to Maintain	3
Percentage of preferred shares added to net debt in Adjusted Comparable Funds From EBITDA to Adjusted Net Debt Ratio, Range To Maintain Expressed As A Multiple	2.5
Maximum
Investment [Line Items]
Range of times to maintain percentage of dividends added to comparable FFO before Interest to adjusted interest coverage, as a multiple	5
Percentage of preferred dividends deducted from Adjusted Comparable Funds From Operations to Adjusted Net Debt Ratio, Range to Maintain	2500.00%
Percentage of preferred shares added to net debt in Adjusted Comparable Funds From Operations to Adjusted Net Debt Ratio, Range to Maintain	3.5
Percentage of preferred shares added to net debt in Adjusted Comparable Funds From EBITDA to Adjusted Net Debt Ratio, Range To Maintain Expressed As A Multiple	3

Capital Disclosure of cash flow

Capital Disclosure of cash flow statement (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of classes of share capital [line items]
Cash flows from (used in) operating activities	$ 702	$ 849	$ 820
Increase (decrease) in cash flow from (used in) operating activities	(147)
Change in non-cash operating working capital balances	(89)	(121)	44
Increase (decrease) in non cash working capital	32
Cash flow from operations before changes in working capital	613	728	864
Increase (decrease) in cash flow from operations before changes in working capital	(115)
Distributions paid to subsidiaries’ non-controlling interests	97	106	165
Increase (decrease) in dividends paid to non controlling interests	9
Property, plant and equipment expenditures	486	417	277
Increase (decrease) in property, plant and equipment expenditure	(69)
Net inflows (outflows) of cash	(56)	120
Increase (decrease) in net inflows (outflows) of cash	(176)
Credit facilities | Committed credit facilities
Disclosure of classes of share capital [line items]
Undrawn borrowing capacity under line of credit	1,500	1,300
Common shares
Disclosure of classes of share capital [line items]
Dividends paid	47	45	46
Increase (decrease) in dividends paid	(2)
Preferred shares
Disclosure of classes of share capital [line items]
Dividends paid	39	$ 40	$ 40
Increase (decrease) in dividends paid	$ 1

Related Party Transactions Disc

Related Party Transactions Disclosure of interests in subsidiaries (Details)

1 Months Ended

3 Months Ended

4 Months Ended

6 Months Ended

11 Months Ended

12 Months Ended

Dec. 31, 2018

Jul. 30, 2018

Jun. 30, 2020

Mar. 31, 2020

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Nov. 29, 2018

Dec. 31, 2020

Jun. 21, 2018

Dec. 31, 2020

TransAlta Renewables Inc.

Disclosure of subsidiaries [line items]

Ownership interest (as a percent)

60.90%

61.10%

60.20%

60.30%

60.40%

60.50%

60.60%

60.80%

61.00%

60.10%

64.00%

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party [Abstract]
Total compensation	$ 27	$ 30	$ 17
Short-term employee benefits	12	13	11
Post-employment benefits	2	2	2
Termination benefits	0	2	0
Share-based payments	$ 13	$ 13	$ 4

Commitments and Contingencies -

Commitments and Contingencies - Commitments (Details) $ in Millions, $ in Millions	Dec. 31, 2020CAD ($)	Jul. 30, 2015USD ($)
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	$ 410
Long-term service agreements	173
Operating leases	36
Growth	1,013
TransAlta Energy Transition Bill	18	$ 55
Total	3,733
Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	2,048
Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	35
2021
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	81
Long-term service agreements	31
Operating leases	4
Growth	509
TransAlta Energy Transition Bill	6
Total	780
2021 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	141
2021 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	8
2022
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	105
Long-term service agreements	37
Operating leases	2
Growth	411
TransAlta Energy Transition Bill	6
Total	718
2022 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	149
2022 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	8
2023
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	101
Long-term service agreements	22
Operating leases	2
Growth	93
TransAlta Energy Transition Bill	6
Total	369
2023 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	137
2023 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	8
2024
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	67
Long-term service agreements	18
Operating leases	1
Growth	0
TransAlta Energy Transition Bill	0
Total	225
2024 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	134
2024 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	5
2025
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	56
Long-term service agreements	10
Operating leases	1
Growth	0
TransAlta Energy Transition Bill	0
Total	206
2025 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	134
2025 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	5
2026
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	0
Long-term service agreements	55
Operating leases	26
Growth	0
TransAlta Energy Transition Bill	0
Total	1,435
2026 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	1,353
2026 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	$ 1

Commitments and Contingencies_2

Commitments and Contingencies (Details) $ in Millions, $ in Millions	Dec. 21, 2020CAD ($)	Oct. 22, 2020CAD ($)	Dec. 31, 2020CAD ($)J	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2020CAD ($)	Dec. 31, 2020terajoule	Dec. 31, 2020USD ($)	Jul. 30, 2015USD ($)
Disclosure of Commitments [Line Items]
Transportation agreement, term			15 years
Long-term firm natural gas delivery transportation, amount transferred per day			400				400
Minimum operating lease payments recognised as expense					$ 8
Sublease payments received (amounts less than)			$ 2	$ 1	$ 1
TransAlta Energy Transition Bill						$ 18			$ 55
Funded portion of energy bill commitment								$ 41
Total payments, line loss proceedings	$ 11	$ 6	25
Accrued payments, line loss proceedings			$ 8
Estimated financial effect of contingent liabilities						12
Emissions performance credits allotted, per year, amount						17
Loss contingency accrual						22
Increase (decrease) in loss contingency accrual, percentage			15.00%
Increase (decrease) in loss contingency accrual						3
AltaLink Management Ltd. [Member]
Disclosure of Commitments [Line Items]
Loss contingency accrual						$ 91
NOVA Gas Transmission Ltd.
Disclosure of Commitments [Line Items]
Long-term firm natural gas delivery transportation, amount transferred per day			351				275
Tidewater
Disclosure of Commitments [Line Items]
Long-term firm natural gas delivery transportation, amount transferred per day			139				139

Segments Disclosures - Addition

Segments Disclosures - Additional Information (Details) - segment	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2020
Disclosure of major customers [line items]
Number of segments		8
Customer 1
Disclosure of major customers [line items]
Percentage of entity's revenue	11.00%

Segments Disclosures - Reported

Segments Disclosures - Reported Segment Earnings (Loss) and Segment Assets (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of operating segments [line items]
Revenues		$ 2,101	$ 2,347	$ 2,249
Fuel, carbon compliance and purchased power		968	1,086	1,100
Gross margin		1,133	1,261	1,149
Operations, maintenance and administration		472	475	515
Depreciation and amortization		654	590	574
Asset impairment		84	25	73
Gain on termination of Keephills 3 coal rights contract	$ 88	0	88	0
Taxes, other than income taxes		33	29	31
Termination of Sundance B and CPPAs		0	56	157
Net other operating expense (income)		(11)	(49)	(47)
Operating income		(99)	335	160
Equity income from associate		1	0	0
Finance lease income		7	6	8
Net interest expense		(238)	(179)	(250)
Foreign exchange gain (loss)		17	(15)	(15)
Gain on sale of assets and other		9	46	1
Earnings (loss) before income taxes		(303)	193	(96)
Contribution from equity accounted investments
Disclosure of operating segments [line items]
Revenues		(3)
Fuel, carbon compliance and purchased power		0
Gross margin		(3)
Operations, maintenance and administration		0
Depreciation and amortization		1
Asset impairment		0
Taxes, other than income taxes		0
Net other operating expense (income)		0
Operating income		(2)
Equity income from associate		1
Finance lease income		0
Net interest expense		1
Foreign exchange gain (loss)		0
Gain on sale of assets and other		0
Earnings (loss) before income taxes		0
Operating segments
Disclosure of operating segments [line items]
Revenues		2,104
Fuel, carbon compliance and purchased power		968
Gross margin		1,136
Operations, maintenance and administration		472
Depreciation and amortization		655
Asset impairment		84
Taxes, other than income taxes		33
Net other operating expense (income)		(11)
Operating income		(97)
Equity income from associate		0
Finance lease income		7
Net interest expense		(239)
Foreign exchange gain (loss)		17
Gain on sale of assets and other		9
Earnings (loss) before income taxes		(303)
Hydro | Operating segments
Disclosure of operating segments [line items]
Revenues		152	156	156
Fuel, carbon compliance and purchased power		8	7	6
Gross margin		144	149	150
Operations, maintenance and administration		37	36	38
Depreciation and amortization		28	32	30
Asset impairment		2	2	0
Gain on termination of Keephills 3 coal rights contract			0
Taxes, other than income taxes		2	3	3
Termination of Sundance B and CPPAs			0	0
Net other operating expense (income)		0	0	0
Operating income		75	76	79
Equity income from associate		0
Finance lease income		0	0	0
Wind and Solar | Operating segments
Disclosure of operating segments [line items]
Revenues		332	312	282
Fuel, carbon compliance and purchased power		25	16	17
Gross margin		307	296	265
Operations, maintenance and administration		53	50	50
Depreciation and amortization		136	124	110
Asset impairment		0	0	12
Gain on termination of Keephills 3 coal rights contract			0
Taxes, other than income taxes		8	8	8
Termination of Sundance B and CPPAs			0	0
Net other operating expense (income)		0	(10)	(6)
Operating income		110	124	91
Equity income from associate		0
Finance lease income		0	0	0
North American Gas | Operating segments
Disclosure of operating segments [line items]
Revenues		217	209	232
Fuel, carbon compliance and purchased power		66	74	96
Gross margin		151	135	136
Operations, maintenance and administration		49	44	48
Depreciation and amortization		46	41	43
Asset impairment		0	0	0
Gain on termination of Keephills 3 coal rights contract			0
Taxes, other than income taxes		2	1	1
Termination of Sundance B and CPPAs			0	0
Net other operating expense (income)		0	(1)	0
Operating income		54	50	44
Equity income from associate		0
Finance lease income		5	6	8
Australian Gas | Operating segments
Disclosure of operating segments [line items]
Revenues		158	160	165
Fuel, carbon compliance and purchased power		10	9	8
Gross margin		148	151	157
Operations, maintenance and administration		32	37	37
Depreciation and amortization		43	48	49
Asset impairment		0	0	0
Gain on termination of Keephills 3 coal rights contract			0
Taxes, other than income taxes		0	0	0
Termination of Sundance B and CPPAs			0	0
Net other operating expense (income)		0	0	0
Operating income		73	66	71
Equity income from associate		0
Finance lease income		2	0	0
Alberta Thermal | Operating segments
Disclosure of operating segments [line items]
Revenues		619	816	912
Fuel, carbon compliance and purchased power		573	570	666
Gross margin		46	246	246
Operations, maintenance and administration		131	138	171
Depreciation and amortization		270	233	241
Asset impairment		75	15	38
Gain on termination of Keephills 3 coal rights contract			88
Taxes, other than income taxes		15	13	13
Termination of Sundance B and CPPAs			56	157
Net other operating expense (income)		(11)	(40)	(41)
Operating income		(434)	31	(19)
Equity income from associate		0
Finance lease income		0	0	0
Centralia | Operating segments
Disclosure of operating segments [line items]
Revenues		497	571	442
Fuel, carbon compliance and purchased power		279	416	314
Gross margin		218	155	128
Operations, maintenance and administration		60	67	61
Depreciation and amortization		105	83	74
Asset impairment		7	(10)	0
Gain on termination of Keephills 3 coal rights contract			0
Taxes, other than income taxes		5	3	5
Termination of Sundance B and CPPAs			0	0
Net other operating expense (income)		0	0	0
Operating income		41	12	(12)
Equity income from associate		0
Finance lease income		0	0	0
Energy Marketing | Operating segments
Disclosure of operating segments [line items]
Revenues		122	129	67
Fuel, carbon compliance and purchased power		0	0	0
Gross margin		122	129	67
Operations, maintenance and administration		30	30	24
Depreciation and amortization		2	2	2
Asset impairment		0	0	0
Gain on termination of Keephills 3 coal rights contract			0
Taxes, other than income taxes		0	0	0
Termination of Sundance B and CPPAs			0	0
Net other operating expense (income)		0	0	0
Operating income		90	97	41
Equity income from associate		0
Finance lease income		0	0	0
Corporate | Operating segments
Disclosure of operating segments [line items]
Revenues		7	(6)	(7)
Fuel, carbon compliance and purchased power		7	(6)	(7)
Gross margin		0	0	0
Operations, maintenance and administration		80	73	86
Depreciation and amortization		25	27	25
Asset impairment		0	18	23
Gain on termination of Keephills 3 coal rights contract			0
Taxes, other than income taxes		1	1	1
Termination of Sundance B and CPPAs			0	0
Net other operating expense (income)		0	2	0
Operating income		(106)	(121)	(135)
Equity income from associate		0
Finance lease income		$ 0	$ 0	$ 0

Segments Disclosures - Selected

Segments Disclosures - Selected Consolidated Statements of Financial Position Information (Details) - CAD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of operating segments [line items]
PP&E	$ 5,822	$ 6,207	$ 6,164
Right-of-use assets	141	146	52
Intangible assets	313	318	$ 373
Goodwill	463	464
Wind and Solar
Disclosure of operating segments [line items]
Goodwill	175	176
Energy Marketing
Disclosure of operating segments [line items]
Goodwill	30	30
Corporate
Disclosure of operating segments [line items]
PP&E	16	17
Right-of-use assets	22	12
Intangible assets	41	45
Goodwill	0	0
Operating segments | Hydro
Disclosure of operating segments [line items]
PP&E	467	469
Right-of-use assets	6	6
Intangible assets	4	5
Goodwill	258	258
Operating segments | Wind and Solar
Disclosure of operating segments [line items]
PP&E	2,005	1,947
Right-of-use assets	55	56
Intangible assets	159	173
Goodwill	175	176
Operating segments | North American Gas
Disclosure of operating segments [line items]
PP&E	382	392
Right-of-use assets	1	0
Intangible assets	32	2
Goodwill	0	0
Operating segments | Australian Gas
Disclosure of operating segments [line items]
PP&E	421	489
Right-of-use assets	4	4
Intangible assets	34	37
Goodwill	0	0
Operating segments | Alberta Thermal
Disclosure of operating segments [line items]
PP&E	2,271	2,540
Right-of-use assets	53	68
Intangible assets	31	41
Goodwill	0	0
Operating segments | Centralia
Disclosure of operating segments [line items]
PP&E	260	352
Right-of-use assets	0	0
Intangible assets	5	6
Goodwill	0	0
Operating segments | Energy Marketing
Disclosure of operating segments [line items]
PP&E	0	1
Right-of-use assets	0	0
Intangible assets	7	9
Goodwill	$ 30	$ 30

Segments Disclosures - Additi_2

Segments Disclosures - Additions to non-current assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	$ 486	$ 417	$ 277
Purchase of intangible assets	14	14	20
Corporate
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	13	1	2
Purchase of intangible assets	13	12	17
Operating segments | Hydro
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	22	23	16
Purchase of intangible assets	0	0	0
Operating segments | Wind and Solar
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	174	229	117
Purchase of intangible assets	0	0	0
Operating segments | North American Gas
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	39	36	21
Purchase of intangible assets	0	0	0
Operating segments | Australian Gas
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	10	6	6
Purchase of intangible assets	0	0	0
Operating segments | Alberta Thermal
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	200	114	101
Purchase of intangible assets	1	2	3
Operating segments | Centralia
Disclosure of operating segments [line items]
Property, plant and equipment expenditures	28	8	14
Purchase of intangible assets	0	0	0
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of operating segments [line items]
Depreciation and amortization	$ 654	$ 590	$ 574
Mine depreciation	144	119	136
Depreciation and amortization on the Consolidated Statements of Cash Flows	$ 798	$ 709	$ 710

Segments Disclosures - Geograph

Segments Disclosures - Geographic Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure of geographical areas [line items]
Revenues	$ 2,101	$ 2,347	$ 2,249
PP&E	5,822	6,207	6,164
Right-of-use assets	141	146	52
Intangible assets	313	318	373
Other assets	206	198
Goodwill	463	464
Canada
Disclosure of geographical areas [line items]
Revenues	1,227	1,460	1,573
PP&E	4,661	4,854
Right-of-use assets	107	109
Intangible assets	185	213
Other assets	74	75
Goodwill	418	418
US
Disclosure of geographical areas [line items]
Revenues	716	727	511
PP&E	737	863
Right-of-use assets	30	33
Intangible assets	94	68
Other assets	61	47
Goodwill	45	46
Australia
Disclosure of geographical areas [line items]
Revenues	158	160	$ 165
PP&E	424	490
Right-of-use assets	4	4
Intangible assets	34	37
Other assets	71	76
Goodwill	$ 0	$ 0