TransAlta (TAC) 40-F 4 Mar 20 2019 FY Annual report (Canada) Financial data

Document and Entity Information

Document and Entity Information Document	12 Months Ended
	Dec. 31, 2019shares
Document And Entity Information [Abstract]
Document Type	40-F
Document Period End Date	Dec. 31, 2019
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	2019
Document Fiscal Period Focus	FY
Entity Common Shares Outstanding	277,265,641
Entity Emerging Growth Company	false

Consolidated Statements of Earn

Consolidated Statements of Earnings (Loss) Statement - CAD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Profit or loss [abstract]
Revenues (Note 5)	$ 2,347	$ 2,249	$ 2,307
Fuel and purchased power (Note 6)	1,086	1,100	1,016
Gross margin	1,261	1,149	1,291
Operations, maintenance and administration (Note 6)	475	515	517
Depreciation and amortization	590	574	635
Asset impairment charges (reversals) (Note 7)	25	73	20
Gain on termination of Keephills 3 coal rights contract	(88)	0	0
Taxes, other than income taxes	29	31	30
Termination of Sundance B and C PPAs	(56)	(157)	0
Net other operating expense (income) (Note 9)	(49)	(47)	(49)
Operating income	335	160	138
Finance lease income	6	8	54
Net interest expense (Note 10)	(179)	(250)	(247)
Foreign exchange loss	(15)	(15)	(1)
Gain on sale of assets and other (Note 4(D) and 17)	46	1	2
Earnings (loss) before income taxes	193	(96)	(54)
Income tax expense (recovery)	17	(6)	64
Net earnings (loss)	176	(90)	(118)
Net earnings (loss) attributable to:
TransAlta shareholders	82	(198)	(160)
Non-controlling interests (Note 12)	94	108	42
Preferred share dividends (Note 25)	30	50	30
Net earnings (loss) attributable to common shareholders	$ 52	$ (248)	$ (190)
Weighted average number of common shares outstanding in the year (millions)	283	287	288
Net earnings (loss) per share attributable to common shareholders, basic and diluted (Note 24)	$ 0.18	$ (0.86)	$ (0.66)

Consolidated Statement of Cash

Consolidated Statement of Cash Flows Statement - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Net earnings (loss)	$ 176	$ (90)	$ (118)
Depreciation and amortization (Note 34)	709	710	708
Gain (loss) on sale of assets (Note 4)	(45)	0	(1)
Accretion of provisions (Note 21)	23	24	23
Decommissioning and restoration costs settled (Note 21)	(34)	(31)	(19)
Deferred income tax expense (recovery) (Note 11)	(18)	(34)	(15)
Unrealized (gain) loss from risk management activities	(32)	30	(48)
Unrealized foreign exchange loss	13	28	22
Provisions	13	7	(7)
Asset impairment charges (reversals) (Note 7)	25	73	20
Other non-cash items	(102)	147	175
Cash flow from operations before changes in working capital	728	864	740
Change in non-cash operating working capital balances (Note 30)	121	(44)	(114)
Cash flow from operating activities	849	820	626
Investing activities
Additions to property, plant and equipment (Note 17 and 34)	(417)	(277)	(338)
Additions to intangibles (Note 19 and 34)	(14)	(20)	(51)
Restricted cash (Note 22)	34	(35)	(30)
Loan receivable (Note 20)	(10)	1	(38)
Acquisition of renewable energy facilities, net of cash acquired (Note 4)	(117)	(30)	0
Investment in the Pioneer Pipeline	(83)	(15)	0
Proceeds on sale of property, plant and equipment	13	2	3
Proceeds on sale of Wintering Hills facility and Solomon disposition (Note 4)	0	2	478
Income tax expense on Solomon disposition (Note 4 and 11)	0	0	(56)
Realized gains on financial instruments	3	2	6
Decrease in finance lease receivable	24	59	59
Other	23	13	(3)
Change in non-cash investing working capital balances	32	(96)	57
Cash flow from (used in) investing activities	(512)	(394)	87
Financing activities
Net increase (decrease) in borrowings under credit facilities (Note 22)	(119)	312	26
Repayment of long-term debt (Note 22)	(96)	(1,179)	(814)
Issuance of long-term debt (Note 22)	166	345	260
Issuance of exchangeable securities	350	0	0
Net proceeds on sale of non-controlling interest in subsidiary (Note 4)	0	144	0
Repurchase of common shares under NCIB (Note 24)	(68)	(23)	0
Realized gains on financial instruments	0	48	106
Distributions paid to subsidiaries' non-controlling interests (Note 12)	(106)	(165)	(172)
Decrease in finance lease obligations (Note 22)	(21)	(18)	(17)
Financing fees and other	(35)	(31)	(6)
Change in non-cash financing working capital balances	0	2	0
Cash flow used in financing activities	(14)	(651)	(703)
Cash flow from (used in) operating, investing, and financing activities	323	(225)	10
Effect of translation on foreign currency cash	(1)	0	(1)
Increase (decrease) in cash and cash equivalents	322	(225)	9
Cash and cash equivalents, beginning of year	89	314	305
Cash and cash equivalents, end of year	411	89	314
Cash income taxes paid	35	87	14
Cash interest paid	185	188	230
Purchase of other long-term assets, classified as investing activities	83	15	0
Common shares
Financing activities
Dividends paid, classified as financing activities	(45)	(46)	(46)
Preferred shares
Financing activities
Dividends paid, classified as financing activities	$ (40)	$ (40)	$ (40)

Trade and Other Receivables (No

Trade and Other Receivables (Notes)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Trade and Other Receivables	Trade and Other Receivables As at Dec. 31 2019 2018 Trade accounts receivable 399 597 Promissory note receivable (1) — 25 Collateral paid (Note 15) 42 105 Current portion of finance lease receivables (Note 8) 15 24 Income taxes receivables 6 5 Trade and other receivables 462 756 (1) The promissory note receivable relates to funding provided for the Antrim wind project in 2018. Refer to Note 4(J) for further details.

Inventory (Notes)

Inventory (Notes)	12 Months Ended
	Dec. 31, 2019
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. The components of inventory are as follows: As at Dec. 31 2019 2018 Parts and materials 108 113 Coal 130 108 Deferred stripping costs 6 7 Natural gas 3 4 Purchased emission credits 4 10 Total 251 242 The change in inventory is as follows: Balance, Dec. 31, 2017 219 Net addition 20 Change in foreign exchange rates 3 Balance, Dec. 31, 2018 242 Net addition 12 Change in foreign exchange rates (3) Balance, Dec. 31, 2019 251 No inventory is pledged as security for liabilities.

Joint Arrangements (Notes)

Joint Arrangements (Notes)	12 Months Ended
	Dec. 31, 2019
Disclosure of interests in other entities [Abstract]
Joint arrangements	Joint Arrangements Joint arrangements at Dec. 31, 2019, included the following: Joint operations Segment Ownership (per cent) Description Sheerness Coal 50 Coal-fired plant 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 Coal 50 Natural gas pipeline in Alberta operated by Tidewater Goldfields Power Gas 50 Gas-fired plant in Australia operated by TransAlta Fort Saskatchewan Gas 60 Cogeneration plant in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta Fortescue River Gas 43 Natural gas pipeline in Western Australia, operated by DBP Development Group McBride Lake Wind 50 Wind generation facility in Alberta operated by TransAlta Soderglen Wind 50 Wind generation facility in Alberta operated by TransAlta Pingston Hydro 50 Hydro facility in British Columbia operated by TransAlta

Related Party Transactions (Not

Related Party Transactions (Notes)	12 Months Ended
	Dec. 31, 2019
Related Party [Abstract]
Related Party Transactions	Related-Party Transactions Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2019, 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 Canada 60.4 Generation and sale of electricity Transactions between the Corporation and its subsidiaries have been eliminated on consolidation and are not disclosed. 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 2019 2018 2017 Total compensation 30 17 24 Comprised of: Short-term employee benefits 13 11 14 Post-employment benefits 2 2 2 Termination benefits 2 — — Share-based payments 13 4 8

Trade and Other Receivables (Ta

Trade and Other Receivables (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Trade and Other Receivables	As at Dec. 31 2019 2018 Trade accounts receivable 399 597 Promissory note receivable (1) — 25 Collateral paid (Note 15) 42 105 Current portion of finance lease receivables (Note 8) 15 24 Income taxes receivables 6 5 Trade and other receivables 462 756 (1) The promissory note receivable relates to funding provided for the Antrim wind project in 2018. Refer to Note 4(J) for further details.

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of inventories [Abstract]
Disclosure Of The Components Of Inventories	The components of inventory are as follows: As at Dec. 31 2019 2018 Parts and materials 108 113 Coal 130 108 Deferred stripping costs 6 7 Natural gas 3 4 Purchased emission credits 4 10 Total 251 242
Disclosure Of The Change In Inventory	The change in inventory is as follows: Balance, Dec. 31, 2017 219 Net addition 20 Change in foreign exchange rates 3 Balance, Dec. 31, 2018 242 Net addition 12 Change in foreign exchange rates (3) Balance, Dec. 31, 2019 251

Joint Arrangements (Tables)

Joint Arrangements (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of interests in other entities [Abstract]
Disclosure of interests in joint arrangements	Joint arrangements at Dec. 31, 2019, included the following: Joint operations Segment Ownership (per cent) Description Sheerness Coal 50 Coal-fired plant 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 Coal 50 Natural gas pipeline in Alberta operated by Tidewater Goldfields Power Gas 50 Gas-fired plant in Australia operated by TransAlta Fort Saskatchewan Gas 60 Cogeneration plant in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta Fortescue River Gas 43 Natural gas pipeline in Western Australia, operated by DBP Development Group McBride Lake Wind 50 Wind generation facility in Alberta operated by TransAlta Soderglen Wind 50 Wind generation facility in Alberta operated by TransAlta Pingston Hydro 50 Hydro facility in British Columbia operated by TransAlta

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party [Abstract]
Disclosure of interests in subsidiaries	Year ended Dec. 31 2019 2018 2017 Revenues 446 462 459 Net earnings 183 241 13 Total comprehensive income 138 281 (24) Amounts attributable to the non-controlling interests: Net earnings 73 94 11 Total comprehensive income 56 110 — Distributions paid to non-controlling interests 69 79 85 As at Dec. 31 2019 2018 Current assets 293 250 Long-term assets 3,409 3,497 Current liabilities (152) (159) Long-term liabilities (1,237) (1,192) Total equity (2,313) (2,396) Equity attributable to non-controlling interests (941) (961) Non-controlling interests’ share (per cent) 39.6 39.1 B. TA Cogen Year ended Dec. 31 2019 2018 2017 Results of operations Revenues 181 185 175 Net earnings 43 29 61 Total comprehensive income 43 29 61 Amounts attributable to the non-controlling interest: Net earnings 21 14 31 Total comprehensive income 21 14 31 Distributions paid to Canadian Power Holdings Inc. 37 86 87 As at Dec. 31 2019 2018 Current assets 41 82 Long-term assets 328 354 Current liabilities (27) (54) Long-term liabilities (19) (28) Total equity (323) (354) Equity attributable to Canadian Power Holdings Inc. (160) (176) Non-controlling interest share (per cent) 49.99 49.99 Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2019, 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 Canada 60.4 Generation and sale of 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 2019 2018 2017 Total compensation 30 17 24 Comprised of: Short-term employee benefits 13 11 14 Post-employment benefits 2 2 2 Termination benefits 2 — — Share-based payments 13 4 8

Trade and Other Receivables (De

Trade and Other Receivables (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Trade accounts receivable	$ 399	$ 597
Promissory note receivable	0	25
Collateral paid (Note 15)	42	105
Current portion of finance lease receivables (Note 8)	15	24
Income taxes receivables	6	5
Trade and other receivables	$ 462	$ 756

Inventory Components of Invento

Inventory Components of Inventory (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of inventories [Abstract]
Parts and materials	$ 108	$ 113
Coal	130	108
Deferred stripping costs	6	7
Natural gas	3	4
Purchased emission credits	4	10
Inventories	$ 251	$ 242	$ 219

Inventory Change in Inventory (

Inventory Change in Inventory (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of inventories [Abstract]
Inventories at the beginning of the period	$ 242	$ 219
Net addition		20
Change in foreign exchange rates	(3)	3
Net addition	12
Inventories at the end of the period	$ 251	$ 242

Joint Arrangements (Details)

Joint Arrangements (Details)	12 Months Ended
	Dec. 31, 2019
Sheerness | Coal generation
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Genesee Unit 3 | Coal generation
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Goldfields Power | Gas generation
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Fort Saskatchewan | Gas generation
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	60.00%
Fortescue River Gas Pipeline | Gas generation
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	43.00%
McBride Lake | Wind Generation
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Soderglen | Wind Generation
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%
Pingston | Hydro
Disclosure of joint operations [line items]
Proportion of ownership interest in joint operation	50.00%

Capital Disclosure of investmen

Capital Disclosure of investment grade credit rating (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Investment [Line Items]
Comparable funds from operations to adjusted interest coverage, actual	4.5	4.8
Adjusted comparable funds from operations to adjusted net debt, actual	19.00%	20.80%
Adjusted net debt to comparable earnings before interest, taxes, depreciation, and amortization, actual	3.9	3.6
Percentage of dividends added to Comparable FFO before Interest to Adjusted Interest Coverage	50.00%
Percentage of preferred dividends deducted from Adjusted Comparable FFO to Adjusted Net Debt	50.00%
Percentage of preferred shares added to net debt in Adjusted Comparable FFO to Adjusted Net Debt	50.00%
Minimum
Investment [Line Items]
Comparable funds from operations to adjusted interest coverage, Target	4
Adjusted comparable funds from operations to adjusted net debt, Target	20
Adjusted net debt to comparable earnings before interest, taxes, depreciation, and amortization, Target	3
Maximum
Investment [Line Items]
Comparable funds from operations to adjusted interest coverage, Target	5
Adjusted comparable funds from operations to adjusted net debt, Target	25
Adjusted net debt to comparable earnings before interest, taxes, depreciation, and amortization, Target	3.5

Related Party Transactions Disc

Related Party Transactions Disclosure of interests in subsidiaries (Details)	1 Months Ended		3 Months Ended				4 Months Ended	11 Months Ended	12 Months Ended	19 Months Ended
	Dec. 31, 2018	Jul. 30, 2018	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Nov. 29, 2018	Jun. 21, 2018	Dec. 31, 2019	Jul. 31, 2017
TransAlta Renewables
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)	60.90%	61.10%	60.40%	60.50%	60.60%	60.80%	61.00%	64.00%		64.00%
Canada | TransAlta Generation Partnership [Member]
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 [Member]
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)									100.00%
UNITED STATES | TransAlta Centralia Generation, LLC [Member]
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)									100.00%
UNITED STATES | TransAlta Energy Marketing (U.S.), Inc [Member]
Disclosure of subsidiaries [line items]
Ownership interest (as a percent)									100.00%
Australia | TransAlta Energy (Australia). Ptv Ltd [Member]
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, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party [Abstract]
Total compensation	$ 30	$ 17	$ 24
Short-term employee benefits	13	11	14
Post-employment benefits	2	2	2
Termination benefits	2	0	0
Share-based payments	$ 13	$ 4	$ 8

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) Statement - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of comprehensive income [abstract]
Net earnings (loss)		$ 176	$ (90)	$ (118)
Other comprehensive income (loss)
Net actuarial gains (losses) on defined benefit plans, net of tax	[1]	(26)	15	(6)
Gains (losses) on derivatives designated as cash flow hedges, net of tax		0	0	(1)
Total items that will not be reclassified subsequently to net earnings		(26)	15	(7)
Gains (losses) on translating net assets of foreign operations,net of tax		(59)	84	(80)
Reclassification of translation gains on net assets of divested foreign operations	[2]	0	0	(9)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax	[3]	21	(41)	50
Reclassification of losses on financial instruments designated as hedges of divested foreign operations, net of tax	[4]	0	0	14
Gains (losses) on derivatives designated as cash flow hedges, net of tax	[5]	61	(8)	214
Reclassification of gains on derivatives designated as cash flow hedges to net earnings, net of tax	[6]	(42)	(46)	(107)
Total items that will be reclassified subsequently to net earnings		(19)	(11)	82
Other comprehensive income (loss)		(45)	4	75
Total comprehensive income (loss)		131	(86)	(43)
Total comprehensive income (loss) attributable to:
TransAlta shareholders		54	(210)	(74)
Non-controlling interests		77	124	31
Net actuarial gains (losses)		(7)	5	(4)
Income tax relating to actuarial gains (losses) arising from changes in financial assumptions of other comprehensive income		0	0	11
Income tax relating to hedges of net investments in foreign operations of other comprehensive income		0	0	2
Income tax recovery relating to reclassification of losses on financial instruments designed as hedges of divested foreign operations		0	0	2
Income tax expense (recovery) relating to gains on derivatives designated as cash flow hedges of other comprehensive income		(16)	(1)	(77)
Income tax expense relating to reclassification of gains on derivatives designated as cash flow hedges to net earnings		$ (10)	$ 11	$ 31
[1]	(1) Net of income tax recovery of $7 million for the year ended Dec. 31, 2019 (2018 - $5 million expense, 2017 - $(4) million recovery).
[2]	(2) Net of reclassification of income tax of nil for the year ended Dec. 31, 2019 (2018 - nil, 2017 - $11 million expense).
[3]	(3) Net of income tax expense of nil for the year ended Dec. 31, 2019 (2018 - nil, 2017 - $2 million expense).
[4]	(4) Net of reclassification of income tax of nil for the year ended Dec. 31, 2019 (2018 - nil, 2017 - $2 million recovery).
[5]	(5) Net of income tax expense of $16 million for the year ended Dec. 31, 2019 (2018 - $1 million recovery, 2017 - $77 million recovery).
[6]	(6) Net of reclassification of income tax expense of $10 million for the year ended Dec. 31, 2019 (2018 - $11 million expense,  2017 - $31 million expense).

Consolidated Statements of Fina

Consolidated Statements of Financial Position Statement - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Assets [abstract]
Cash and cash equivalents	$ 411	$ 89
Restricted cash	32	66
Trade and other receivables	462	756
Prepaid expenses	19	13
Risk management assets	166	146
Inventory	251	242
Current assets	1,341	1,312
Long-term portion of finance lease receivable	176	191
Risk management assets	640	662
Property, plant and equipment	6,207	6,164
Right-of-use assets	146	0
Intangible assets	318	373
Goodwill	464	464
Deferred income tax assets	18	28
Other assets	198	234
Total assets	9,508	9,428
Liabilities [abstract]
Accounts payable and accrued liabilities	413	496
Current portion of decommissioning and other provisions (Note 21)	58	70
Risk management liabilities (Note 14 and 15)	81	90
Current contract liabilities	1	8
Income taxes payable	14	10
Dividends payable (Note 24 and 25)	37	58
Current portion of long-term debt and finance lease obligations (Note 22)	513	148
Current liabilities	1,117	880
Credit facilities, long-term debt, and finance lease obligations (Note 22)	2,699	3,119
Exchangeable securities	326	0
Decommissioning and other provisions (Note 21)	488	386
Deferred income tax liabilities (Note 11)	472	501
Risk management liabilities (Note 14 and 15)	29	41
Contract liabilities (Note 5)	14	80
Defined benefit obligation and other long-term liabilities (Note 23)	301	287
Equity
Contributed surplus	42	11
Deficit	(1,455)	(1,496)
Accumulated other comprehensive income (Note 26)	454	481
Equity attributable to shareholders	2,961	2,997
Non-controlling interests (Note 12)	1,101	1,137
Total equity	4,062	4,134
Total liabilities and equity	9,508	9,428
Gross carrying amount
Assets [abstract]
Property, plant and equipment	13,395	13,202
Intangible assets	788	807
Liabilities [abstract]
Accounts payable and accrued liabilities	413
Dividends payable (Note 24 and 25)	37
Exchangeable securities	350
Accumulated depreciation
Assets [abstract]
Property, plant and equipment	(7,188)	(7,038)
Intangible assets	470	434
Common shares
Equity
Issued capital (Note 24)	2,978	3,059
Preferred shares
Equity
Issued capital (Note 24)	$ 942	$ 942

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity Statement - 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		Attributable to shareholders	Attributable to shareholdersCommon shares	Attributable to shareholdersPreferred shares	Attributable to non-controlling interests
Changes in equity [abstract]
Impact of change in accounting policy (Note 3)	$ (13)						$ (14)					$ (14)			$ 1
Adjusted beginning balance	4,372			$ 3,094	$ 942	$ 10	(1,223)			$ 489		3,312			1,060
Balance, beginning of year at Dec. 31, 2017	4,385			3,094	942	10	(1,209)			489	[1]	3,326			1,059
Changes in equity [abstract]
Net earnings (loss)	(90)						(198)					(198)			108
Other comprehensive income (loss)
Net gains on translating net assets of foreign operations, net of hedges and of tax	43									43	[1]	43
Net losses on derivatives designated as cash flow hedges, net of tax	(54)									(54)	[1]	(54)			0
Net actuarial gains on defined benefits plans, net of tax	15									15	[1]	15
Intercompany FVOCI investments	0									(16)	[1]	(16)			16
Total comprehensive income (loss)	(86)						(198)			(12)	[1]	(210)			124
Share dividends (Note 24)	(50)	$ (57)	$ (50)					$ (57)	$ (50)				$ (57)	$ (50)
Changes in non-controlling interests in TransAlta Renewables (Note 4(N) and 12)	157						20			4	[1]	24			133
Effect of share-based payment plans (Note 29)	1					1						1
Shares purchased under NCIB	(23)			(35)			12					(23)
Distributions paid, and payable, to non-controlling interests	(180)														(180)
Balance, end of year at Dec. 31, 2018	4,134			3,059	942	11	(1,496)			481	[1]	2,997			1,137
Changes in equity [abstract]
Impact of change in accounting policy (Note 3)	3						3					3			0
Adjusted beginning balance	4,137			3,059	942	11	(1,493)			481		3,000			1,137
Net earnings (loss)	176						82					82			94
Other comprehensive income (loss)
Net gains on translating net assets of foreign operations, net of hedges and of tax	(38)									(38)	[1]	(38)
Net losses on derivatives designated as cash flow hedges, net of tax	19									19	[1]	19
Net actuarial gains on defined benefits plans, net of tax	(26)									(26)	[1]	(26)
Intercompany FVOCI investments	0											17			(17)
Total comprehensive income (loss)	131						82			(28)	[1]	54			77
Share dividends (Note 24)	(30)	$ (34)	$ (30)					$ (34)	$ (30)				$ (34)	$ (30)
Changes in non-controlling interests in TransAlta Renewables (Note 4(N) and 12)	28						5			1	[1]	6			22
Effect of share-based payment plans (Note 29)	33			2		31						33
Shares purchased under NCIB	(68)			(83)			15					(68)
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	[1]	$ 2,961			$ 1,101
[1]	(1) Refer to Note 28 for details on components of, and changes in, accumulated other comprehensive income (loss).

Corporate Information (Notes)

Corporate Information (Notes)	12 Months Ended
	Dec. 31, 2019
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: Canadian Coal, US Coal, Canadian Gas, Australian Gas, Wind and Solar, and Hydro. 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. 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 Canadian Coal 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 The Corporate segment includes the Corporation’s central financial, legal, administrative, corporate development and investor relation functions. Activities and charges directly or reasonably attributable to other segments are allocated thereto. 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 Mar. 3, 2020. 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 (Notes)	12 Months Ended
	Dec. 31, 2019
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 - 2019 and 2018 Policy The Corporation adopted IFRS 15 Revenue from Contracts with Customers (IFRS 15) with an initial adoption date of Jan. 1, 2018. The Corporation elected to adopt IFRS 15 retrospectively with the modified retrospective method of transition practical expedient and elected to apply IFRS 15 only to contracts that are active at the date of initial adoption. Comparative information has not been restated and is reported under IAS 18 Revenue (IAS 18). Refer to section III below for the accounting policy for years prior to 2018. 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 which 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 standalone 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. III. Revenue Recognition Policy Prior to 2018 The majority of the Corporation’s revenues are derived from the sale of physical power, the leasing of power facilities and from energy marketing and trading activities. Revenues are measured at the fair value of the consideration received or receivable. Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components: fixed capacity payments for availability, energy payments for generation of electricity, incentives or penalties for exceeding or not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary services. Each component is recognized when: i) output, delivery or satisfaction of specific targets is achieved, all as governed by contractual terms; ii) the amount of revenue can be measured reliably; iii) it is probable that the economic benefits will flow to the Corporation; and iv) the costs incurred or to be incurred in respect of the transaction can be measured reliably. Revenue from the rendering of services is recognized when criteria ii), iii) and iv) above are met and when the stage of completion of the transaction at the end of the reporting period can be measured reliably. Revenues from non-contracted capacity are comprised of energy payments, at market prices, for each megawatt hour (“MWh”) produced, and are recognized upon delivery. 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. 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 Effective Jan. 1, 2018, the Corporation adopted IFRS 9 Financial Instruments ("IFRS 9"). In accordance with the transition provisions of the standard, the Corporation elected to not restate prior periods. Refer to section III below for information on its prior accounting policy. The Corporation's accounting policies under IFRS 9 are outlined below. 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 "passthrough" 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. III. Financial Instruments and Hedges Accounting Policy Prior to 2018 Financial Instruments Financial assets and financial liabilities, including derivatives and certain non-financial derivatives, are recognized on the Consolidated Statements of Financial Position when the Corporation becomes a party to the contract. All financial instruments, except for certain non-financial derivative contracts that meet the Corporation’s own use requirements, are measured at fair value upon initial recognition. Measurement in subsequent periods depends on whether the financial instrument has been classified as: at fair value through profit or loss, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities. Classification of the financial instrument is determined at inception depending on the nature and purpose of the financial instrument. Financial assets and financial liabilities classified or designated as at fair value through profit or loss are measured at fair value with changes in fair values recognized in net earnings. Financial assets classified as either held-to-maturity or as loans and receivables, and other financial liabilities, are measured at amortized cost using the effective interest method of amortization. Other financial assets are those non-derivative financial assets that are designated as such or that have not been classified as another type of financial asset, and are measured at fair value through OCI. Other financial assets are measured at cost if fair value is not reliably measurable. Financial assets are assessed for impairment on an ongoing basis and at reporting dates. An impairment may exist if an incurred loss event has arisen that has an impact on the recoverability of the financial asset. Factors that may indicate an incurred loss event and related impairment may exist include, for example, if a debtor is experiencing significant financial difficulty, or a debtor has entered or it is probable that they will enter, bankruptcy or other financial reorganization. The carrying amount of financial assets, such as receivables, is reduced for impairment losses through the use of an allowance account, and the loss is recognized in net earnings. 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 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. Derivative instruments that are embedded in financial or non-financial contracts that are not already required to be recognized at fair value are treated and recognized as separate derivatives if their risks and characteristics are not closely related to their host contracts and the contract is not measured at fair value. Changes in the fair values of these and other derivative instruments are recognized in net earnings with the exception of the effective portion of i) derivatives designated as cash flow hedges and ii) hedges of foreign currency exposure of a net investment in a foreign operation, each of which is recognized in OCI. Transaction costs are expensed as incurred for financial instruments classified or designated as at fair value through profit or loss. 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. 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 hedging relationship qualifies for hedge accounting if, at inception, it is formally designated and documented as a hedge, and the hedge is expected to be highly effective at inception and on an ongoing basis. 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 accounted for on the Consolidated Statements of Financial Position at fair value, 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. Hedge effectiveness for fair value hedges is achieved if changes in the fair value of the derivative are highly effective at offsetting changes in the fair value of the item hedged. If hedge accounting is discontinued, the carrying amount of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying amount of the hedged item are amortized to net earnings over the remaining term of the original hedging relationship. The Corporation primarily uses interest rate swaps as fair value hedges to manage the ratio of floating rate versus fixed rate debt. Interest rate swaps require the periodic exchange of payments without the exchange of the notional principal amount on which the payments are based. Interest expense on the debt is adjusted to include the payments made or received under the interest rate swaps. 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. Hedge effectiveness is achieved if the derivative’s cash flows are highly effective at offsetting the cash flows of the hedged item and the timing of the cash flows is similar. All components of each derivative’s change in fair value are included in the assessment of cash flow hedge effectiveness. If hedge accounting is discontinued, the amounts previously recognized in AOCI are reclassified to net earnings during the periods when the variability in the cash flows of the hedged item affects net earnings. Gains and losses on derivatives are reclassified to net earnings from AOCI immediately when the forecasted transaction is no longer expected to occur within the time period specified in the hedge documentation. The Corporation primarily uses physical and financial swaps, forward sales contracts, futures contracts and options as cash flow hedges to hedge the Corporation’s exposure to fluctuations in electricity and natural gas prices. If hedging criteria are met, the fair values of the hedges are recorded in risk management assets or liabilities with changes in value being reported in OCI. Gains and losses on these derivatives are recognized, on settlement, in net earnings in the same period and financial statement caption as the hedged exposure. The Corporation also uses foreign currency forward contracts as cash flow hedges to hedge the foreign exchange exposures resulting from highly probable forecasted project-related costs denominated in foreign currencies. If the hedging criteria are met, changes in fair value are reported in OCI with the fair value being reported in risk management assets or liabilities, as appropriate. Upon settlement of the derivative, any gain or loss on the forward contracts is included in the cost of the asset acquired or liability incurred. The Corporation uses forward starting interest rate swaps as cash flow hedges to hedge exposures to anticipated changes in interest rates for forecasted issuances of debt. If the hedging criteria are met, changes in fair value are reported in OCI with the fair value being reported in risk management assets or liabilities, as appropriate. When the swaps are closed out on issuance of the debt, the resulting gains or losses recorded in AOCI are amortized to net earnings over the term of the swap. If no debt is issued, the gains or losses are recognized in net earnings immediately. 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. The Corporation primarily uses foreign currency forward contracts and foreign-denominated debt to hedge exposure to changes in the carrying values of the Corporation’s net investments in foreign operations that result from changes in foreign exchange rates. D. Cash and Cash Equivalents Cash and cash equi

Accounting Changes (Notes)

Accounting Changes (Notes)	12 Months Ended
	Dec. 31, 2018
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Accounting Changes	Accounting Changes A. Current Accounting Changes I. IFRS 16 Leases The Corporation adopted IFRS 16 with an initial adoption date of Jan. 1, 2019. IFRS 16 sets out the principles for the recognition, measurement, presentation and disclosure of leases. The standard provides a single lessee accounting model, requiring lessees to recognize a right of use asset and liabilities for all in-scope leases. Under IFRS 16, a contract contains a lease when the customer obtains the right to control the use of an identified asset for a period of time in exchange for consideration. Previously, the Corporation determined at contract inception whether an arrangement is or contains a lease under IAS 17 Leases ("IAS 17") or International Financial Reporting Interpretations Committee Interpretation 4 Determining Whether an Arrangement Contains a Lease . The Corporation elected to adopt IFRS 16 using the modified retrospective approach on transition. The Corporation applied the definition of a lease and related guidance set out in IFRS 16 to all lease contracts in existence at Dec. 31, 2018. All relevant contractual arrangements outstanding at that date were reviewed to assess if the contract meets the new definition of a lease.Comparative information has not been restated and is reported under IAS 17. Refer to Note 2(Q)(II) for details on the accounting policy in prior years. The Corporation recognized the cumulative impact of the initial application of the standard of $3 million in deficit as at Jan. 1, 2019. In applying IFRS 16 for the first time, the Corporation used the following practical expedients permitted by the standard: ▪ Exemption to not recognize right of use assets and lease liabilities for short-term leases that have a remaining lease term of less than 12 months as at Jan. 1, 2019, and for low value leases; ▪ Excluded initial direct costs from the measurement of the right of use asset at the date of initial application; ▪ Used hindsight to determine the lease term where the contract contained options to extend or terminate the lease; ▪ Adjusted the right of use assets by the amount relating to onerous contract provisions as defined under IAS 37 Provisions, contingent liabilities and contingent assets ("IAS 37") immediately before the date of initial application; and ▪ Measured the right of use asset at an amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments related to that lease that was recognized in the statement of financial position immediately before the date of initial application. Impact on the Financial Statements Lessee The Corporation recognized the cumulative impact of the initial application of the standard by recording a right of use asset based on the corresponding lease liability measured at the present value of the remaining lease payments discounted using the Corporation's incremental borrowing rate (or the rate implicit in the lease) applied to the lease liabilities at Jan. 1, 2019. The weighted average incremental borrowing rate applied to the lease liabilities on Jan. 1, 2019, was 5.71 per cent. The following table reconciles the Corporation's operating lease commitments at Dec. 31, 2018, as previously disclosed in the Corporation’s 2018 annual consolidated financial statements, to the lease obligations recognized on initial application of IFRS 16 and included in credit facilities, long-term debt and lease obligations on the Consolidated Statements of Financial Position as at Jan. 1, 2019: Non-cancellable operating lease commitments disclosed at Dec. 31, 2018 80 Less: Exemption for low-value leases (1) Add: Extension and termination options reasonably certain to be exercised 4 Undiscounted lease liability 83 Discounted using the incremental borrowing rate at Jan. 1, 2019 (31) New lease liabilities recognized as at Jan. 1, 2019 52 Add: 2018 finance lease obligations 63 Less: 2018 finance lease obligations that do not meet the IFRS 16 definition of a lease (32) Lease liabilities as at Jan. 1, 2019 83 The associated right of use assets were measured at an amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments, onerous contract provisions and lease inducements. On Jan. 1, 2019, the Corporation recognized right of use assets of $85 million, including $38 million that was previously included in PP&E, intangible assets and other assets. Applying the IFRS 16 definition of a lease to a contractual arrangement that was accounted for as a finance lease under IAS 17 but is no longer considered a lease under IFRS 16 resulted in the derecognition of a finance lease asset of $29 million and a finance lease liability of $32 million with the net impact of $3 million recorded in deficit. Lessor Several of the Corporation's long-term contracts at certain wind, hydro and solar facilities are no longer considered to be operating leases under IFRS 16. Revenues earned on these contracts are now accounted for applying IFRS 15 Revenue from Contracts with Customers . No significant change in the pattern of revenue recognition arose. The Corporation continues to account for its subleases as operating leases. For further details on the lease policy under IFRS 16, refer to Note 2(Q)(I) and to Note 18 for a summary of the Corporation's leases. II. IFRS 3 Business Combinations Effective Oct. 1, 2019, the Corporation early-adopted amendments to IFRS 3 Business Combinations ("IFRS 3 amendments"), in advance of its mandatory effective date of Jan. 1, 2020. The Corporation adopted the IFRS 3 amendments prospectively and therefore the comparative information presented for 2018 has not been restated. The IFRS 3 amendments are intended to assist entities to determine whether a transaction should be accounted for as a business combination or as an asset acquisition. Specifically, these amendments: ▪ Clarify the minimum requirements for a business, whereby at minimum, an input and a substantive process that together significantly contribute to the ability to create output must be present; ▪ Remove the assessment of whether market participants are capable of replacing any missing elements so that the assessment is based on what has been acquired in its current state and condition, rather than on whether market participants are capable of replacing any missing elements, for example, by integrating the acquired activities and assets; ▪ Add guidance to help entities assess whether an acquired process is substantive, which requires more persuasive evidence when there are no outputs, because the existence of outputs provides some evidence that the acquired set of activities and assets is a business; ▪ Narrow the definition of outputs to focus on goods or services provided to customers, investment income or other income from ordinary activities; and ▪ Introduce an optional fair value concentration test that can be applied on a transaction-by-transaction basis to permit a simplified assessment of whether an acquired set of activities and assets are not a business. The concentration test is met if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets. The Corporation elected to apply the optional fair value concentration test to its acquisition of the remaining 50 per cent interest in Keephills 3 (refer to Note 4(D) for further details). There are no other impacts to the asset acquisitions that were completed during the year ended Dec. 31, 2019. III. IFRIC 23 - Uncertainty over Income Tax Treatments The Corporation adopted IFRIC 23 Uncertainty over Income Tax Treatments on its effective date of Jan. 1, 2019 and applied it retrospectively. No cumulative effect of initially applying the guidance arose. The Interpretation clarifies the application of recognition and measurement requirements in IAS 12 Income Taxes when there is uncertainty over income tax treatments and provides guidance on: considering uncertain tax treatments separately or together; examination by tax authorities; the appropriate method to reflect uncertainty; and accounting for changes in facts and circumstances. IV. Change in Estimates Canadian Coal 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(A), the Corporation adjusted the useful lives of some of its mine assets to align with the Corporation's coal-to-gas conversion plans. In addition, on Jan. 1, 2017, the useful lives of the PP&E and amortizable intangibles associated with some of the Corporation’s Alberta coal assets were reduced to 2030. As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2018, increased by approximately $38 million (2017 - $58 million). The useful lives may be revised or extended in compliance with the Corporation’s accounting policies, dependent upon future operating decisions and events, such as coal-to-gas conversions. Due to the Corporation’s decision to retire Sundance Unit 1 effective Jan. 1, 2018 (refer to Note 7 for further details), the useful lives of the Sundance Unit 1 PP&E and amortizable intangibles were reduced in the second quarter of 2017 by two years to Dec. 31, 2019. As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2017, increased by approximately $26 million. Since Sundance Unit 1 was shut down two years early, the Canadian Minister of Environment & Climate Change agreed to extend the useful life of Sundance Unit 2 from 2019 to 2021. As such, during the third quarter of 2017, the Corporation extended the useful life of Sundance Unit 2 to 2021. As a result, depreciation expense and intangibles amortization for the year ended Dec. 31, 2017 decreased in total by approximately $4 million. However, in the third quarter of 2018, the Corporation retired Sundance Unit 2 and recorded an impairment charge for the remaining net book value of the asset (refer to Note 7 for further details). 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 plant 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. Centralia During the third quarter of 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 be completed as originally proposed. The Corporation's current 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. TransAlta estimates that the undiscounted amount of cash flow required to settle this additional obligation is approximately $222 million, which will be incurred between 2021 and 2035. The provision may be revised in compliance with the Corporation's accounting policies, dependent upon future operating decisions and as more information becomes available. B. 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 Events (Notes)

Significant Events (Notes)	12 Months Ended
	Dec. 31, 2019
Significant Events [Abstract]
Significant Events	Significant and Subsequent Events A. Clean Energy Investment Plan On Sept. 16, 2019, TransAlta announced its Clean Energy Investment Plan, which includes converting its existing Alberta coal assets to natural gas and advancing its leadership position in onsite 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 plan includes converting three of its existing Alberta thermal units to gas in 2020 and 2021 by replacing existing coal burners with natural gas burners. As discussed further below in this section, the Corporation is also advancing permitting to convert one, or possibly two, of its units to highly efficient combined-cycle natural gas units. 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 the Alberta thermal assets; and ▪ Significantly reducing air emissions and costs. On Oct. 30, 2019, TransAlta acquired two 230 MW Siemens F class gas turbines and related equipment for $84 million. These turbines will be redeployed to TransAlta's Sundance site as part of the strategy to repower Sundance Unit 5 to a highly efficient combined-cycle unit. TransAlta expects to issue Limited Notice to Proceed (“LNTP”) in 2020 and Full Notice to Proceed (“FNTP”) in 2021 for the Sundance Unit 5 repowering, with an expected commercial operation date in 2023. The Sundance Unit 5 repowered combined-cycle unit will have a capacity of approximately 730 MW and is expected to cost approximately $750 million to $770 million. In conjunction with the Sundance Unit 5 permitting, TransAlta is also permitting Keephills Unit 1 to maintain the option to repower Keephills Unit 1 to a combined-cycle unit, depending on market fundamentals. As part of this transaction, we also acquired a long-term PPA for capacity plus energy, including the passthrough of greenhouse gas ("GHG") costs, starting in late 2023 with Shell Energy North America (Canada). 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. The Big Level and Antrim wind projects began commercial operations on Dec. 19, 2019 and Dec, 24, 2019, respectively. The Skookumchuck and Windrise wind projects are currently under construction. These projects are underpinned by long-term PPAs with highly creditworthy counterparties. In addition, TransAlta is currently constructing a cogeneration facility which will be jointly owned, operated and maintained with SemCAMS. B. Acquisition of Wind Development Projects During 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. C. Agreement to Construct and Own a Cogeneration Plant in Alberta On Oct. 1, 2019, TransAlta and SemCAMS Midstream ULC (“SemCAMS”) announced that they had 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 Kaybob facility is strategically located in the Western Canadian Sedimentary Basin and accepts natural gas production out of the Montney and Duvernay formations. TransAlta will construct the cogeneration plant, which will be jointly owned, operated and maintained with SemCAMS. The capital cost of the new cogeneration facility is expected to be approximately $105 million to $115 million and the project is expected to deliver approximately $18 million in annual EBITDA. TransAlta will be responsible for all capital costs during construction and, subject to the satisfaction of certain conditions, SemCAMS is expected to purchase a 50 per cent interest in the new cogeneration facility as of the commercial operation date, which is targeted for late 2021. All of the steam production and approximately half of the electricity output will be contracted to SemCAMS under a 13-year fixed price contract. The remaining electricity generation will be sold into the Alberta power market by TransAlta. The agreement contemplates an automatic seven-year extension subject to certain termination rights. D. 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. As discussed in Note 3(A)(II), the Corporation early-adopted 2020 amendments to IFRS 3 Business Combinations , which introduce an optional fair value concentration test. The Corporation elected to apply the optional fair value concentration test to its acquisition of the non-operating interest in Keephills 3, through which it was determined that greater than 90 per cent of the fair value was concentrated in the PP&E acquired. As a result, the acquisition was determined to not be a business and IFRS 3 requirements were not applied and the existing carrying amount of the owned 50 per cent of Keephills 3 was not required to be assessed at fair value. 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 The sale of Genesee 3 resulted in a gain of $77 million, which was recognized in gains on sale of assets and other on the statement of earnings during the fourth quarter of 2019. On the closing of the transaction, all of the Keephills 3 and Genesee 3 project agreements with Capital Power were terminated, including the agreement governing the supply of coal from TransAlta’s Sunhills mine to the Keephills 3 facility. The Sunhills mine accounted for the revenues generated under this agreement pursuant to IFRS 15 Revenue from Contracts with Customers , which resulted in the recognition of a contract liability representing the mine’s unsatisfied performance obligations for which consideration was received in advance. On Oct. 1, 2019, upon termination of this agreement, the Sunhills mine had no future performance obligations and accordingly, the balance of the contract liability of $88 million was recognized in earnings in the fourth quarter of 2019. E. Termination of the Alberta Sundance Power Purchase Arrangements On Sept. 18, 2017, the Corporation received formal notice from the Balancing Pool for the termination of the Sundance B and C PPAs effective Mar. 31, 2018. This announcement was expected and the Corporation took steps to re-take dispatch control for the units effective Mar. 31, 2018. Pursuant to a written agreement, the Balancing Pool paid the Corporation approximately $157 million on Mar. 29, 2018. The Corporation disputed the termination payment received. The Balancing Pool excluded certain mining and corporate assets that should have been included in the net book value calculation, which the Corporation pursued from the Balancing Pool through an arbitration initiated under the PPAs. On Aug. 26, 2019, the Corporation announced it was successful in the arbitration and received the full amount it was seeking to recover of $56 million, plus GST and interest. F. Strategic Investment by Brookfield On Mar. 25, 2019, the Corporation announced that it had 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. Under the terms of the Investment Agreement, Brookfield agreed to invest $750 million in the Corporation through the purchase of exchangeable securities, which 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. The remaining $400 million will be invested in October 2020 in exchange for a new series of redeemable, retractable first preferred shares, subject to the satisfaction of certain conditions being met. 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 24 for further details. In addition, subject to the exceptions in the Investment Agreement, Brookfield has committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to not less than nine per cent at the conclusion of the prescribed share purchase period, provided that Brookfield is not obligated to purchase any common shares at a price per share in excess of $10 per share. 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 provide advice and recommendations in connection with the operation, and maximizing 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 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 (which occurred on May 1, 2019). 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 transaction. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter is scheduled to proceed to trial beginning Sep. 14, 2020. Refer to Note 35 for further details. G. Skookumchuck Wind Project On April 12, 2019, TransAlta signed an agreement with Southern Power to purchase a 49 per cent interest in the Skookumchuck wind project, a 136.8 MW wind project currently under construction and located in Lewis and Thurston counties near Centralia in Washington state. The project has a 20-year PPA with Puget Sound Energy. TransAlta has the option to make its investment when the facility reaches its commercial operation date, which is expected to be in the first half of 2020. TransAlta's 49 per cent interest in the total capital investment is expected to be $150 million to $160 million, a portion of which is expected to be funded with tax equity financing . H. Pioneer Pipeline On Dec. 17, 2018, the Corporation exercised its option to acquire 50 per cent ownership in the Pioneer gas pipeline ("Pioneer Pipeline"). During the second quarter of 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. Tidewater Midstream and Infrastructure Ltd ("Tidewater") 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 the year ended Dec. 31, 2019, TransAlta invested $83 million in the Pioneer Pipeline and has invested $100 million life-to-date. The Pioneer Pipeline is held in a separate entity that is a joint operation with Tidewater. 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. 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. If these facts and circumstances change, the classification of the joint arrangement may change. I. Mothballing of Sundance Units On Mar. 8, 2019, the Corporation announced that the Alberta Electric System Operator ("AESO") granted an extension to the mothballing of Sundance Units 3 and 5, which will remain mothballed until Nov. 1, 2021, extended from April 1, 2020. The extensions were requested by TransAlta based on its assessment of market prices and market conditions. TransAlta has the ability to return either of the units back to full operation by providing three months’ notice to the AESO. J. US Wind Projects On Feb. 20, 2018, TransAlta Renewables Inc. ("TransAlta Renewables") announced it entered into an arrangement to acquire interests in two construction-ready wind projects in the Northeastern United States (collectively, the "US Wind Projects"). The Big Level wind project ("Big Level") consists of a 90 MW wind project located in Pennsylvania that has a 15-year PPA with Microsoft Corp., and the Antrim wind project ("Antrim") consists of a 29 MW wind project located in New Hampshire with two 20-year PPAs with Partners Healthcare and New Hampshire Electric Co-op. The Counterparties in the PPAs all have a Standard & Poor's credit ratings of A+ or better. A subsidiary of TransAlta acquired Big Level on Mar. 1, 2018 and Antrim on Mar. 28, 2019. On April 20, 2018, TransAlta Renewables completed the acquisition of an economic interest in Big Level from a subsidiary of TransAlta Power Ltd. (“TA Power”). Pursuant to the arrangement, a TransAlta subsidiary owns Big Level directly and TA Power issued to TransAlta Renewables tracking preferred shares that pay quarterly dividends based on the pre-tax net earnings of Big Level. The tracking preferred shares have preference over the common shares of TA Power held by TransAlta, in respect of dividends and the distribution of assets in the event of the liquidation, dissolution or winding-up of TA Power. On March 28, 2019, the closing conditions related to the acquisition of Antrim were finalized and the TransAlta subsidiary acquired the development project for total cash consideration of $24 million and the settlement of the balance of the outstanding loan receivable of $41 million. As a result, the Corporation recognized $50 million for assets under construction in PP&E and $15 million in intangibles. The TransAlta subsidiary also paid the final holdback for the Big Level development project of $7 million (US$5 million) on the closing of Antrim. Cost estimates for the US Wind Projects were reforecasted to be within the range of US$250 million to US$270 million, primarily due to construction and weather-related impacts as well as higher interconnection costs. TransAlta Renewables funded these costs either by acquiring additional tracking preferred shares issued by TA Power or by subscribing for interest-bearing promissory notes issued by the project entity. The proceeds from the issuance of such preferred shares or notes were used exclusively in connection with the acquisition and construction of the US Wind Projects. During 2019, TransAlta Renewables funded the acquisition of Antrim and the construction costs of the US Wind Projects by subscribing for $142 million (US$105 million) of interest-bearing promissory notes and $78 million (US$59 million) of tracking preferred shares. Big Level and Antrim each began commercial operations in December 2019. In conjunction with reaching commercial operation, tax equity proceeds were raised to partially fund the US Wind Projects in the amount of approximately US$85 million for Big Level and approximately US$41 million for Antrim. The tax equity financing is classified as long-term debt on the Consolidated Statements of Financial Position. From the tax equity proceeds, a subsidiary of TransAlta repaid $52 million (US$40 million) of the interest-bearing promissory notes from TransAlta Renewables. The remaining amount of the tax equity proceeds is held as reserves within the project entity and will be released upon certain conditions being met. Once these conditions are met, the reserves will be released and the subsidiary of TransAlta will repay the remaining outstanding interest-bearing promissory notes from TransAlta Renewables. K. Normal Course Issuer Bid 2019 On May 27, 2019, the Corporation announced that the Toronto Stock Exchange ("TSX") accepted the notice filed by the Corporation to implement a normal course issuer bid ("NCIB") for a portion of its common shares. Pursuant to the NCIB, the Corporation may purchase 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. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled. The period during which TransAlta is authorized to make purchases under the NCIB commenced on May 29, 2019, and ends on May 28, 2020, 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 176,447 common shares (being 25 per cent of the average daily trading volume on the TSX of 705,788 common shares for the six months ended April 30, 2019) 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, 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 26 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. L. Windrise On Dec. 17, 2018, TransAlta's 207 MW Windrise wind project was selected by the AESO as one of the three successful projects in the third round of the Renewable Electricity Program. The Windrise wind project, which is in the county of Willow Creek, is underpinned by a 20-year Renewable Electricity Support Agreement with the AESO. The project is expected to cost approximately $270 million to $285 million and is targeted to reach commercial operation during the first half of 2021. M. Kent Hills 3 Wind Project During 2017, a subsidiary of TransAlta Renewables, Kent Hills Wind LP ("KHWLP"), entered into a long-term contract with New Brunswick Power Corporation (“NB Power”) for the sale of all power generated by an additional 17.25 MW of capacity from the Kent Hills 3 expansion wind project. At the same time, the term of the Kent Hills 1 contract with NB Power was extended from 2033 to 2035, matching the life of the Kent Hills 2 and Kent Hills 3 wind projects. On Oct. 19, 2018, TransAlta Renewables announced that the expansion is fully operational, bringing total generating capacity of the Kent Hills wind farm to 167 MW. N. TransAlta Renewables Acquires Three Renewable Assets from the Corporation On May 31, 2018, TransAlta Renewables acquired from a subsidiary of the Corporation an economic interest in the 50 MW Lakeswind wind farm in Minnesota and 21 MWs of solar projects located in Massachusetts ("Mass Solar") through the subscription of tracking preferred shares of a subsidiary of the Corporation. In addition, TransAlta Renewables acquired from a subsidiary of the Corporation ownership of the 20 MW Kent Breeze wind farm located in Ontario. The total purchase price for the three assets was approximately $166 million, including the assumption of $62 million of tax equity obligations and project debt, for net cash consideration of $104 million. The Corporation continues to operate these assets on behalf of TransAlta Renewables. The acquisition of Kent Breeze was accounted for by TransAlta Renewables as a business combination under common control, requiring the application of the pooling of interests method of accounting, whereby the assets and liabilities acquired were recognized at the book values previously recognized by TransAlta at May 31, 2018, and not at their fair values. As a result, the Corporation recognized a transfer of equity from the non-controlling interests in the amount of $1 million in 2018. On June 28, 2018, TransAlta Renewables subscribed for an additional $33 million of tracking preferred shares of a subsidiary of the Corporation related to Mass Solar, to fund the repayment of Mass Solar's project debt. In connection with these acquisitions, the Corporation recorded a $12 million impairment charge, of which $11 million was recorded against PP&E and $1 million against intangibles. See Note 7 for further details. O. TransAlta Renewables Closes $150 Million Offering of Common Shares On June 22, 2018, TransAlta Renewables closed a bought deal offering of 11,860,000 common shares through a syndicate of underwriters (the "Offering"). The common shares were issued at a price of $12.65 per common share for gross proceeds of approximately $150 million ($144 million of net proceeds). The net proceeds of the Offering were used to partially repay drawn amounts under TransAlta Renewables' credit facility, which was drawn in order to fund recent acquisitions. The additional liquidity under the credit facility was used for general corporate purposes, including ongoing construction costs associated with the US Wind Projects, described in 4(J) above. The Corporation did not purchase any additional common shares under the Offering and, following the closing, owned 161 million common shares, representing approximately 61 per cent of the outstanding common shares of TransAlta Renewables. See Note 12 for further details of TransAlta's ownership of TransAlta Renewables. P. $345 Million Financing Related to the Off-Coal Agreement On July 20, 2018, the Corporation monetized the payments under the Off-Coal Agreement with the Government of Alberta by closing a $345 million bond offering through its indirect wholly owned subsidiary, TransAlta OCP LP ("TransAlta OCP"). The offering was a private placement that was secured by, among other things, a first ranking charge over the OCA payments payable by the Government of Alberta. The amortizing bonds bear interest at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030. The bonds have a rating of BBB, with a stable trend, by DBRS. Under the terms of 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. The net proceeds were used to partially repay the 6.40 per cent debentures, as described below. Q. Early Redemption of $400 Million of Debentures On Aug. 2, 2018, the Corporation early redeemed all of its then outstanding 6.40 per cent debentures, due Nov. 18, 2019, for the principal amount of $400 million. The redemption price was approximately $425 million in aggregate, including a prepayment premium and accrued and unpaid interest. See Note 23 for further details. R. Early Redemption of Senior Notes On March 15, 2018, the Corporation early redeemed all of its then outstanding 6.650 per cent US$500 million senior notes due May 15, 2018, for approximately $617 million (US$516 million). A $5 million early redemption premium was recognized in net interest expense. See Note 23 for further details. S. Notice of Termination of South Hedland Power Purchase Agreement from Fortescue Metals Group Limited On Nov. 13, 2017, the Corporation announced that TEC Hedland Pty Ltd ("TEC Hedland"), a subsidiary of the Corporation, received formal notice of termination of the South Hedland Power Purchase Agreement ("South Hedland PPA") from a subsidiary of Fortescue Metals Group Limited ("FMG"). The South Hedland PPA allows FMG to terminate the agreement if the facility has not reached commercial operation within a specified time period. FMG is asserting that the South Hedland facility did not achieve commercial operation in accordance with the terms of the South Hedland PPA within the specified time period. The Corporation believes that all conditions required to establish commercial operations, including all performance conditions, have been achieved under the terms of the South Hedland PPA. These conditions include receiving a commercial operation certificate, successfully completing and passing certain test requirements, and obtaining all permits and approvals required from the North West Interconnected System and government agencies. Confirmation of commercial operation has been provided by independent engineering firms, as well as by Horizon Power, the state-owned utility. The Corporation is taking all steps necessary to protect its interests in the facility and ensure all cash flows promised under the South Hedland PPA are realized. The South Hedland facility has been fully operational and able to meet FMG’s requirements under the terms of the South Hedland PPA since July 2017. TEC Hedland commenced proceedings in the Supreme Court of Western Australia on Dec. 4, 2017, to recover amounts invoiced under the South Hedland PPA. This matter is scheduled to proceed to trial beginning June 15, 2020. See also Note 35. T. Reacquisition of Solomon Facility On Aug. 1, 2017, the Corporation received notice of FMG’s intention to repurchase the Solomon facility from TEC Pipe Pty Ltd. ("TEC Pipe"), a wholly owned subsidiary of the Corporation, for approximately US$335 million. FMG completed its acquisition of the Solomon facility on Nov. 1, 2017, and TEC Pipe received US$325 million as consideration. FMG has held back the balance from the purchase price. It is the Corporation’s view that this should not have been held back and the Corporation is taking action in the Supreme Court of Western Australia to recover all, or a significant portion of, this amount from FMG. A trial date for this matter has not yet been scheduled. See also Note 35. U. TransAlta Renewables' $260-Million Project Financing of New Brunswick Wind Assets and Early Redemption of Outstanding Debentures On Oct. 2, 2017, TransAlta Renewables announced that its indirect majority-owned subsidiary, Kent Hills Wind LP ("KHWLP"), closed an approximate $260 million bond offering, secured by, among other things, a first ranking charge over all assets of KHWLP. The bonds are amortizing and bear interest at a rate of 4.454 per cent, payable quarterly, and mature on Nov. 30, 2033. A portion of the net proceeds was used to fund a portion of the construction costs for the 17.25 MW Kent Hills 3 wind project. The remaining proceeds were advanced to its subsidiary Canadian Hydro Developers, Inc. ("CHD") and to Natural Forces Technologies Inc., KHWLP’s partner, which owns approximately 17 per cent of KHWLP. At the same time, CHD, a wholly owned subsidiary of TransAlta Renewables, provided notice that it would be early redeeming all of its unsecured debentures. The debentures were scheduled to mature in June 2018. On Oct. 12, 2017, CHD redeemed the unsecured debentures for $201 million, which included the principal of $191 million, an early redemption premium of $6 million and accrued interest of $4 million. The $6 million early redemption premium was recognized in net interest expense for the year ended Dec. 31, 2017. V. Force Majeure Relief – Keephills 1 Keephills 1 tripped off-line on March 5, 2013, due to a suspected winding failure within the generator. After extensive testing and analysis, it was determined that a full rewind of the generator stator was required. After completing the repairs, the unit returned to service on Oct. 6, 2013. The Corporation claimed force majeure relief on March 26, 2013. The buyer, ENMAX, disputed the claim of force majeure, which triggered the need for an arbitration hearing that took place in May 2016. On Nov. 18, 2016, the Corporation announced that the independent arbitration panel confirmed the Corporation’s claim for force majeure relief. Accordingly, the Corporation reversed a provision of approximately $94 million in 2016. The buyer and the Balancing Pool sought to set the arbitration panel’s decision aside in the Court of Queen’s Bench of Alberta. The Court of Queen's Bench dismissed this application. ENMAX and the Balancing Pool are now attempting to appeal that decision in the Court of Appeal, which requires leave (permission) of the Court. The leave application was heard on Nov. 13, 2019. On Feb. 13, 2019, the Alberta Court of Appeal granted the Balancing Pool and ENMAX permission to appeal. The next step is for TransAlta to continue to defend the arbitration award in the appeal application, which will likely be heard in 2020. W. Mississauga Cogeneration Facility NUG Contract On Dec. 22, 2016, the Corporation announced it had signed the Non-Utility Generator Contract (the "NUG Contract") with the Ontario Independent Electricity System Operator (the “IESO”) for its Mississauga cogeneration facility. The NUG Contract was effective on Jan. 1, 2017, and, in conjunction with the execution of the NUG Contract, the Corporation agreed to terminate, effective Dec. 31, 2016, the facility’s existing contract with the Ontario Electricity Financial Corporation, which would have otherwise terminated in December 2018. In December 2018, TransAlta exercised its option to terminate its land lease agreement, where the Mississauga facility is located, with Boeing Canada Inc. effective Dec. 31, 2021. TransAlta is required to remove the plant and restore the site within the three-year time frame. The NUG Contract provided the Corporation with fixed monthly payments until Dec. 31, 2018, with no delivery obligations. Further details on the NUG Contract and its impact on these financial statements can be found in Note 9(B). X. Wintering Hills Assets Held for Sale The Corporation acquired its interest in Wintering Hills in 2015 in connection with the restructuring of the arrangements associated with its Poplar Creek cogeneration facility. At Dec. 31, 2016, the criteria for Wintering Hills to be classified as held for sale were met. The

Revenue (Notes)

Revenue (Notes)	12 Months Ended
	Dec. 31, 2019
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 energy marketing and trading 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, 2019 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Revenues from contracts with 395 10 205 87 244 142 — — 1,083 Revenue from leases (1) 65 — — 65 — — — — 130 Revenue from derivatives (17) 160 2 — 18 — 129 4 296 Government incentives — — — — 8 — — — 8 Revenue from other (2) 373 401 2 8 42 14 — (10) 830 Total revenue 816 571 209 160 312 156 129 (6) 2,347 Revenues from contracts with customers Timing of revenue recognition At a point in time 41 10 — — 27 — — — 78 Over time 354 — 205 87 217 142 — — 1,005 Total revenue from contracts 395 10 205 87 244 142 — — 1,083 (1) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. (2) Includes merchant revenue and other miscellaneous. Year ended Dec. 31, 2018 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Revenues from contracts with 517 9 224 91 206 132 — — 1,179 Revenue from leases (1) 68 — — 68 27 7 — — 170 Revenue from derivatives (1) 115 4 — (20) — 67 — 165 Government incentives — — — — 16 — — — 16 Revenue from other (2) 328 318 4 6 53 17 — (7) 719 Total revenue 912 442 232 165 282 156 67 (7) 2,249 Revenues from contracts with customers Timing of revenue recognition At a point in time 38 9 — — 18 — — — 65 Over time 479 — 224 91 188 132 — — 1,114 Total revenue from contracts with customers 517 9 224 91 206 132 — — 1,179 (1) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases (2017 - $247 million). (2) Includes merchant revenue and other miscellaneous. B. Contract Liabilities The Corporation has recognized the following revenue-related contract liabilities: Contract liabilities 2019 2018 Balance, beginning of the year 88 62 IFRS 16 and 15 transition adjustments (1) 15 17 Amounts transferred to revenue included in opening balance (10) (10) Consideration received 5 13 Increases due to interest accrued and expensed during the period 5 6 Contract termination associated with the purchase of Keephills 3 (Note 4(D)) (88) — Balance, end of year 15 88 Current portion 1 8 Long-term portion 14 80 (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. In 2018, this adjustment related to the significant financing component added on adoption of IFRS 15. Contract liabilities in 2018 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 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, 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. Canadian Coal At Dec. 31, 2019, the Corporation has PPAs with the Balancing Pool for capacity and electricity from two of its coal plants, as dispatched, with contract end dates of Dec. 31, 2020. All generation produced is delivered for the benefit of the customer. Certain sources of revenue under one PPA contract are accounted for as a lease and are excluded from these disclosures. Pricing is comprised of multiple components, of both fixed and variable nature, consisting of a capacity payment based on a return of capital , availability payments (from or to the customer) based on the 30-day rolling average pool price and actual availability of the plant as compared to targeted availability specified in the PPAs, recovery of regulatory pass-through costs, and payments for delivery of energy based on the variable cost of producing the energy. Energy-related payments are variable depending on output from the plant, which is dependent upon market demand and the operational ability of the plant. Revenues are generally recognized over time, on a monthly basis. Future revenues that are based upon variable consideration are considered to be fully constrained and are excluded from these disclosures. The Corporation also has several contracts for sale of byproducts of coal combustion from certain of its coal plants. The contracts range in duration from one to three years. 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. 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, 2019, are approximately $452 million, of which the Corporation expects to recognize approximately $116 million over the next fiscal year and on average, between $5 million to $10 million in 2023 and $40 million to $45 million annually thereafter for the duration of the contracts. US Coal 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. Canadian Gas At Dec. 31, 2019, the Corporation has contracts with customers to deliver energy services from one of its gas plants 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 plant, 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, 2019, the Corporation had contracts with customers to deliver steam, hot water and chilled water from one of its other gas plants 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. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2019, are approximately $18 million in total, of which the Corporation expects to recognize between approximately $4 million to $6 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; accordingly, disclosures related to remaining performance obligations are not provided for these contracts. Australian Gas At Dec. 31, 2019, the Corporation has PPAs with customers to deliver electricity from its gas plants located in Australia. One contract is considered to be a lease and is excluded from these disclosures. 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 2021 to 2042. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2019, are approximately $2,095 million, of which the Corporation expects to recognize approximately $223 million in total over the next three fiscal years and on average, between approximately $80 million to $110 million annually thereafter for the duration of the contracts. Wind and Solar At Dec. 31, 2019, the Corporation had long-term contracts with customers to deliver electricity and the associated renewable energy credits from three wind farms 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 at a point in 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 purchaser 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, 2019, are approximately $8 million, of which the Corporation expects to recognize between approximately $1 million to $2 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. Hydro At Dec. 31, 2019, the Corporation has a PPA with the Balancing Pool to provide the capacity of 12 hydro plants throughout the province of Alberta. The capacity payment is fixed on an annual basis. As part of the PPA, the Corporation also has a financial obligation to the Balancing Pool determined on the basis of notional quantities of electricity delivered and the pool price for the period. The Corporation expects to recognize revenue as it makes capacity available to the customer until completion of the contract term at Dec. 31, 2020. The Corporation also has contracts for blackstart services at specific hydro plants, which conclude in 2020, and 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, 2019, are approximately $72 million, which the Corporation expects to recognize in the next two fiscal years. 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.

Expenses by Nature (Notes)

Expenses by Nature (Notes)	12 Months Ended
	Dec. 31, 2019
Analysis of income and expense [abstract]
Expenses by Nature	Expenses by Nature Expenses classified by nature are as follows: Year ended Dec. 31 2019 2018 2017 Fuel and Operations, Fuel and Operations, Fuel and Operations, Fuel (1) 669 — 656 — 685 — Purchased power 246 — 210 — 162 — Mine depreciation 119 — 136 — 73 — Salaries and benefits (1) 52 228 98 245 96 248 Other operating expenses — 247 — 270 — 269 Total 1,086 475 1,100 515 1,016 517

Asset Impairment Charges and Re

Asset Impairment Charges and Reversals (Notes)	12 Months Ended
	Dec. 31, 2019
Disclosure of impairment of assets [Abstract]
Asset Impairment Charges and Reversals	Asset Impairment Charges 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. 2019 Centralia Plant In 2012, the Corporation recorded an impairment of $347 million relating to the Centralia Plant CGU. As part of the annual impairment test, the Corporation considers possible indicators of impairment at the Centralia Plant CGU. In 2019, an internal valuation indicated the fair value less costs of disposal of the Centralia Plant 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 US Coal 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 for coal transition established with the State of Washington. The valuation period includes cash flows until the decommissioning of the plant 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. The Corporation's current 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)(IV) and 22 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 Canadian Coal segment and accordingly wrote the assets down to net realizable value, resulting in an impairment charge of $15 million. B. 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(N)). 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 charge 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 17 and 19). C. 2017 Sundance Unit 1 In the second quarter of 2017, the Corporation recognized an impairment charge on Sundance Unit 1 in the amount of $20 million, due to the Corporation’s decision to early retire Sundance Unit 1. Previously, the Corporation had expected Sundance Unit 1 to operate in the merchant market in 2018 and 2019 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 Jan. 1, 2018. Discounting did not have a material impact. No separate stand-alone impairment test was required for Sundance Unit 2, as mothballing the unit maintained the Corporation’s flexibility to operate the Unit as part of the Corporation’s Alberta Merchant CGU to 2021. D. Project Development Costs

Finance Lease Receivables (Note

Finance Lease Receivables (Notes)	12 Months Ended
	Dec. 31, 2019
Disclosure of recognised finance lease as assets by lessee [abstract]
Finance Lease Receivables	Finance Lease Receivables Amounts receivable under the Corporation’s finance leases associated with the Poplar Creek cogeneration facility and in 2018, the Fort Saskatchewan cogeneration facility are as follows: As at Dec. 31 2019 2018 Minimum Present value of Minimum Present value of Within one year 20 20 30 29 Second to fifth years inclusive 80 74 80 74 More than five years 120 97 140 112 220 191 250 215 Less: unearned finance lease income 29 — 35 — Total finance lease receivables 191 191 215 215 Included in the Consolidated Statements of Financial Position as: Current portion of finance lease receivables (Note 13) 15 24 Long-term portion of finance lease receivables 176 191 191 215

Net Other Operating (Income) Lo

Net Other Operating (Income) Losses (Notes)	12 Months Ended
	Dec. 31, 2018
Analysis of income and expense [abstract]
Net other operating (income) losses	Net Other Operating Income Net other operating income includes the following: Year ended Dec. 31 2019 2018 2017 Alberta Off-Coal Agreement (40) (40) (40) Mississauga cogeneration facility NUG Contract (1) — (9) Insurance recoveries (10) (7) — Other expenses 2 — — Net other operating income (49) (47) (49) A. 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 will not impact the payments received. Refer to Note 4(D) 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), commencing Jan. 1, 2017, and terminating 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(P) and 23 for further details. B. Mississauga Cogeneration Facility Contract On Dec. 22, 2016, the Corporation announced it had signed the NUG Contract with the IESO for its Mississauga cogeneration facility. The contract was effective on Jan. 1, 2017. The Corporation agreed to terminate the prior contract with the IESO early, which would have otherwise terminated in December 2018. During the fourth quarter of 2017, the Corporation renegotiated the facility's land lease agreement at a lower cost than previously estimated in 2016, and accordingly, recognized a gain of $9 million. In December 2018, TransAlta exercised its option to terminate its land lease agreement for the site with Boeing Canada Inc. effective Jan. 1, 2021. TransAlta is required to remove the plant and restore the site within the three-year time frame. C. Insurance Recoveries During 2019, the Corporation received $10 million in insurance recoveries, which related to insurance proceeds for tower fires at Wyoming Wind and Summerview. During 2018, the Corporation received $7 million in insurance recoveries, of which $6 million related to insurance proceeds for the tower fire at Wyoming Wind and a $1 million claim related to equipment repairs within Canadian Coal. There were no insurance recoveries in 2017.

Net Interest Expense (Notes)

Net Interest Expense (Notes)	12 Months Ended
	Dec. 31, 2019
Net Interest Expense [Abstract]
Net interest expense	Net Interest Expense The components of net interest expense are as follows: Year ended Dec. 31 2019 2018 2017 Interest on debt 161 184 218 Interest on exchangeable securities (Note 24) 20 — — Interest income (13) (11) (7) Capitalized interest (Note 17) (6) (2) (9) Loss on redemption of bonds (Note 23) — 24 6 Interest on finance lease obligations 4 3 3 Credit facility fees, bank charges and other interest 15 13 18 Tax shield on tax equity financing (Note 23) (1) (35) — — Other (2) 10 15 (3) Accretion of provisions (Note 22) 23 24 21 Net interest expense 179 250 247 (1) Relates to the tax benefit associated with bonus tax depreciation claimed in 2019 on the Big Level and Antrim wind 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 (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2019
Income Taxes [Abstract]
Income Taxes	Income Taxes A. Consolidated Statements of Earnings I. Rate Reconciliations Year ended Dec. 31 2019 2018 2017 Earnings before income taxes 193 (96) (54) Net earnings attributable to non-controlling interests not subject to tax (26) (19) (35) Adjusted earnings before income taxes 167 (115) (89) Statutory Canadian federal and provincial income tax rate (%) 26.5 % 26.8 % 26.8 % Expected income tax expense (recovery) 44 (31) (24) Increase (decrease) in income taxes resulting from: Differences in effective foreign tax rates 5 (3) (11) Writedown (reversal of writedown) of deferred income tax assets (9) 27 (15) Statutory and other rate differences (31) — 110 Other 8 1 4 Income tax expense (recovery) 17 (6) 64 Effective tax rate (%) 10 % 5 % 72 % II. Components of Income Tax Expense The components of income tax expense are as follows: Year ended Dec. 31 2019 2018 2017 Current income tax expense (1) 35 28 79 Deferred income tax expense (recovery) related to the origination and reversal of 22 (61) (110) Deferred income tax expense resulting from changes in tax rates or laws (2,3) (31) — 110 Deferred income tax expense (recovery) arising from the writedown (reversal of writedown) of deferred income tax assets (4) (9) 27 (15) Income tax expense (recovery) 17 (6) 64 Year ended Dec. 31 2019 2018 2017 Current income tax expense 35 28 79 Deferred income tax recovery (18) (34) (15) Income tax expense (recovery) 17 (6) 64 (1) During 2017, the Corporation recognized current tax expense of $56 million due to the disposition of the Solomon facility Nov. 1, 2017. (2) In 2019, the Corporation recognized a deferred income tax recovery of $31 million related to a decrease in the Alberta corporate tax rate from 12 per cent to 8 per cent. The tax decrease is phased in as follows: 11 per cent effective July 1, 2019, 10 per cent effective January 1, 2020, 9 per cent effective January 1, 2021, and 8 per cent effective January 1, 2022. (3) On Dec. 22, 2017, the US government enacted H.R.1, originally known as the Tax Cuts and Jobs Act, which includes legislation to decrease its federal corporate income tax rate from 35 per cent to 21 per cent. The Corporation's net deferred tax liability associated with its directly owned US operations is made up of a deferred tax asset and a deferred tax liability that net to $6 million. The decrease in the US federal corporate income tax rate resulted in a decrease to the deferred tax asset of $104 million, all of which is recorded as deferred tax expense in the Consolidated Statement of Earnings, offset by a decrease to the deferred tax liability of $110 million, of which $1 million is recorded as deferred tax expense in the Consolidated Statement of Earnings with an offsetting $111 million deferred tax recovery recorded in the Consolidated Statement of Other Comprehensive Income. (4) During the year ended Dec. 31, 2019, the Corporation recorded a reversal of a previous writedown of deferred income tax assets of $9 million (2018 - $27 million writedown, 2017 - $15 million writedown reversal). The deferred income tax assets relate mainly 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. The Corporation previously wrote these assets off when it was not considered probable that sufficient future taxable income would be available from the Corporation’s directly owned US operations to utilize the underlying tax losses. Recognized ordinary income and other comprehensive income has given rise to taxable temporary differences, which forms the primary basis for utilization of some of the tax losses and the reversal of the writedown. 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 2019 2018 2017 Income tax expense (recovery) related to: Net impact related to cash flow hedges 6 (12) (108) Net impact related to net investment hedges — — (7) Net actuarial gains (losses) (7) 5 (4) Income tax expense reported in equity (1) (7) (119) C. Consolidated Statements of Financial Position Significant components of the Corporation’s deferred income tax assets (liabilities) are as follows: As at Dec. 31 2019 2018 Net operating loss carryforwards 494 547 Future decommissioning and restoration costs 122 113 Property, plant and equipment (828) (896) Risk management assets and liabilities, net (141) (145) Employee future benefits and compensation plans 56 68 Interest deductible in future periods 42 48 Foreign exchange differences on US-denominated debt 40 35 Deferred coal revenues — 23 Other deductible temporary differences 4 — Net deferred income tax liability, before writedown of deferred income tax assets (211) (207) Writedown of deferred income tax assets (243) (266) Net deferred income tax liability, after writedown of deferred income tax assets (454) (473) The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows: As at Dec. 31 2019 2018 Deferred income tax assets (1) 18 28 Deferred income tax liabilities (472) (501) Net deferred income tax liability (454) (473) (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

Non-Controlling Interests (Note

Non-Controlling Interests (Notes)	12 Months Ended
	Dec. 31, 2019
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, 2019 TransAlta Cogeneration L.P. 49.99% - Canadian Power Holdings Inc. TransAlta Renewables 39.6% - 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 coal 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 farm located in New Brunswick. The South Hedland facility achieved commercial operation on July 28, 2017. On Aug. 1, 2017, the Corporation converted its 26.1 million Class B shares held in TransAlta Renewables into 26.4 million common shares of TransAlta Renewables. At that time, the Corporation’s equity participation percentage in TransAlta Renewables increased to 64 per cent from 59.8 per cent. The Class B shares were converted at a ratio greater than 1:1 because the construction and commissioning costs for the project were below the referenced costs agreed to with TransAlta Renewables. 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 may elect to automatically reinvest monthly dividends into additional common shares of the Corporation. As a result of the conversion of the Class B shares, the DRIP and the Offering described in Note 4(O), the Corporation’s share of ownership and equity participation in TransAlta Renewables has changed as follows: Period Ownership and voting Equity participation Jan. 6, 2016 to July 31, 2017 64.0 59.8 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 Apr. 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 Year ended Dec. 31 2019 2018 2017 Revenues 446 462 459 Net earnings 183 241 13 Total comprehensive income 138 281 (24) Amounts attributable to the non-controlling interests: Net earnings 73 94 11 Total comprehensive income 56 110 — Distributions paid to non-controlling interests 69 79 85 As at Dec. 31 2019 2018 Current assets 293 250 Long-term assets 3,409 3,497 Current liabilities (152) (159) Long-term liabilities (1,237) (1,192) Total equity (2,313) (2,396) Equity attributable to non-controlling interests (941) (961) Non-controlling interests’ share (per cent) 39.6 39.1 B. TA Cogen Year ended Dec. 31 2019 2018 2017 Results of operations Revenues 181 185 175 Net earnings 43 29 61 Total comprehensive income 43 29 61 Amounts attributable to the non-controlling interest: Net earnings 21 14 31 Total comprehensive income 21 14 31 Distributions paid to Canadian Power Holdings Inc. 37 86 87 As at Dec. 31 2019 2018 Current assets 41 82 Long-term assets 328 354 Current liabilities (27) (54) Long-term liabilities (19) (28) Total equity (323) (354) Equity attributable to Canadian Power Holdings Inc. (160) (176) Non-controlling interest share (per cent) 49.99 49.99

Financial Instruments (Notes)

Financial Instruments (Notes)	12 Months Ended
	Dec. 31, 2019
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, 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 receivable — — 176 176 Risk management assets Current 71 95 — 166 Long-term 607 33 — 640 Other assets (Note 21) — — 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 finance lease obligations (2) — — 3,212 3,212 Exchangeable securities — — 326 326 (1) Includes cash equivalents of nil. (2) Includes current portion. Carrying value as at Dec. 31, 2018 Derivatives Derivatives Amortized cost Other financial assets (FVTPL) Total Financial assets Cash and cash equivalents (1) — — 89 — 89 Restricted cash — — 66 — 66 Trade and other receivables — — 731 25 756 Long-term portion of finance lease receivables — — 191 — 191 Risk management assets Current 60 86 — — 146 Long-term 629 33 — — 662 Other assets — — 37 15 52 Financial liabilities Accounts payable and accrued liabilities — — 496 — 496 Dividends payable — — 58 — 58 Risk management liabilities Current 1 89 — — 90 Long-term 1 40 — — 41 Credit facilities, long-term debt and finance lease obligations (2) — — 3,267 — 3,267 (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 calculated within the Corporation’s energy trading risk management system 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 2019 2018 Description Base fair value Sensitivity Base fair value Sensitivity Long-term power sale – US 737 +46 801 +116 Unit contingent power purchases (6) +1 18 +4 Structured products – Eastern US 7 +2 6 +5 Full requirements – Eastern US 10 +3 — — Long-term wind energy sale – Eastern US (28) +20 (39) +21 Others — +7 9 +3 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 2021, 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. Forward power price ranges per MWh used in determining the Level III base fair value at Dec. 31, 2019, are US$20 to US$28 (Dec. 31, 2018 - US$20 to US$35). The sensitivity analysis has been prepared using the Corporation’s assessment that a US$3 to US$9 (Dec. 31, 2018 - US$6) price decrease or increase in the forward power prices is a reasonably possible change. The contract is denominated in US dollars. With the weakening of the US dollar relative to the Canadian dollar from Dec. 31, 2018 to Dec. 31, 2019, the base fair value and the sensitivity values have decreased by approximately $11 million and $2 million, respectively. ii. Unit Contingent Power Purchases Under the unit contingent PPAs, the Corporation has agreed to purchase power contingent upon the actual generation of specific units owned and operated by third parties. Under these types of agreements, the purchaser pays the supplier an agreed upon fixed price per MWh of output multiplied by the pro-rata share of actual unit production (nil if a plant outage occurs). The contracts are accounted for as FVTPL. The key unobservable inputs used in the valuations are delivered volume expectations and hourly shapes of production. Hourly shaping of the production will result in realized prices that may be at a discount (or premium) relative to the average settled power price. Reasonably possible alternative inputs were used to determine sensitivity on the fair value measurements. This analysis is based on historical production data of the generation units for available history. Price and volumetric discount ranges per MWh used in the Level III base fair value measurement at Dec. 31, 2019, are nil (Dec. 31, 2018 – nil) and 2.2 per cent to 2.8 per cent (Dec. 31, 2018 – 2.2 per cent to 16.9 per cent), respectively. The sensitivity analysis has been prepared using the Corporation’s assessment of a reasonably possible change in price discount ranges of approximately 1.0 per cent to 2.0 per cent (Dec. 31, 2018 – 1.1 per cent to 1.9 per cent) and a change in volumetric discount rates of approximately 8.6 per cent to 10.5 per cent (Dec. 31, 2018 – 8.6 per cent and 27.3 per cent), which approximate one standard deviation for each input. iii. Structured Products – Eastern US The Corporation has fixed priced power and heat rate contracts in the eastern United States. Under the fixed priced power contracts, the Corporation has agreed to buy or sell power at non-liquid locations or during non-standard hours. The Corporation has also bought and sold heat rate contracts at both liquid and non-liquid locations. Under a heat rate contract, the buyer has the right to purchase power at times when the market heat rate is higher than the contractual heat rate. As at Dec. 31, 2019, the Corporation did not have any open positions on heat rate 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. Basis relationship and non-standard shape factors used in the Level III base fair value measurement at Dec. 31, 2019, are 91 per cent to 112 per cent and 63 per cent to 116 per cent (Dec. 31, 2018 – 75 per cent to 109 per cent and 63 per cent to 104 per cent), respectively. The sensitivity analysis has been prepared using the Corporation’s assessment of a reasonably possible change in market forward spreads of approximately 4.0 per cent to 6.0 per cent (Dec. 31, 2018 – 4.2 per cent to 6.9 per cent) and a change in non-standard shape factors of approximately 4.0 per cent to 10.0 per cent (Dec. 31, 2018 – 4.0 per cent to 9.3 per cent), which approximate one standard deviation for each input. The key unobservable inputs in the valuation of the heat rate contracts are implied volatilities and correlations. As there are no open positions on Level III heat rate option contracts, the implied volatilities and correlations used in the Level III base fair value measurement at Dec. 31, 2019, are nil and nil (Dec. 31, 2018 – 25 per cent to 84 per cent and 70 per cent), respectively. The sensitivity analysis was prepared using the Corporation’s assessment of a reasonably possible change in implied volatilities ranges and correlations of approximately nil and nil, respectively (2018 – 37 per cent to 49 per cent and 30 per cent, respectively). 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. The sensitivity analysis has been prepared using the Corporation’s assessment that a reasonably possible change in the expected portfolio delivery volumes and portfolio’s realized cost of supply of (+/-) 5 per cent and (+/-) US$1 per MWh, respectively. v. Long-Term Wind Energy Sale – Eastern US In relation to the acquisition of Big Level (See Note 4(J)), 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 forward prices for power and RECs beyond 2024 and 2022, respectively. Forward power and REC prices per MWh used in determining the Level III base fair value at Dec. 31, 2019, are US$38 to US$60 and US$9 (Dec. 31, 2018 – US$42 to US$68 and US$7 to US$8), respectively. The sensitivity analysis has been prepared using the Corporation’s assessment that a change in expected proxy generation volumes of 10 per cent (2018 – 10 per cent), a change in energy prices of US$6 (2018 – US$6) and a change in REC prices of US$1 (2018 – US$1) as reasonably possible changes. 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, 2019, are as follows: Level I - $3 million net liability (Dec. 31, 2018 – $3 million net asset), Level II – $9 million net asset (Dec. 31, 2018 – $19 million net liability) and Level III – $686 million net asset (Dec. 31, 2018 – $695 million net asset). Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2019, are primarily attributable to the settlement of contracts and unfavourable foreign exchange rates, partially offset by favourable market prices. 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, 2019 and 2018, respectively: Year ended Dec. 31, 2019 Year ended Dec. 31, 2018 Hedge Non-hedge Total Hedge Non-hedge Total Opening balance 689 6 695 719 52 771 Changes attributable to: Market price changes on existing contracts 77 8 85 (7) (9) (16) Market price changes on new contracts — 14 14 — 4 4 Contracts settled (57) (19) (76) (90) (42) (132) Change in foreign exchange rates (31) (1) (32) 67 5 72 Transfers into (out of) Level III — — — — (4) (4) Net risk management assets at end of period 678 8 686 689 6 695 Additional Level III information: Gains recognized in other comprehensive income 46 — 46 60 — 60 Total gains included in earnings before income taxes 57 21 78 90 — 90 Unrealized gains (losses) included in earnings before — 2 2 — (42) (42) III. Other Risk Management Assets and Liabilities Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in managing exposures on non-energy marketing transactions such as interest rates, the net investment in foreign operations and other foreign currency risks. Hedge accounting is not always applied. Other risk management assets and liabilities with a total net asset fair value of $4 million as at Dec. 31, 2019 (Dec. 31, 2018 – $2 million net liability) are classified as Level II fair value measurements. The significant changes in other net risk management assets during the year ended Dec. 31, 2019, are primarily attributable to favourable market prices on existing contracts. IV. Other Financial Assets and Liabilities The fair value of financial assets and liabilities measured at other than fair value is as follows: Fair value (1) Total Level I Level II Level III Total value (1) Exchangeable securities - Dec. 31, 2019 — 342 — 342 326 Long-term debt - Dec. 31, 2019 — 3,157 — 3,157 3,070 Long-term debt - Dec. 31, 2018 — 3,181 — 3,181 3,204 (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, 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 21) 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 14 above for fair value Level III valuation techniques used. In some instances, a difference may arise between the fair value of a financial instrument at initial recognition (the “transaction price”) and the amount calculated through a valuation model. This unrealized gain or loss at inception is recognized in net earnings (loss) only if the fair value of the instrument is evidenced by a quoted market price in an active market, observable current market transactions that are substantially the same, or a valuation technique that uses observable market inputs. Where these criteria are not met, the difference is deferred on the Consolidated Statements of Financial Position in risk management assets or liabilities, and is recognized in net earnings (loss) over the term of the related contract. The difference between the transaction price and the fair value determined using a valuation model, yet to be recognized in net earnings, and a reconciliation of changes is as follows: As at Dec. 31 2019 2018 2017 Unamortized net gain at beginning of year 49 105 148 New inception gains (losses) 3 (14) 12 Change in foreign exchange rates — 5 (7) Amortization recorded in net earnings during the year (43) (47) (48) Unamortized net gain at end of year 9 49 105

Risk Management Activities (Not

Risk Management Activities (Notes)	12 Months Ended
	Dec. 31, 2019
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, 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 As at Dec. 31, 2018 Cash flow Not Total Commodity risk management Current 59 — 59 Long-term 628 (8) 620 Net commodity risk management assets (liabilities) 687 (8) 679 Other Current — (3) (3) Long-term — 1 1 Net other risk management liabilities — (2) (2) Total net risk management assets (liabilities) 687 (10) 677 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 2019 2018 Current Long-term Current Long-term Current Long-term Current Long-term Gross amounts recognized 316 631 (191) (100) 224 657 (116) (42) Gross amounts set-off (140) (42) 140 42 (53) (6) 53 6 Net amounts as included in the 176 589 (51) (58) 171 651 (63) (36) 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 coal plant 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, 2019, associated with the Corporation’s proprietary trading activities was $1 million (2018 - $2 million, 2017 - $5 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, 2019, associated with the Corporation’s commodity derivative instruments used in generation hedging activities was $25 million (2018 - $18 million, 2017 - $16 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, 2019, associated with these transactions was $8 million (2018 - $13 million, 2017 - $5 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 2019 2018 Type Notional Notional Notional Notional Electricity (MWh) 222 — 2,128 — During 2019, unrealized pre-tax gains of $1 million (2018 - $4 million, 2017 - $2 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 2019 2018 Type Notional Notional Notional Notional Electricity (MWh) 16,097 7,204 58,885 37,023 Natural gas (GJ) 38,062 55,023 80,413 110,488 Transmission (MWh) — 1,818 29 11,163 Emissions (MWh) 184 138 — — Emissions (tonnes) 2,436 2,446 3,134 2,948 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 represents 11 per cent of the Corporation’s debt as at Dec. 31, 2019 (2018 – 14 per cent). Interest rate risk is managed with the use of derivatives. No derivatives related to interest rate risk were outstanding as at Dec. 31, 2019, 2018 or 2017. 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. 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 as 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 (2018 - US$400 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 2019 2018 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign Exchange Forward Contracts - foreign-denominated receipts/expenditures 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 USD and AUD 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. In early 2017, the Corporation revised its hedging strategies related to cash flows from its foreign operations. These foreign currency contracts became part of the Corporation's revised strategy, as opposed to a separate hedge program. 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 2019 2018 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign exchange forward contracts – foreign-denominated receipts/expenditures AUD286 CAD266 — 2020 - 2023 AUD218 CAD205 (5) 2019-2022 USD108 CAD139 (4) 2020 - 2023 USD164 CAD214 (7) 2019-2022 Foreign exchange forward contracts – foreign-denominated debt CAD191 USD150 6 2022 CAD124 USD100 10 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 (2018 and 2017 - 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 2019 2018 2017 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 (18) 2 (13) — (5) — AUD (6) — (7) — (7) — Total (24) 2 (20) — (12) — (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, 2019: Investment grade (Per cent) Non-investment grade (Per cent) Total (Per cent) Total Trade and other receivables (1) 85 15 100 462 Long-term finance lease receivable 100 — 100 176 Risk management assets (1) 99 1 100 806 Loan receivable (2) — 100 100 47 Total 1,491 (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 21 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 historical rates of default by segment of trade receivables as well as 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, 2019. The Corporation’s maximum exposure to credit risk at Dec. 31, 2019, 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, 2019, was $5 million (2018 - $13 million). 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, 2019, TransAlta maintains investment grade ratings from one credit rating agency and below investment grade ratings from three credit rating agencies. Between 2020 and 2022, the Corporation has approximately $1,217 million of debt maturing, comprised of approximately $920 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments. For the debt maturing in 2020, we expect to utilize our existing cash and credit facilities and we expect to refinance the debt maturing in 2022. Refer to Note 4(F) and 24 for further details. 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: 2020 2021 2022 2023 2024 2025 and thereafter Total Accounts payable and accrued liabilities 413 — — — — — 413 Long-term debt (1) 494 98 625 372 105 1,410 3,104 Exchangeable securities (2) — — — — — 350 350 Commodity risk management assets (89) (89) (143) (139) (135) (97) (692) Other risk management (assets) liabilities 1 — (6) 2 — (1) (4) Lease obligations 19 14 9 6 4 90 142 Interest on long-term debt and lease obligations (3) 161 138 128 98 87 671 1,283 Interest on exchangeable securities (2, 3) 25 25 25 24 24 — 123 Dividends payable 37 — — — — — 37 Total 1,061 186 638 363 85 2,423 4,756 (1) Excludes impact of hedge accounting. (2) Assumes the debentures will be exchanged on Jan. 1, 2025. Refer to Note 24 for further details. (3) 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 2020 2021 2022 2023 2024 2025 and thereafter Cash flow hedges Foreign Currency Forward Contracts Notional amount ($ millions) CAD/USD 116 8 — — — — Average Exchange Rate CAD/USD 0.7672 0.7686 — — — — Commodity Derivative Instruments Electricity Notional amount (thousands MWh) 3,465 3,424 3,329 3,329 3,338 2,628 Average Price ($ per MWh) 67.82 71.06 73.55 75.39 77.28 79.20 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, 2019 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 19 MMWh 678 Risk management assets 47 Foreign currency risk Net investment hedges Foreign-denominated debt USD370 CAD483 Credit facilities, long-term debt and finance lease obligations 21 As at Dec. 31, 2018 Notional amount Carrying amount Line item in the statement of financial position Change in fair Commodity price risk Cash flow hedges Physical power sales 23 MMWh 687 Risk management assets 60 Foreign currency risk Net investment hedges Foreign-denominated debt USD400 CAD546 Credit facilities, long-term debt and finance lease obligations (41) The impact of the hedged items on the statement of financial position is as follows: As at Dec. 31, 2019 2019 2018 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 47 527 60 508 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) Net investment hedges Net investment in foreign 21 (21) (41) 17 (1) Included in AOCI The hedging gain recognized in OCI before tax is equal to the change in fair value used for measuring effectiveness. 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, 2019 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 77 Revenue (59) Revenue — Forward starting interest rate swaps — Interest expense 6 Interest expense — OCI impact 77 OCI impact (53) Net earnings impact — Over the next 12 months, the Corporation estimates that approximately $68 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, 2018 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 (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 — Year ended Dec. 31, 2017 (as reported under IAS 39) 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 163 Revenue (172) Revenue — Foreign exchange forwards on project hedges (1) Property, plant, and equipment — Foreign exchange (gain) loss — Foreign exchange forwards on US debt — Foreign exchange (gain) loss 3 Foreign exchange (gain) loss — Cross-currency swaps (26) Foreign exchange (gain) loss 24 Foreign exchange (gain) loss — Forward starting interest rate swaps — Interest expense 7 Interest expense — OCI impact 136 OCI impact (138) Net earnings impact — During December 2016, the Corporation entered into a new contract with the Ontario IESO relating to the Mississauga cogeneration facility that principally terminated the contract effective Jan. 1, 2017. Accordingly, in 2017 the Corporation reclassified unrealized pre-tax cash flow commodity hedge losses of $31 million and $15 million of unrealized pre-tax cash flow foreign exchange hedge gains from AOCI to net earnings due to hedge de-designations for accounting purposes. The cash flow hedges were in respect of future gas purchases expected to occur between 2017 and 2018. See Note 9(B) for further details. II. Effect of Non-Hedges For the year ended Dec. 31, 2019, the Corporation recognized a net unrealized gain of $33 million (2018 - loss of $29 million, 2017 - gain of $45 million) related to commodity derivatives. For the year ended Dec. 31, 2019, a gain of $24 million (2018 - gain of $3 million, 2017 - gain of $28 million) related to foreign exchange and other derivatives was recognized, which is comprised of net unrealized gains of $6 million (2018 - gains of $4 million, 2017 - losses of $2 million) and net realized gains of $18 million (2018 - losses of $1 million, 2017 - gains of $30 million). F. Collateral I. Financial Assets Provided as Collateral At Dec. 31, 2019, the Corporation provided $42 million (2018 – $105 million) in cash and cash equivalents as collateral to regulated clearing agents as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents. Collateral provided is included in accounts receivable in the Consolidated Statements of Financial Position. II. Financial Assets Held as Collateral At Dec. 31, 2019, the Corporation held $3 million (2018 – $17 million) in cash collateral associated with counterparty obligations. Under the terms of the contracts, the Corporation may be obligated to pay interest on the outstanding balances and to return the principal when the counterparties have met their contractual obligations or when the amount of the obligation declines as a result of changes in market value. Interest payable to the counterparties on the collateral received is calculated in accordance with each contract. Collateral held is included in accounts payable in the Consolidated Statements of Financial Position. III. Contingent Features in Derivative Instruments Collateral is posted in the normal course of business based on the 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. As at Dec. 31, 2019, the Corporation had posted collateral of $112 million (Dec. 31, 2018 – $120 million) in the form of letters of credit on derivative instruments in a net liability position. Certain derivative agreements contain credit-risk-contingent features, which if triggered could result in the Corporation having to post an additional $51 million (Dec. 31, 2018 – $120 million) of collateral to its counterparties.

Property, Plant, and Equipment

Property, Plant, and Equipment (Notes)	12 Months Ended
	Dec. 31, 2018
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, 2017 95 5,888 1,982 3,228 1,315 95 370 12,973 Additions (2) — — — 1 — 275 8 284 Additions - finance lease — — — — 10 — — 10 Disposals (3) — — — (1) — (3) (7) Impairment charge (Note 7) — (38) — (11) — — — (49) Revisions and additions to decommissioning and restoration costs — (12) (1) (3) (16) — — (32) Retirement of assets — (47) (17) (6) (16) — (4) (90) Change in foreign exchange rates 2 105 (13) 26 7 4 — 131 Transfers — 41 13 51 39 (174) 12 (18) As at Dec. 31, 2018 94 5,937 1,964 3,286 1,338 200 383 13,202 Adjustments on implementation of IFRS 16 (Note 3) (3) — — — (7) (101) — — (108) Additions (4) — — — — — 407 115 522 Acquisitions (Note 4(D) and 4(J)) (5) — 300 — — — 139 — 439 Disposals (6) (2) (389) (260) — (34) — (19) (704) Impairment (charges) reversals (Note 7) — 448 — (2) (15) — — 431 Revisions and additions to decommissioning and restoration costs — (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 (7) — 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 Accumulated depreciation As at Dec. 31, 2017 — 3,431 1,072 1,037 713 — 142 6,395 Depreciation — 306 79 123 125 — 16 649 Retirement of assets — (56) (13) (2) (12) — — (83) Disposals — — — — (1) — (4) (5) Change in foreign exchange rates — 84 (3) 6 5 — — 92 Transfers — — (7) (3) — — — (10) As at Dec. 31, 2018 — 3,765 1,128 1,161 830 — 154 7,038 Adjustments on implementation of IFRS 16 (Note 3) (3) — — — (3) (43) — — (46) Depreciation — 304 77 136 97 — 16 630 Retirement of assets — (158) (23) (3) (6) — — (190) Disposals (5) — (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 Carrying amount As at Dec. 31, 2017 95 2,457 910 2,191 602 95 228 6,578 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 (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) Includes $7 million related to the acquisition of Big Level. (3) Includes net $33 million transferred to right of use assets and $29 million of finance lease assets that were derecognized on implementation of IFRS 16. Refer to Note 3 for further details. (4) Includes 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. (5) 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. (6) 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 Sunhills 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). (7) Mainly relates to transferring the Pioneer Pipeline and US Wind Projects from assets under construction to coal generation and renewable generation, respectively.

Right of Use Asset (Notes)

Right of Use Asset (Notes)	12 Months Ended
	Dec. 31, 2019
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 and other assets — — 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) Change in foreign exchange rates (1) — — — — (1) Transfers — — — (1) — (1) As at Dec. 31, 2019 58 16 2 25 45 146 (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 farms as a result of revised interpretations of the unit of account / identified asset concepts present in IFRS 16. For the year ended Dec. 31, 2019, TransAlta paid $25 million related to recognized lease liabilities, consisting of $4 million in interest and $21 million in principal repayments. For the year ended Dec. 31, 2019, the Corporation expensed $2 million related to short-term and $1 million related to low value leases. 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 (Notes)

Intangible Assets (Notes)	12 Months Ended
	Dec. 31, 2019
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, 2017 178 314 223 29 744 Additions (1) — — — 53 53 Retirements and disposals (2) — (2) — — (2) Change in foreign exchange rates — 3 — — 3 Transfers 7 24 14 (36) 9 As at Dec. 31, 2018 185 339 237 46 807 Assets transferred to right of use assets on — (5) — — (5) Additions — — — 14 14 Acquisition — 1 — 15 16 Disposals (Note 4(D)) (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 Accumulated amortization As at Dec. 31, 2017 125 188 67 — 380 Amortization 9 32 9 — 50 Retirements and disposals — (1) — — (1) Change in foreign exchange rates — 2 — — 2 Transfers (17) — 20 — 3 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(D)) (9) (1) — — (10) Change in foreign exchange rates — (1) — — (1) Transfers 1 (1) — — — As at Dec. 31, 2019 117 246 107 — 470 Carrying amount As at Dec. 31, 2017 53 126 156 29 364 As at Dec. 31, 2018 68 118 141 46 373 As at Dec. 31, 2019 32 132 143 11 318 (1) Includes $33 million related to the acquisition of Big Level.

Goodwill (Notes)

Goodwill (Notes)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 Hydro 258 259 Wind and Solar 176 175 Energy Marketing 30 30 Total goodwill 464 464 For the purposes of the 2019 annual goodwill impairment review, the Corporation determined the recoverable amounts of the Hydro, Wind and Solar, and Energy Marketing segments by calculating the fair value less costs of disposal using discounted cash flow projections based on the 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. The key assumption 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 2019 models ranged between $5 to $183 per MWh during the forecast period (2018 – $6 to $179 per MWh). Discount rates used for the goodwill impairment calculation in 2019 ranged from 3.6 per cent to 7.0 per cent (2018 – 5.3 per cent to 6.6 per cent). No reasonable possible change in the assumptions would have resulted in an impairment of goodwill.

Other Assets (Notes)

Other Assets (Notes)	12 Months Ended
	Dec. 31, 2019
Disclosure of financial assets [abstract]
Other Assets	Other Assets The components of other assets are as follows: As at Dec. 31 2019 2018 South Hedland prepaid transmission access and distribution costs 67 72 Deferred licence fees 9 11 Project development costs 19 47 Deferred service costs — 12 Long-term prepaids and other assets 56 55 Loan receivable 47 37 Total other assets 198 234 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 include the project costs for Windrise (Note 4(L)) and the US wind development projects (Note 4(B)). Some projects were written off in 2019 and 2018 as they are no longer proceeding (see Note 7(D)). Deferred service costs related to TransAlta’s contracted payments for shared capital projects required at the Genesee Unit 3 and Keephills Unit 3 sites. As part of the Genesee Unit 3 and Keephills Unit 3 swap, these assets were included in the transaction (Note 4(D)). Long-term prepaids and other assets includes: the funded portion of the TransAlta Energy Transition Bill commitments discussed in Note 35(F), the Keephills Unit 3 provincially required transmission deposit which is anticipated to be reimbursed over the next two years to 2021, as long as certain performance criteria are met, and other miscellaneous prepaids and deposits.

Decommissioning and Other Provi

Decommissioning and Other Provisions (Notes)	12 Months Ended
	Dec. 31, 2019
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, 2017 437 33 470 Liabilities incurred 5 17 22 Liabilities settled (31) (10) (41) Accretion 24 — 24 Acquisition of liabilities (Big Level) — 8 8 Revisions in estimated cash flows 2 3 5 Revisions in discount rates (37) — (37) Reversals — (5) (5) Change in foreign exchange rates 7 3 10 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 16 — 16 Reversals — (1) (1) Change in foreign exchange rates (7) — (7) Balance, Dec. 31, 2019 501 45 546 (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, described in Note 3(A)(IV), the discount rates used for the Canadian coal and mining operations decommissioning provisions were changed. The use of a lower inflation rate decreased the corresponding liabilities. Decommissioning and Other Total Balance, Dec. 31, 2018 407 49 456 Current portion 35 35 70 Non-current portion 372 14 386 Balance, Dec. 31, 2019 501 45 546 Current portion 36 22 58 Non-current portion 465 23 488 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 $1.3 billion, which will be incurred between 2020 and 2073. The majority of the costs will be incurred between 2020 and 2050. At Dec. 31, 2019, the Corporation had provided a surety bond in the amount of US$147 million (2018 – US$139 million) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2019, the Corporation had provided letters of credit in the amount of $128 million (2018 – $122 million) in support of future decommissioning obligations at the Alberta 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.

Credit Facilities, Long-Term De

Credit Facilities, Long-Term Debt, and Finance Lease Obligations (Notes)	12 Months Ended
	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Credit Facilities, Long-Term Debt, and Finance Lease Obligations	Credit Facilities, Long-Term Debt and Finance Lease Obligations A. Amounts Outstanding The amounts outstanding are as follows: As at Dec. 31 2019 2018 Carrying Face Interest (1) Carrying Face Interest (1) Credit facilities (2) 220 220 3.5 % 339 339 3.8 % Debentures 647 651 5.8 % 647 651 5.8 % Senior notes (3) 905 914 5.4 % 943 955 5.4 % Non-recourse (4) 1,144 1,157 4.3 % 1,236 1,250 4.4 % Other (5) 154 162 7.1 % 39 39 9.2 % 3,070 3,104 3,204 3,234 Finance lease obligations 142 63 3,212 3,267 Less: current portion of long-term debt (494) (130) Less: current portion of finance lease obligations (19) (18) Total current long-term debt and finance lease (513) (148) Total credit facilities, long-term debt and finance 2,699 3,119 (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, 2019 - US$0.7 billion (Dec. 31, 2018 - US$0.7 billion). (4) Includes US$1 million at Dec. 31, 2019 (Dec. 31, 2018 - US$1 million). (5) Includes US$117 at Dec. 31, 2019 (Dec. 31, 2018 - US$21 million) of tax equity financing. Our credit facilities include the Corporation's $1.3 billion committed syndicated bank credit facility expiring in 2023, TransAlta Renewable's $700 million committed syndicated bank credit facility expiring in 2023 and the Corporation's three bilateral credit facilities totalling $240 million expiring in 2021. The $2.0 billion (Dec. 31, 2018 – $1.8 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. During 2019, the Corporation renewed these credit facilities and TransAlta Renewables' facility was increased by $200 million to $700 million. During 2018, the Corporation's US$200 million committed facility was cancelled and the Corporation's committed syndicated bank credit facility was increased by $250 million. The Corporation has a total of $2.2 billion (Dec. 31, 2018 – $2.0 billion) of committed credit facilities, including TransAlta Renewables’ credit facility of $0.7 billion (Dec. 31, 2018 – $0.5 billion). In total, $1.3 billion (Dec. 31, 2018 – $0.9 billion) is not drawn. At Dec. 31, 2019, the $0.9 billion (Dec. 31, 2018 – $1.1 billion) of credit utilized under these facilities was comprised of actual drawings of $220 million (Dec. 31, 2018 – $339 million) and letters of credit of $690 million (Dec. 31, 2018 – $720 million). The Corporation is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. In addition to the $1.3 billion available under the credit facilities, the Corporation also has $411 million of available cash and cash equivalents and $17 million ($10 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 5.0 per cent to 7.3 per cent and have maturity dates ranging from 2020 to 2030. 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. During 2017, the Corporation's US$400 million 1.90 per cent senior note matured and was paid out using existing liquidity. The repayment was hedged with a currency swap. The maturity value of the bond was $434 million. A total of US$370 million (2018 - US$400 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 2033 and bear interest at rates ranging from 2.95 per cent to 6.03 per cent. 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 $122 million and Lakeswind of $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(J) 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 wind 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 20 29, 10 years from commercial operation of the projects; and Lakeswind - March 31, 2024. TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2019, 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 and TransAlta OCP non-recourse bonds with a carrying value of $1,143 million as at Dec. 31, 2019 (Dec. 31, 2018 - $1,235 million) 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 fourth quarter of 2019. However, funds in these entities that have accumulated since the fourth quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2020. At Dec. 31, 2019, $42 million (Dec. 31, 2018 –$33 million) of cash was subject to these financial restrictions. 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. The Corporation has elected to use letters of credit as at Dec. 31, 2019. Proceeds received from the Big Level and Antrim tax equity financing in the amount of $91 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 outstanding project development costs. C. Security Non-recourse debts totalling $719 million as at Dec. 31, 2019 (Dec. 31, 2018 – $766 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 property, plant and equipment with total carrying amounts of $967 million at Dec. 31, 2019 (Dec. 31, 2018 – $1,021 million) and intangible assets with total carrying amounts of $63 million (Dec. 31, 2018 – $70 million). At Dec. 31, 2019, a non-recourse bond of approximately $119 million (Dec. 31, 2018 – $127 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 $305 million (Dec. 31, 2018 – $342 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 2020 2021 2022 2023 2024 2025 and thereafter Total Principal repayments (1) 494 98 625 372 105 1,410 3,104 Lease obligations 19 14 9 6 4 90 142 (1) Excludes impact of derivatives. E. Restricted Cash At Dec. 31, 2019, the Corporation had $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 the first half of 2020. The Corporation also had $17 million (Dec. 31, 2018 – $35 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 2020. The Corporation had nil (Dec. 31, 2018 – $31 million) restricted cash related to the Kent Hills project financing. 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 (Notes)

Exchangeable Securities (Notes)	12 Months Ended
	Dec. 31, 2019
Exchangeable Securities [Abstract]
Exchangeable Securities	Exchangeable Securities On March 25, 2019, the Corporation announced that it had 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. The remaining $400 million will be invested in October 2020 in exchange for a new series of redeemable, retractable first preferred shares, subject to the satisfaction of certain conditions. A. $350 Million Unsecured Subordinated Debentures As at Dec. 31, 2019 Carrying value Face value Interest Exchangeable debentures – due May 1, 2039 326 350 7% 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, 2019 Description Base fair value Sensitivity Option to exchange – embedded derivative — +35 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 (Notes)	12 Months Ended
	Dec. 31, 2018
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 2019 2018 Defined benefit obligation (Note 30) 268 227 Long-term incentive accruals (Note 29) 4 9 Other 29 51 Total 301 287

Common Shares (Notes)

Common Shares (Notes)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 284.6 3,059 287.9 3,094 Purchased and cancelled under the NCIB (7.7) (83) (3.3) (35) Stock options exercised 0.1 2 — — Issued and outstanding, end of year 277.0 2,978 284.6 3,059 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 2019 2018 Total shares purchased (1) 7,716,300 3,264,500 Average purchase price per share $ 8.80 $ 7.02 Total cost 68 23 Weighted average book value of shares cancelled 83 35 Amount recorded in deficit 15 12 (1) As at Dec. 31, 2019, includes 189,900 (2018 - 204,000) 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 2019 2018 2017 Net earnings (loss) attributable to common shareholders 52 (248) (190) Basic and diluted weighted average number of common shares outstanding (millions) 283 287 288 Net earnings (loss) per share attributable to common shareholders, basic and diluted 0.18 (0.86) (0.66) E. Dividends On Oct. 9, 2019, the Corporation declared a quarterly dividend of $0.04 per common share, payable on Jan. 1, 2020. On Jan. 16, 2020, the Corporation declared a quarterly dividend of $0.0425 per common share, payable on Apr. 1, 2020. 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 rate first preferred shares. As at Dec. 31 2019 2018 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, 2019. 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 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 five five ▪ Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. ▪ Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2019, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over Benchmark (per cent) Convertible to A Fixed 0.67725 March 31, 2021 2.03 B B Floating 0.93575 March 31, 2021 2.03 A C Fixed 1.00675 June 30, 2022 3.10 D D Floating — — 3.10 C E Fixed 1.29850 Sept. 30, 2022 3.65 F F Floating — — 3.65 E G Fixed 1.32500 Sept. 30, 2024 3.80 H H Floating — — 3.80 G B. Dividends The following table summarizes the value of preferred share dividends declared in 2019, 2018 and 2017: Total dividends declared Series 2019 2018 2017 A 5 9 5 B 1 1 1 C 8 14 9 E 9 15 8 G 7 11 7 Total for the year 30 50 30 TransAlta’s capital is comprised of the following: As at Dec. 31 2019 2018 Increase/ Long-term debt (1) 3,212 3,267 (55) Exchangeable securities 326 — 326 Equity Common shares 2,978 3,059 (81) Preferred shares 942 942 — Contributed surplus 42 11 31 Deficit (1,455) (1,496) 41 Accumulated other comprehensive income 454 481 (27) Non-controlling interests 1,101 1,137 (36) Less: available cash and cash equivalents (2) (411) (89) (322) Less: principal portion of restricted cash on TransAlta OCP Bonds (3) (10) (27) 17 Less: fair value asset of hedging instruments on long-term debt (4) (7) (10) 3 Total capital 7,172 7,275 (103) (1) Includes lease obligations, 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 (Notes)

Preferred Shares (Notes)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 284.6 3,059 287.9 3,094 Purchased and cancelled under the NCIB (7.7) (83) (3.3) (35) Stock options exercised 0.1 2 — — Issued and outstanding, end of year 277.0 2,978 284.6 3,059 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 2019 2018 Total shares purchased (1) 7,716,300 3,264,500 Average purchase price per share $ 8.80 $ 7.02 Total cost 68 23 Weighted average book value of shares cancelled 83 35 Amount recorded in deficit 15 12 (1) As at Dec. 31, 2019, includes 189,900 (2018 - 204,000) 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 2019 2018 2017 Net earnings (loss) attributable to common shareholders 52 (248) (190) Basic and diluted weighted average number of common shares outstanding (millions) 283 287 288 Net earnings (loss) per share attributable to common shareholders, basic and diluted 0.18 (0.86) (0.66) E. Dividends On Oct. 9, 2019, the Corporation declared a quarterly dividend of $0.04 per common share, payable on Jan. 1, 2020. On Jan. 16, 2020, the Corporation declared a quarterly dividend of $0.0425 per common share, payable on Apr. 1, 2020. 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 rate first preferred shares. As at Dec. 31 2019 2018 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, 2019. 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 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 five five ▪ Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. ▪ Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2019, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over Benchmark (per cent) Convertible to A Fixed 0.67725 March 31, 2021 2.03 B B Floating 0.93575 March 31, 2021 2.03 A C Fixed 1.00675 June 30, 2022 3.10 D D Floating — — 3.10 C E Fixed 1.29850 Sept. 30, 2022 3.65 F F Floating — — 3.65 E G Fixed 1.32500 Sept. 30, 2024 3.80 H H Floating — — 3.80 G B. Dividends The following table summarizes the value of preferred share dividends declared in 2019, 2018 and 2017: Total dividends declared Series 2019 2018 2017 A 5 9 5 B 1 1 1 C 8 14 9 E 9 15 8 G 7 11 7 Total for the year 30 50 30 TransAlta’s capital is comprised of the following: As at Dec. 31 2019 2018 Increase/ Long-term debt (1) 3,212 3,267 (55) Exchangeable securities 326 — 326 Equity Common shares 2,978 3,059 (81) Preferred shares 942 942 — Contributed surplus 42 11 31 Deficit (1,455) (1,496) 41 Accumulated other comprehensive income 454 481 (27) Non-controlling interests 1,101 1,137 (36) Less: available cash and cash equivalents (2) (411) (89) (322) Less: principal portion of restricted cash on TransAlta OCP Bonds (3) (10) (27) 17 Less: fair value asset of hedging instruments on long-term debt (4) (7) (10) 3 Total capital 7,172 7,275 (103) (1) Includes lease obligations, 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 (Notes)	12 Months Ended
	Dec. 31, 2018
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: 2019 2018 Currency translation adjustment Opening balance, Jan. 1 17 (26) Gains (losses) on translating net assets of foreign operations, net of reclassifications to net earnings, (59) 84 Gains (losses) on financial instruments designated as hedges of foreign operations, net of 21 (41) Balance, Dec. 31 (21) 17 Cash flow hedges Opening balance, Jan. 1 508 562 Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax (1) 19 (54) Balance, Dec. 31 527 508 Employee future benefits Opening balance, Jan. 1 (29) (44) Net actuarial gains (losses) on defined benefit plans, net of tax (2) (26) 15 Balance, Dec. 31 (55) (29) Other Opening balance, Jan. 1 (15) (3) Change in ownership of TransAlta Renewables 1 4 Intercompany investments at FVOCI 17 (16) Balance, Dec. 31 3 (15) Accumulated other comprehensive income 454 481 (1) Net of income tax of $6 million for the year ended Dec. 31, 2019 (2018 - $12 million). (2) Net of income tax of $7 million for the year ended Dec. 31, 2019 (2018 - $5 million).

Share-Based Payment Plans (Note

Share-Based Payment Plans (Notes)	12 Months Ended
	Dec. 31, 2018
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 three three three 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 2019 was $19 million (2018 - $8 million, 2017 - $15 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 $2 million in 2019 (2018 - nil, 2017 - $1 million). C. Stock Option Plans The Corporation is authorized to grant options to purchase up to an aggregate of 13 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 2019, the Corporation granted executive officers of the Corporation a total of 1.4 million stock options with a weighted average exercise price of $5.65 that vest after a three The total options outstanding and exercisable under these stock option plans at Dec. 31, 2019, are outlined below: Options outstanding Range of exercise prices (1) ($ per share) Number of options (millions) Weighted average remaining contractual life (years) Weighted average exercise price ($ per share) 5.00 - 9.00 3.3 4.7 6.34 22.00 - 30.00 0.5 0.1 23.44 5.00 - 30.00 3.8 4.2 8.41 (1) Options currently exercisable as at Dec. 31, 2019.

Cash Flow Information (Notes)

Cash Flow Information (Notes)	12 Months Ended
	Dec. 31, 2019
Disclosure of cash flow statement [Abstract]
Cash Flow Information	Cash Flow Information A. Change in Non-Cash Operating Working Capital Year ended Dec. 31 2019 2018 2017 (Use) source: Accounts receivable 261 58 (228) Prepaid expenses — 19 (75) Income taxes receivable (6) — 8 Inventory (13) (21) (7) Accounts payable, accrued liabilities and provisions (130) (97) 186 Income taxes payable 9 (3) 2 Change in non-cash operating working capital 121 (44) (114) B. Changes in Liabilities from Financing Activities 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 activities 3,325 195 133 (35) 64 (42) (65) 3,575 Balance Net cash flows New leases Dividends declared Foreign exchange impact Other Balance Long-term debt and finance lease 3,707 (540) 10 — 95 (5) 3,267 Dividends payable (common and 34 (86) — 107 — 3 58 Total liabilities from financing activities 3,741 (626) 10 107 95 (2) 3,325

Capital (Notes)

Capital (Notes)	12 Months Ended
	Dec. 31, 2019
Disclosure of notes and other explanatory information [Abstract]
Capital	Capital TransAlta’s capital is comprised of the following: As at Dec. 31 2019 2018 Increase/ Long-term debt (1) 3,212 3,267 (55) Exchangeable securities 326 — 326 Equity Common shares 2,978 3,059 (81) Preferred shares 942 942 — Contributed surplus 42 11 31 Deficit (1,455) (1,496) 41 Accumulated other comprehensive income 454 481 (27) Non-controlling interests 1,101 1,137 (36) Less: available cash and cash equivalents (2) (411) (89) (322) Less: principal portion of restricted cash on TransAlta OCP Bonds (3) (10) (27) 17 Less: fair value asset of hedging instruments on long-term debt (4) (7) (10) 3 Total capital 7,172 7,275 (103) (1) Includes lease obligations, 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). In 2019, Moody's reaffirmed its issuer rating of Ba1 and revised their rating outlook to stable from positive. During 2019, Fitch Ratings downgraded the Corporation below investment grade to BB+ 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 downgraded the Corporation’s Unsecured Debt rating and Issuer Rating to 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 2019 2018 Target Funds from operations before interest to adjusted interest coverage (times) 4.5 4.8 4 to 5 Adjusted funds from operations to adjusted net debt (%) 19.0 20.8 20 to 25 Adjusted net debt to adjusted comparable earnings before interest, taxes, depreciation and amortization (times) 3.9 3.6 3.0 to 3.5 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 obligations (net of capitalized interest) divided by interest on debt, exchangeable securities and lease obligations (net of capitalized interest) plus 50 per cent of dividends paid on preferred shares. 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 Corporation’s goal is to maintain this ratio in a range of 20 to 25 per cent. Adjusted Net Debt to Adjusted Comparable Earnings before Interest, Taxes, Depreciation and Amortization (“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 Corporation’s goal is to maintain this ratio in a range of 3.0 to 3.5 times. At times, the credit ratios may be outside of the specified ranges while the Corporation executes its coal-to-gas transition 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, 2019 and 2018, cash inflows and outflows are summarized below. The Corporation manages variations in working capital using existing liquidity under credit facilities. Year ended Dec. 31 2019 2018 Increase Cash flow from operating activities 849 820 29 Change in non-cash working capital (121) 44 (165) Cash flow from operations before changes in working capital 728 864 (136) Dividends paid on common shares (45) (46) 1 Dividends paid on preferred shares (40) (40) — Distributions paid to subsidiaries’ non-controlling interests (106) (165) 59 Property, plant and equipment expenditures (417) (277) (140) Inflow 120 336 (216) TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2019, $1.3 billion (2018 - $0.9 billion) of the Corporation’s available credit facilities were not drawn. 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.

Commitments and Contingencies (

Commitments and Contingencies (Notes)	12 Months Ended
	Dec. 31, 2019
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 other contractual commitments, either directly or through its interests in joint operations. Approximate future payments under these agreements are as follows: 2020 2021 2022 2023 2024 2025 and thereafter Total Natural gas, transportation and 125 125 120 128 131 1,493 2,122 Transmission 9 5 4 3 — — 21 Coal supply and mining 147 16 16 16 8 14 217 Long-term service agreements 50 22 32 17 15 14 150 Operating leases 4 2 2 2 3 64 77 Growth 535 254 196 270 13 — 1,268 TransAlta Energy Transition Bill 6 6 6 6 — — 24 Total 876 430 376 442 170 1,585 3,879 A. Natural Gas, Transportation and Other Contracts Includes fixed price or volume natural gas purchase and transportation contracts. 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 coal plant. The coal supply agreements allow TransAlta to take delivery of coal at fixed volumes with dates extending to 2020. 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 cessation of coal-fired emissions from the Sheerness coal-fired plant on or before Dec. 31, 2030. 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 (refer to Note 3(A)(I) for further details), operating lease expenses were recognized as incurred in the statement of earnings. During the year ended Dec. 31, 2018, $8 million (2017 - $7 million) was recognized as an expense in respect of operating leases. Sublease payments received during 2019, 2018 and 2017 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: coal-to-gas conversions and repowering Sudance Unit 5, Kaybob cogeneration, Windrise, Windcharger and Skookumchuck and any final costs associated with the Big Level and Antrim 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 Memorandum of Agreement, 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, 2019, the Corporation has funded approximately US$37 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 Alberta Utilities Commission ("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. A more recent decision by the AUC determined the methodology to be used retroactively, which made it possible for the Corporation to estimate the total retroactive potential exposure faced by the Corporation for its non-PPA power generation. The single invoice for the historical adjustments was to be issued in April 2021, with cash settlement expected in June 2021. The current total estimate of exposure based on known data is approximately $12 million. However, the AESO recently requested the AUC approve a pay-as-you-go settlement, instead of issuing a single invoice. This form of settlement would permit the AESO to issue an invoice for each historical year as the line loss factors are recalculated, resulting in invoices being issued as early as April 2020 for settlement in June 2020, a year earlier than anticipated. The Corporation is challenging this request. II. FMG Disputes The Corporation is currently engaged in two disputes with FMG. The first dispute arose as a result of FMG’s attempted termination of the South Hedland PPA on the basis that the conditions to establishing commercial operation under the South Hedland PPA had not been met. TransAlta's view is that all conditions to establishing commercial operation under the terms of the South Hedland PPA had been satisfied in full. TransAlta initiated legal action against FMG, seeking payment 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 is scheduled to proceed to trial beginning June 15, 2020. The second dispute involves FMG’s claims against TransAlta related to the transfer of the Solomon facility to FMG. FMG claims certain amounts related to the condition of the facility while TransAlta claims certain outstanding costs that should be reimbursed. A trial date for this matter has not yet been scheduled but it will likely not occur until 2021. 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 on such date, and Brookfield BRP Holdings (Canada), as defendants. Mangrove is alleging, among other things, oppression by the Corporation and the named Directors and is seeking to set aside the 2019 Brookfield Investment. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter is scheduled to proceed to trial beginning Sept. 14, 2020. IV. Keephills 1 Superheater Keephills Unit 1 was taken offline from Mar. 17, 2015 to May 17, 2015 as a result of a large leak in the secondary superheater. TransAlta claimed force majeure under the PPA. ENMAX Energy Corporation, the purchaser under the PPA at the time, did not dispute the force majeure but the Balancing Pool is attempting to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. TransAlta denied the Balancing Pool had the right to do so. The Alberta Court of Queen’s Bench confirmed that the Balancing Pool has a right under the PPA to commence an arbitration, independent of the PPA buyer. On Sept. 4, 2019, the Alberta Court of Appeal upheld the lower court’s decision. TransAlta sought permission to appeal the Alberta's Court of Appeal’s decision to the Supreme Court of Canada. The application was denied and the matter will now proceed to arbitration, with a hearing potentially sometime in 2020. V. 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 mine. The Balancing Pool filed a statement of intent to participate as an intervener because it disagrees that, amongst other things, the mine decommissioning costs should be included. TransAlta anticipates it will receive payment from the Balancing Pool in 2020 for its decommissioning costs; however, the amount is uncertain. VI. Hydro PPA Renewable Energy Credits The Balancing Pool claims to be entitled to emissions performance credits ("EPCs"), valued at approximately $27 million, earned by the Hydro plants under the Carbon Competitiveness Incentive Regulation in 2018 and 2019. 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. The Corporation anticipates this dispute will be resolved by the end of 2021.

Segment Disclosures (Notes)

Segment Disclosures (Notes)	12 Months Ended
	Dec. 31, 2019
Disclosure of entity's operating segments [Abstract]
Segments Disclosures	Segment Disclosures A. Description of Reportable Segments The Corporation has eight reportable segments as described in Note 1. B. Reported Segment Earnings (Loss) and Segment Assets I. Earnings Information Year ended Dec. 31, 2019 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Revenues 816 571 209 160 312 156 129 (6) 2,347 Fuel, carbon compliance and 570 416 74 9 16 7 — (6) 1,086 Gross margin 246 155 135 151 296 149 129 — 1,261 Operations, maintenance and 138 67 44 37 50 36 30 73 475 Depreciation and amortization 233 83 41 48 124 32 2 27 590 Asset impairment charge 15 (10) — — — 2 — 18 25 Gain on termination of (88) — — — — — — — (88) Taxes, other than income taxes 13 3 1 — 8 3 — 1 29 Termination of Sundance B and (56) — — — — — — — (56) Net other operating expense (40) — (1) — (10) — — 2 (49) Operating income (loss) 31 12 50 66 124 76 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 Year ended Dec. 31, 2018 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Revenues 912 442 232 165 282 156 67 (7) 2,249 Fuel, carbon compliance and 666 314 96 8 17 6 — (7) 1,100 Gross margin 246 128 136 157 265 150 67 — 1,149 Operations, maintenance and 171 61 48 37 50 38 24 86 515 Depreciation and amortization 241 74 43 49 110 30 2 25 574 Asset impairment charge 38 — — — 12 — — 23 73 Taxes, other than income taxes 13 5 1 — 8 3 — 1 31 Termination of Sundance B and (157) — — — — — — — (157) Net other operating income (41) — — — (6) — — — (47) Operating income (loss) (19) (12) 44 71 91 79 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) Year ended Dec. 31, 2017 Canadian US Canadian Australian Wind Hydro Energy Corporate Total Revenues 999 435 261 135 287 121 69 — 2,307 Fuel, carbon compliance and 585 293 101 14 17 6 — — 1,016 Gross margin 414 142 160 121 270 115 69 — 1,291 Operations, maintenance and 192 51 50 31 48 37 24 84 517 Depreciation and amortization 317 73 38 37 111 31 2 26 635 Asset impairment reversals 20 — — — — — — — 20 Taxes, other than income taxes 13 4 1 — 8 3 — 1 30 Net other operating income (40) — (9) — — — — — (49) Operating income (loss) (88) 14 80 53 103 44 43 (111) 138 Finance lease income — — 11 43 — — — — 54 Net interest expense (247) Foreign exchange loss (1) Gain on sale of assets 2 Earnings before income taxes (54) II. Selected Consolidated Statements of Financial Position Information As at Dec. 31, 2019 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total PP&E 2,540 352 392 489 1,947 469 1 17 6,207 Right of use assets 68 — — 4 56 6 — 12 146 Intangible assets 41 6 2 37 173 5 9 45 318 Goodwill — — — — 176 258 30 — 464 As at Dec. 31, 2018 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total PP&E 2,587 332 391 554 1,799 481 1 19 6,164 Intangible assets 81 7 4 41 173 4 11 52 373 Goodwill — — — — 175 259 30 — 464 III. Selected Consolidated Statements of Cash Flows Information Additions to non-current assets are as follows: Year ended Dec. 31, 2019 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Additions to non-current assets: PP&E 114 8 36 6 229 23 — 1 417 Intangible assets 2 — — — — — — 12 14 Year ended Dec. 31, 2018 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Additions to non-current assets: PP&E 101 14 21 6 117 16 — 2 277 Intangible assets 3 — — — — — — 17 20 Year ended Dec. 31, 2017 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Additions to non-current assets: PP&E 116 35 31 114 20 16 — 6 338 Intangible assets 5 1 — 29 — — — 16 51 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 2019 2018 2017 Depreciation and amortization expense on the Consolidated Statements of 590 574 635 Depreciation included in fuel, carbon compliance and purchased power (Note 6) 119 136 73 Depreciation and amortization on the Consolidated Statements of Cash Flows 709 710 708 C. Geographic Information I. Revenues Year ended Dec. 31 2019 2018 2017 Canada 1,460 1,573 1,663 US 727 511 509 Australia 160 165 135 Total revenue 2,347 2,249 2,307 II. Non-Current Assets Property, plant and Right of use assets Intangible assets Other assets Goodwill As at Dec. 31 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 Canada 4,854 4,953 109 — 213 273 75 101 418 417 US 863 657 33 — 68 59 47 50 46 47 Australia 490 554 4 — 37 41 76 83 — — Total 6,207 6,164 146 — 318 373 198 234 464 464 D. Significant Customer During the year ended Dec. 31, 2019, sales to one customer represented 11 per cent of the Corporation’s total revenue (2018 - one customer represented 19 per cent).

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Revenue recognition	Revenue Recognition I. Revenue from Contracts with Customers - 2019 and 2018 Policy The Corporation adopted IFRS 15 Revenue from Contracts with Customers (IFRS 15) with an initial adoption date of Jan. 1, 2018. The Corporation elected to adopt IFRS 15 retrospectively with the modified retrospective method of transition practical expedient and elected to apply IFRS 15 only to contracts that are active at the date of initial adoption. Comparative information has not been restated and is reported under IAS 18 Revenue (IAS 18). Refer to section III below for the accounting policy for years prior to 2018. 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 which 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 standalone 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. III. Revenue Recognition Policy Prior to 2018 The majority of the Corporation’s revenues are derived from the sale of physical power, the leasing of power facilities and from energy marketing and trading activities. Revenues are measured at the fair value of the consideration received or receivable. Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components: fixed capacity payments for availability, energy payments for generation of electricity, incentives or penalties for exceeding or not meeting availability targets, excess energy payments for power generation above committed capacity, and ancillary services. Each component is recognized when: i) output, delivery or satisfaction of specific targets is achieved, all as governed by contractual terms; ii) the amount of revenue can be measured reliably; iii) it is probable that the economic benefits will flow to the Corporation; and iv) the costs incurred or to be incurred in respect of the transaction can be measured reliably. Revenue from the rendering of services is recognized when criteria ii), iii) and iv) above are met and when the stage of completion of the transaction at the end of the reporting period can be measured reliably. Revenues from non-contracted capacity are comprised of energy payments, at market prices, for each megawatt hour (“MWh”) produced, and are recognized upon delivery.
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 Effective Jan. 1, 2018, the Corporation adopted IFRS 9 Financial Instruments ("IFRS 9"). In accordance with the transition provisions of the standard, the Corporation elected to not restate prior periods. Refer to section III below for information on its prior accounting policy. The Corporation's accounting policies under IFRS 9 are outlined below. 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 "passthrough" 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. III. Financial Instruments and Hedges Accounting Policy Prior to 2018 Financial Instruments Financial assets and financial liabilities, including derivatives and certain non-financial derivatives, are recognized on the Consolidated Statements of Financial Position when the Corporation becomes a party to the contract. All financial instruments, except for certain non-financial derivative contracts that meet the Corporation’s own use requirements, are measured at fair value upon initial recognition. Measurement in subsequent periods depends on whether the financial instrument has been classified as: at fair value through profit or loss, available-for-sale, held-to-maturity, loans and receivables, or other financial liabilities. Classification of the financial instrument is determined at inception depending on the nature and purpose of the financial instrument. Financial assets and financial liabilities classified or designated as at fair value through profit or loss are measured at fair value with changes in fair values recognized in net earnings. Financial assets classified as either held-to-maturity or as loans and receivables, and other financial liabilities, are measured at amortized cost using the effective interest method of amortization. Other financial assets are those non-derivative financial assets that are designated as such or that have not been classified as another type of financial asset, and are measured at fair value through OCI. Other financial assets are measured at cost if fair value is not reliably measurable. Financial assets are assessed for impairment on an ongoing basis and at reporting dates. An impairment may exist if an incurred loss event has arisen that has an impact on the recoverability of the financial asset. Factors that may indicate an incurred loss event and related impairment may exist include, for example, if a debtor is experiencing significant financial difficulty, or a debtor has entered or it is probable that they will enter, bankruptcy or other financial reorganization. The carrying amount of financial assets, such as receivables, is reduced for impairment losses through the use of an allowance account, and the loss is recognized in net earnings. 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 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. Derivative instruments that are embedded in financial or non-financial contracts that are not already required to be recognized at fair value are treated and recognized as separate derivatives if their risks and characteristics are not closely related to their host contracts and the contract is not measured at fair value. Changes in the fair values of these and other derivative instruments are recognized in net earnings with the exception of the effective portion of i) derivatives designated as cash flow hedges and ii) hedges of foreign currency exposure of a net investment in a foreign operation, each of which is recognized in OCI. Transaction costs are expensed as incurred for financial instruments classified or designated as at fair value through profit or loss. 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. 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 hedging relationship qualifies for hedge accounting if, at inception, it is formally designated and documented as a hedge, and the hedge is expected to be highly effective at inception and on an ongoing basis. 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 accounted for on the Consolidated Statements of Financial Position at fair value, 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. Hedge effectiveness for fair value hedges is achieved if changes in the fair value of the derivative are highly effective at offsetting changes in the fair value of the item hedged. If hedge accounting is discontinued, the carrying amount of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying amount of the hedged item are amortized to net earnings over the remaining term of the original hedging relationship. The Corporation primarily uses interest rate swaps as fair value hedges to manage the ratio of floating rate versus fixed rate debt. Interest rate swaps require the periodic exchange of payments without the exchange of the notional principal amount on which the payments are based. Interest expense on the debt is adjusted to include the payments made or received under the interest rate swaps. 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. Hedge effectiveness is achieved if the derivative’s cash flows are highly effective at offsetting the cash flows of the hedged item and the timing of the cash flows is similar. All components of each derivative’s change in fair value are included in the assessment of cash flow hedge effectiveness. If hedge accounting is discontinued, the amounts previously recognized in AOCI are reclassified to net earnings during the periods when the variability in the cash flows of the hedged item affects net earnings. Gains and losses on derivatives are reclassified to net earnings from AOCI immediately when the forecasted transaction is no longer expected to occur within the time period specified in the hedge documentation. The Corporation primarily uses physical and financial swaps, forward sales contracts, futures contracts and options as cash flow hedges to hedge the Corporation’s exposure to fluctuations in electricity and natural gas prices. If hedging criteria are met, the fair values of the hedges are recorded in risk management assets or liabilities with changes in value being reported in OCI. Gains and losses on these derivatives are recognized, on settlement, in net earnings in the same period and financial statement caption as the hedged exposure. The Corporation also uses foreign currency forward contracts as cash flow hedges to hedge the foreign exchange exposures resulting from highly probable forecasted project-related costs denominated in foreign currencies. If the hedging criteria are met, changes in fair value are reported in OCI with the fair value being reported in risk management assets or liabilities, as appropriate. Upon settlement of the derivative, any gain or loss on the forward contracts is included in the cost of the asset acquired or liability incurred. The Corporation uses forward starting interest rate swaps as cash flow hedges to hedge exposures to anticipated changes in interest rates for forecasted issuances of debt. If the hedging criteria are met, changes in fair value are reported in OCI with the fair value being reported in risk management assets or liabilities, as appropriate. When the swaps are closed out on issuance of the debt, the resulting gains or losses recorded in AOCI are amortized to net earnings over the term of the swap. If no debt is issued, the gains or losses are recognized in net earnings immediately. 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. The Corporation primarily uses foreign currency forward contracts and foreign-denominated debt to hedge exposure to changes in the carrying values of the Corporation’s net investments in foreign operations that result from changes in foreign exchange rates.
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: Coal generation 2-10 years Pipeline 50 years Gas generation 2-30 years Hydro generation 2-60 years Wind generation 2-30 years Mining property and equipment 2-10 years Capital spares and other 2-60 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.
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.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 Benefits The 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)). 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. 2019 Lease Policy 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 obligations in the Consolidated Statements of Earnings (loss); and ▪ Recognizes the principal repayments on lease obligations as financing activities and interest payments on lease obligations as operating activities in the Consolidated Statements of Cash Flow. 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.
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. 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 2017 to 2019 is found in Notes 7, 17 and 20. II. 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. III. Income Taxes Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of the jurisdictions in which the 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 11 for further details on the impacts of the Corporation’s tax policies. IV. 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 14. 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. V. 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. VI. Provisions for Decommissioning and Restoration Activities TransAlta recognizes provisions for decommissioning and restoration obligations as outlined in Note 2(N) and Note 22. 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 2019 in respect of decommissioning and restoration provisions can be found in Note 3(A)(IV) and Notes 7 and 22. VII. Useful Life of PP&E Each significant component of an item of PP&E is depreciated over its estimated useful life. Estimated useful lives are determined based on current facts and past experience, and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological obsolescence and regulations. The useful lives of PP&E are reviewed at least annually to ensure they continue to be appropriate. Information on changes in useful lives of facilities is disclosed in Note 3(A)(IV). VIII. 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 30 for disclosures on employee future benefits. IX. 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 and 22 with respect to other provisions. X. Revenue from Contracts with Customers Where contracts contain multiple promises for goods or services, management exercises judgment in determining whether goods or services constitute distinct goods or services or a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer. The determination of a performance obligation affects whether the transaction price is recognized at a point in time or over time. Management considers both the mechanics of the contract and the economic and operating environment of the contract in determining whether the goods or services in a contract are distinct. In determining the transaction price and estimates of variable consideration, management considers 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 standalone selling price, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions. The satisfaction of performance obligations requires management to make judgments as to when control of the underlying good or service transfers to the customer. Determining when a performance obligation is satisfied affects the timing of revenue recognition. Management considers both customer acceptance of the good or service, and the impact of laws and regulations such as certification requirements, in determining when this transfer occurs. Management also applies judgment in determining whether the invoice practical expedient permits recognition of revenue at the invoiced amount, if that invoiced amount corresponds directly with the entity's performance to date. XI. Classification of Joint Arrangements Upon entering into a joint arrangement, the 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.

Significant Accounting Polici_3

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
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: Coal generation 2-10 years Pipeline 50 years Gas generation 2-30 years Hydro generation 2-60 years Wind generation 2-30 years Mining property and equipment 2-10 years Capital spares and other 2-60 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, 2017 95 5,888 1,982 3,228 1,315 95 370 12,973 Additions (2) — — — 1 — 275 8 284 Additions - finance lease — — — — 10 — — 10 Disposals (3) — — — (1) — (3) (7) Impairment charge (Note 7) — (38) — (11) — — — (49) Revisions and additions to decommissioning and restoration costs — (12) (1) (3) (16) — — (32) Retirement of assets — (47) (17) (6) (16) — (4) (90) Change in foreign exchange rates 2 105 (13) 26 7 4 — 131 Transfers — 41 13 51 39 (174) 12 (18) As at Dec. 31, 2018 94 5,937 1,964 3,286 1,338 200 383 13,202 Adjustments on implementation of IFRS 16 (Note 3) (3) — — — (7) (101) — — (108) Additions (4) — — — — — 407 115 522 Acquisitions (Note 4(D) and 4(J)) (5) — 300 — — — 139 — 439 Disposals (6) (2) (389) (260) — (34) — (19) (704) Impairment (charges) reversals (Note 7) — 448 — (2) (15) — — 431 Revisions and additions to decommissioning and restoration costs — (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 (7) — 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 Accumulated depreciation As at Dec. 31, 2017 — 3,431 1,072 1,037 713 — 142 6,395 Depreciation — 306 79 123 125 — 16 649 Retirement of assets — (56) (13) (2) (12) — — (83) Disposals — — — — (1) — (4) (5) Change in foreign exchange rates — 84 (3) 6 5 — — 92 Transfers — — (7) (3) — — — (10) As at Dec. 31, 2018 — 3,765 1,128 1,161 830 — 154 7,038 Adjustments on implementation of IFRS 16 (Note 3) (3) — — — (3) (43) — — (46) Depreciation — 304 77 136 97 — 16 630 Retirement of assets — (158) (23) (3) (6) — — (190) Disposals (5) — (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 Carrying amount As at Dec. 31, 2017 95 2,457 910 2,191 602 95 228 6,578 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 (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) Includes $7 million related to the acquisition of Big Level. (3) Includes net $33 million transferred to right of use assets and $29 million of finance lease assets that were derecognized on implementation of IFRS 16. Refer to Note 3 for further details. (4) Includes 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. (5) 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. (6) 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 Sunhills 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

Accounting Changes - (Tables)

Accounting Changes - (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of changes in accounting policies, accounting estimates and errors [Abstract]
Reconciliation of operating lease liabilities at date of initial application of IFRS 16	The following table reconciles the Corporation's operating lease commitments at Dec. 31, 2018, as previously disclosed in the Corporation’s 2018 annual consolidated financial statements, to the lease obligations recognized on initial application of IFRS 16 and included in credit facilities, long-term debt and lease obligations on the Consolidated Statements of Financial Position as at Jan. 1, 2019: Non-cancellable operating lease commitments disclosed at Dec. 31, 2018 80 Less: Exemption for low-value leases (1) Add: Extension and termination options reasonably certain to be exercised 4 Undiscounted lease liability 83 Discounted using the incremental borrowing rate at Jan. 1, 2019 (31) New lease liabilities recognized as at Jan. 1, 2019 52 Add: 2018 finance lease obligations 63 Less: 2018 finance lease obligations that do not meet the IFRS 16 definition of a lease (32) Lease liabilities as at Jan. 1, 2019 83

Significant Events (Tables)

Significant Events (Tables)	12 Months Ended
	Dec. 31, 2019
Significant Events [Abstract]
Description of nature and financial effect of business combinations during period	Consequently, the acquisition has been accounted for as an asset acquisition, with the following carrying amounts assigned based on relative fair values:Working capital11  Property, plant and equipment308  Other assets3  Other liabilities(2) Decommissioning and other provisions(19) Total acquisition cost301

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
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 energy marketing and trading 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, 2019 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Revenues from contracts with 395 10 205 87 244 142 — — 1,083 Revenue from leases (1) 65 — — 65 — — — — 130 Revenue from derivatives (17) 160 2 — 18 — 129 4 296 Government incentives — — — — 8 — — — 8 Revenue from other (2) 373 401 2 8 42 14 — (10) 830 Total revenue 816 571 209 160 312 156 129 (6) 2,347 Revenues from contracts with customers Timing of revenue recognition At a point in time 41 10 — — 27 — — — 78 Over time 354 — 205 87 217 142 — — 1,005 Total revenue from contracts 395 10 205 87 244 142 — — 1,083 (1) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases. (2) Includes merchant revenue and other miscellaneous. Year ended Dec. 31, 2018 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Revenues from contracts with 517 9 224 91 206 132 — — 1,179 Revenue from leases (1) 68 — — 68 27 7 — — 170 Revenue from derivatives (1) 115 4 — (20) — 67 — 165 Government incentives — — — — 16 — — — 16 Revenue from other (2) 328 318 4 6 53 17 — (7) 719 Total revenue 912 442 232 165 282 156 67 (7) 2,249 Revenues from contracts with customers Timing of revenue recognition At a point in time 38 9 — — 18 — — — 65 Over time 479 — 224 91 188 132 — — 1,114 Total revenue from contracts with customers 517 9 224 91 206 132 — — 1,179 (1) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases (2017 - $247 million). (2) Includes merchant revenue and other miscellaneous.
Changes In Contract Liabilities	The Corporation has recognized the following revenue-related contract liabilities: Contract liabilities 2019 2018 Balance, beginning of the year 88 62 IFRS 16 and 15 transition adjustments (1) 15 17 Amounts transferred to revenue included in opening balance (10) (10) Consideration received 5 13 Increases due to interest accrued and expensed during the period 5 6 Contract termination associated with the purchase of Keephills 3 (Note 4(D)) (88) — Balance, end of year 15 88 Current portion 1 8 Long-term portion 14 80

Expenses by Nature (Tables)

Expenses by Nature (Tables)	12 Months Ended
	Dec. 31, 2019
Analysis of income and expense [abstract]
Expenses classified by nature	Expenses classified by nature are as follows: Year ended Dec. 31 2019 2018 2017 Fuel and Operations, Fuel and Operations, Fuel and Operations, Fuel (1) 669 — 656 — 685 — Purchased power 246 — 210 — 162 — Mine depreciation 119 — 136 — 73 — Salaries and benefits (1) 52 228 98 245 96 248 Other operating expenses — 247 — 270 — 269 Total 1,086 475 1,100 515 1,016 517

Finance Lease Receivables (Tabl

Finance Lease Receivables (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of recognised finance lease as assets by lessee [abstract]
Disclosure of recognised finance lease	Amounts receivable under the Corporation’s finance leases associated with the Poplar Creek cogeneration facility and in 2018, the Fort Saskatchewan cogeneration facility are as follows: As at Dec. 31 2019 2018 Minimum Present value of Minimum Present value of Within one year 20 20 30 29 Second to fifth years inclusive 80 74 80 74 More than five years 120 97 140 112 220 191 250 215 Less: unearned finance lease income 29 — 35 — Total finance lease receivables 191 191 215 215 Included in the Consolidated Statements of Financial Position as: Current portion of finance lease receivables (Note 13) 15 24 Long-term portion of finance lease receivables 176 191 191 215

Net Other Operating (Income) _2

Net Other Operating (Income) Losses (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 2017 Alberta Off-Coal Agreement (40) (40) (40) Mississauga cogeneration facility NUG Contract (1) — (9) Insurance recoveries (10) (7) — Other expenses 2 — — Net other operating income (49) (47) (49)

Net Interest Expense (Tables)

Net Interest Expense (Tables)	12 Months Ended
	Dec. 31, 2019
Analysis of income and expense [abstract]
Components of net interest expense	The components of net interest expense are as follows: Year ended Dec. 31 2019 2018 2017 Interest on debt 161 184 218 Interest on exchangeable securities (Note 24) 20 — — Interest income (13) (11) (7) Capitalized interest (Note 17) (6) (2) (9) Loss on redemption of bonds (Note 23) — 24 6 Interest on finance lease obligations 4 3 3 Credit facility fees, bank charges and other interest 15 13 18 Tax shield on tax equity financing (Note 23) (1) (35) — — Other (2) 10 15 (3) Accretion of provisions (Note 22) 23 24 21 Net interest expense 179 250 247 (1) Relates to the tax benefit associated with bonus tax depreciation claimed in 2019 on the Big Level and Antrim wind 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, 2019
Income Taxes [Abstract]
Rate reconciliations	Rate Reconciliations Year ended Dec. 31 2019 2018 2017 Earnings before income taxes 193 (96) (54) Net earnings attributable to non-controlling interests not subject to tax (26) (19) (35) Adjusted earnings before income taxes 167 (115) (89) Statutory Canadian federal and provincial income tax rate (%) 26.5 % 26.8 % 26.8 % Expected income tax expense (recovery) 44 (31) (24) Increase (decrease) in income taxes resulting from: Differences in effective foreign tax rates 5 (3) (11) Writedown (reversal of writedown) of deferred income tax assets (9) 27 (15) Statutory and other rate differences (31) — 110 Other 8 1 4 Income tax expense (recovery) 17 (6) 64 Effective tax rate (%) 10 % 5 % 72 %
Components of income tax expense	The components of income tax expense are as follows: Year ended Dec. 31 2019 2018 2017 Current income tax expense (1) 35 28 79 Deferred income tax expense (recovery) related to the origination and reversal of 22 (61) (110) Deferred income tax expense resulting from changes in tax rates or laws (2,3) (31) — 110 Deferred income tax expense (recovery) arising from the writedown (reversal of writedown) of deferred income tax assets (4) (9) 27 (15) Income tax expense (recovery) 17 (6) 64 Year ended Dec. 31 2019 2018 2017 Current income tax expense 35 28 79 Deferred income tax recovery (18) (34) (15) Income tax expense (recovery) 17 (6) 64 (1) During 2017, the Corporation recognized current tax expense of $56 million due to the disposition of the Solomon facility Nov. 1, 2017. (2) In 2019, the Corporation recognized a deferred income tax recovery of $31 million related to a decrease in the Alberta corporate tax rate from 12 per cent to 8 per cent. The tax decrease is phased in as follows: 11 per cent effective July 1, 2019, 10 per cent effective January 1, 2020, 9 per cent effective January 1, 2021, and 8 per cent effective January 1, 2022. (3) On Dec. 22, 2017, the US government enacted H.R.1, originally known as the Tax Cuts and Jobs Act, which includes legislation to decrease its federal corporate income tax rate from 35 per cent to 21 per cent. The Corporation's net deferred tax liability associated with its directly owned US operations is made up of a deferred tax asset and a deferred tax liability that net to $6 million. The decrease in the US federal corporate income tax rate resulted in a decrease to the deferred tax asset of $104 million, all of which is recorded as deferred tax expense in the Consolidated Statement of Earnings, offset by a decrease to the deferred tax liability of $110 million, of which $1 million is recorded as deferred tax expense in the Consolidated Statement of Earnings with an offsetting $111 million deferred tax recovery recorded in the Consolidated Statement of Other Comprehensive Income. (4) During the year ended Dec. 31, 2019, the Corporation recorded a reversal of a previous writedown of deferred income tax assets of $9 million (2018 - $27 million writedown, 2017 - $15 million writedown reversal). The deferred income tax assets relate mainly 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. The Corporation previously wrote these assets off when it was not considered probable that sufficient future taxable income would be available from the Corporation’s directly owned US operations to utilize the underlying tax losses. Recognized ordinary income and other comprehensive income has given rise to taxable temporary differences, which forms the primary basis for utilization of some of the tax losses and the reversal of the writedown.
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 2019 2018 2017 Income tax expense (recovery) related to: Net impact related to cash flow hedges 6 (12) (108) Net impact related to net investment hedges — — (7) Net actuarial gains (losses) (7) 5 (4) Income tax expense reported in equity (1) (7) (119)
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 2019 2018 Net operating loss carryforwards 494 547 Future decommissioning and restoration costs 122 113 Property, plant and equipment (828) (896) Risk management assets and liabilities, net (141) (145) Employee future benefits and compensation plans 56 68 Interest deductible in future periods 42 48 Foreign exchange differences on US-denominated debt 40 35 Deferred coal revenues — 23 Other deductible temporary differences 4 — Net deferred income tax liability, before writedown of deferred income tax assets (211) (207) Writedown of deferred income tax assets (243) (266) Net deferred income tax liability, after writedown of deferred income tax assets (454) (473) The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows: As at Dec. 31 2019 2018 Deferred income tax assets (1) 18 28 Deferred income tax liabilities (472) (501) Net deferred income tax liability (454) (473) (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, 2019
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, 2019 TransAlta Cogeneration L.P. 49.99% - Canadian Power Holdings Inc. TransAlta Renewables 39.6% - 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 conversion of the Class B shares, the DRIP and the Offering described in Note 4(O), the Corporation’s share of ownership and equity participation in TransAlta Renewables has changed as follows: Period Ownership and voting Equity participation Jan. 6, 2016 to July 31, 2017 64.0 59.8 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 Apr. 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
Disclosure of interests in subsidiaries	Year ended Dec. 31 2019 2018 2017 Revenues 446 462 459 Net earnings 183 241 13 Total comprehensive income 138 281 (24) Amounts attributable to the non-controlling interests: Net earnings 73 94 11 Total comprehensive income 56 110 — Distributions paid to non-controlling interests 69 79 85 As at Dec. 31 2019 2018 Current assets 293 250 Long-term assets 3,409 3,497 Current liabilities (152) (159) Long-term liabilities (1,237) (1,192) Total equity (2,313) (2,396) Equity attributable to non-controlling interests (941) (961) Non-controlling interests’ share (per cent) 39.6 39.1 B. TA Cogen Year ended Dec. 31 2019 2018 2017 Results of operations Revenues 181 185 175 Net earnings 43 29 61 Total comprehensive income 43 29 61 Amounts attributable to the non-controlling interest: Net earnings 21 14 31 Total comprehensive income 21 14 31 Distributions paid to Canadian Power Holdings Inc. 37 86 87 As at Dec. 31 2019 2018 Current assets 41 82 Long-term assets 328 354 Current liabilities (27) (54) Long-term liabilities (19) (28) Total equity (323) (354) Equity attributable to Canadian Power Holdings Inc. (160) (176) Non-controlling interest share (per cent) 49.99 49.99 Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2019, 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 Canada 60.4 Generation and sale of electricity

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
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, 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 receivable — — 176 176 Risk management assets Current 71 95 — 166 Long-term 607 33 — 640 Other assets (Note 21) — — 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 finance lease obligations (2) — — 3,212 3,212 Exchangeable securities — — 326 326 (1) Includes cash equivalents of nil. (2) Includes current portion. Carrying value as at Dec. 31, 2018 Derivatives Derivatives Amortized cost Other financial assets (FVTPL) Total Financial assets Cash and cash equivalents (1) — — 89 — 89 Restricted cash — — 66 — 66 Trade and other receivables — — 731 25 756 Long-term portion of finance lease receivables — — 191 — 191 Risk management assets Current 60 86 — — 146 Long-term 629 33 — — 662 Other assets — — 37 15 52 Financial liabilities Accounts payable and accrued liabilities — — 496 — 496 Dividends payable — — 58 — 58 Risk management liabilities Current 1 89 — — 90 Long-term 1 40 — — 41 Credit facilities, long-term debt and finance lease obligations (2) — — 3,267 — 3,267
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, 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 receivable — — 176 176 Risk management assets Current 71 95 — 166 Long-term 607 33 — 640 Other assets (Note 21) — — 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 finance lease obligations (2) — — 3,212 3,212 Exchangeable securities — — 326 326 (1) Includes cash equivalents of nil. (2) Includes current portion. Carrying value as at Dec. 31, 2018 Derivatives Derivatives Amortized cost Other financial assets (FVTPL) Total Financial assets Cash and cash equivalents (1) — — 89 — 89 Restricted cash — — 66 — 66 Trade and other receivables — — 731 25 756 Long-term portion of finance lease receivables — — 191 — 191 Risk management assets Current 60 86 — — 146 Long-term 629 33 — — 662 Other assets — — 37 15 52 Financial liabilities Accounts payable and accrued liabilities — — 496 — 496 Dividends payable — — 58 — 58 Risk management liabilities Current 1 89 — — 90 Long-term 1 40 — — 41 Credit facilities, long-term debt and finance lease obligations (2) — — 3,267 — 3,267
Disclosure for sensitivity ranges for the base fair value	As at Dec. 31 2019 2018 Description Base fair value Sensitivity Base fair value Sensitivity Long-term power sale – US 737 +46 801 +116 Unit contingent power purchases (6) +1 18 +4 Structured products – Eastern US 7 +2 6 +5 Full requirements – Eastern US 10 +3 — — Long-term wind energy sale – Eastern US (28) +20 (39) +21 Others — +7 9 +3
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, 2019 and 2018, respectively: Year ended Dec. 31, 2019 Year ended Dec. 31, 2018 Hedge Non-hedge Total Hedge Non-hedge Total Opening balance 689 6 695 719 52 771 Changes attributable to: Market price changes on existing contracts 77 8 85 (7) (9) (16) Market price changes on new contracts — 14 14 — 4 4 Contracts settled (57) (19) (76) (90) (42) (132) Change in foreign exchange rates (31) (1) (32) 67 5 72 Transfers into (out of) Level III — — — — (4) (4) Net risk management assets at end of period 678 8 686 689 6 695 Additional Level III information: Gains recognized in other comprehensive income 46 — 46 60 — 60 Total gains included in earnings before income taxes 57 21 78 90 — 90 Unrealized gains (losses) included in earnings before — 2 2 — (42) (42)
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) Exchangeable securities - Dec. 31, 2019 — 342 — 342 326 Long-term debt - Dec. 31, 2019 — 3,157 — 3,157 3,070 Long-term debt - Dec. 31, 2018 — 3,181 — 3,181 3,204 (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 2019 2018 2017 Unamortized net gain at beginning of year 49 105 148 New inception gains (losses) 3 (14) 12 Change in foreign exchange rates — 5 (7) Amortization recorded in net earnings during the year (43) (47) (48) Unamortized net gain at end of year 9 49 105

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2019
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, 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 As at Dec. 31, 2018 Cash flow Not Total Commodity risk management Current 59 — 59 Long-term 628 (8) 620 Net commodity risk management assets (liabilities) 687 (8) 679 Other Current — (3) (3) Long-term — 1 1 Net other risk management liabilities — (2) (2) Total net risk management assets (liabilities) 687 (10) 677 The Corporation’s outstanding commodity derivative instruments designated as hedging instruments are as follows: As at Dec. 31 2019 2018 Type Notional Notional Notional Notional Electricity (MWh) 222 — 2,128 — The Corporation’s outstanding commodity derivative instruments not designated as hedging instruments are as follows: As at Dec. 31 2019 2018 Type Notional Notional Notional Notional Electricity (MWh) 16,097 7,204 58,885 37,023 Natural gas (GJ) 38,062 55,023 80,413 110,488 Transmission (MWh) — 1,818 29 11,163 Emissions (MWh) 184 138 — — Emissions (tonnes) 2,436 2,446 3,134 2,948 As at Dec. 31 2019 2018 Notional Notional Fair value Maturity Notional Notional Fair value Maturity Foreign exchange forward contracts – foreign-denominated receipts/expenditures AUD286 CAD266 — 2020 - 2023 AUD218 CAD205 (5) 2019-2022 USD108 CAD139 (4) 2020 - 2023 USD164 CAD214 (7) 2019-2022 Foreign exchange forward contracts – foreign-denominated debt CAD191 USD150 6 2022 CAD124 USD100 10 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 2019 2018 Current Long-term Current Long-term Current Long-term Current Long-term Gross amounts recognized 316 631 (191) (100) 224 657 (116) (42) Gross amounts set-off (140) (42) 140 42 (53) (6) 53 6 Net amounts as included in the 176 589 (51) (58) 171 651 (63) (36)
Effect of Hedges	The impact of hedged items designated in hedging relationships on OCI and net earnings is: Year ended Dec. 31, 2019 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 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 Pre-tax (gain) loss 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 (2018 and 2017 - 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 2019 2018 2017 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 (18) 2 (13) — (5) — AUD (6) — (7) — (7) — Total (24) 2 (20) — (12) — (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, 2019: Investment grade (Per cent) Non-investment grade (Per cent) Total (Per cent) Total Trade and other receivables (1) 85 15 100 462 Long-term finance lease receivable 100 — 100 176 Risk management assets (1) 99 1 100 806 Loan receivable (2) — 100 100 47 Total 1,491 (1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts.
Maturity Analysis of Financial Liabilities	A maturity analysis of the Corporation’s financial liabilities is as follows: 2020 2021 2022 2023 2024 2025 and thereafter Total Accounts payable and accrued liabilities 413 — — — — — 413 Long-term debt (1) 494 98 625 372 105 1,410 3,104 Exchangeable securities (2) — — — — — 350 350 Commodity risk management assets (89) (89) (143) (139) (135) (97) (692) Other risk management (assets) liabilities 1 — (6) 2 — (1) (4) Lease obligations 19 14 9 6 4 90 142 Interest on long-term debt and lease obligations (3) 161 138 128 98 87 671 1,283 Interest on exchangeable securities (2, 3) 25 25 25 24 24 — 123 Dividends payable 37 — — — — — 37 Total 1,061 186 638 363 85 2,423 4,756 (1) Excludes impact of hedge accounting. (2) Assumes the debentures will be exchanged on Jan. 1, 2025. Refer to Note 24 for further details.
Hedging Instruments	The impact of the hedging instruments on the statement of financial position is as follows: As at Dec. 31, 2019 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 19 MMWh 678 Risk management assets 47 Foreign currency risk Net investment hedges Foreign-denominated debt USD370 CAD483 Credit facilities, long-term debt and finance lease obligations 21 As at Dec. 31, 2018 Notional amount Carrying amount Line item in the statement of financial position Change in fair Commodity price risk Cash flow hedges Physical power sales 23 MMWh 687 Risk management assets 60 Foreign currency risk Net investment hedges Foreign-denominated debt USD400 CAD546 Credit facilities, long-term debt and finance lease obligations (41) The impact of the hedged items on the statement of financial position is as follows: As at Dec. 31, 2019 2019 2018 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 47 527 60 508 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) Net investment hedges Net investment in foreign 21 (21) (41) 17

Property, Plant, and Equipmen_2

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
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: Coal generation 2-10 years Pipeline 50 years Gas generation 2-30 years Hydro generation 2-60 years Wind generation 2-30 years Mining property and equipment 2-10 years Capital spares and other 2-60 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, 2017 95 5,888 1,982 3,228 1,315 95 370 12,973 Additions (2) — — — 1 — 275 8 284 Additions - finance lease — — — — 10 — — 10 Disposals (3) — — — (1) — (3) (7) Impairment charge (Note 7) — (38) — (11) — — — (49) Revisions and additions to decommissioning and restoration costs — (12) (1) (3) (16) — — (32) Retirement of assets — (47) (17) (6) (16) — (4) (90) Change in foreign exchange rates 2 105 (13) 26 7 4 — 131 Transfers — 41 13 51 39 (174) 12 (18) As at Dec. 31, 2018 94 5,937 1,964 3,286 1,338 200 383 13,202 Adjustments on implementation of IFRS 16 (Note 3) (3) — — — (7) (101) — — (108) Additions (4) — — — — — 407 115 522 Acquisitions (Note 4(D) and 4(J)) (5) — 300 — — — 139 — 439 Disposals (6) (2) (389) (260) — (34) — (19) (704) Impairment (charges) reversals (Note 7) — 448 — (2) (15) — — 431 Revisions and additions to decommissioning and restoration costs — (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 (7) — 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 Accumulated depreciation As at Dec. 31, 2017 — 3,431 1,072 1,037 713 — 142 6,395 Depreciation — 306 79 123 125 — 16 649 Retirement of assets — (56) (13) (2) (12) — — (83) Disposals — — — — (1) — (4) (5) Change in foreign exchange rates — 84 (3) 6 5 — — 92 Transfers — — (7) (3) — — — (10) As at Dec. 31, 2018 — 3,765 1,128 1,161 830 — 154 7,038 Adjustments on implementation of IFRS 16 (Note 3) (3) — — — (3) (43) — — (46) Depreciation — 304 77 136 97 — 16 630 Retirement of assets — (158) (23) (3) (6) — — (190) Disposals (5) — (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 Carrying amount As at Dec. 31, 2017 95 2,457 910 2,191 602 95 228 6,578 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 (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) Includes $7 million related to the acquisition of Big Level. (3) Includes net $33 million transferred to right of use assets and $29 million of finance lease assets that were derecognized on implementation of IFRS 16. Refer to Note 3 for further details. (4) Includes 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. (5) 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. (6) 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 Sunhills 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, 2019
Disclosure of leases [Abstract]
Disclosure of quantitative information about right-of-use assets [text block]	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 and other assets — — 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) Change in foreign exchange rates (1) — — — — (1) Transfers — — — (1) — (1) As at Dec. 31, 2019 58 16 2 25 45 146

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2017 178 314 223 29 744 Additions (1) — — — 53 53 Retirements and disposals (2) — (2) — — (2) Change in foreign exchange rates — 3 — — 3 Transfers 7 24 14 (36) 9 As at Dec. 31, 2018 185 339 237 46 807 Assets transferred to right of use assets on — (5) — — (5) Additions — — — 14 14 Acquisition — 1 — 15 16 Disposals (Note 4(D)) (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 Accumulated amortization As at Dec. 31, 2017 125 188 67 — 380 Amortization 9 32 9 — 50 Retirements and disposals — (1) — — (1) Change in foreign exchange rates — 2 — — 2 Transfers (17) — 20 — 3 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(D)) (9) (1) — — (10) Change in foreign exchange rates — (1) — — (1) Transfers 1 (1) — — — As at Dec. 31, 2019 117 246 107 — 470 Carrying amount As at Dec. 31, 2017 53 126 156 29 364 As at Dec. 31, 2018 68 118 141 46 373 As at Dec. 31, 2019 32 132 143 11 318 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 2019 2018 Hydro 258 259 Wind and Solar 176 175 Energy Marketing 30 30 Total goodwill 464 464

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2017 178 314 223 29 744 Additions (1) — — — 53 53 Retirements and disposals (2) — (2) — — (2) Change in foreign exchange rates — 3 — — 3 Transfers 7 24 14 (36) 9 As at Dec. 31, 2018 185 339 237 46 807 Assets transferred to right of use assets on — (5) — — (5) Additions — — — 14 14 Acquisition — 1 — 15 16 Disposals (Note 4(D)) (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 Accumulated amortization As at Dec. 31, 2017 125 188 67 — 380 Amortization 9 32 9 — 50 Retirements and disposals — (1) — — (1) Change in foreign exchange rates — 2 — — 2 Transfers (17) — 20 — 3 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(D)) (9) (1) — — (10) Change in foreign exchange rates — (1) — — (1) Transfers 1 (1) — — — As at Dec. 31, 2019 117 246 107 — 470 Carrying amount As at Dec. 31, 2017 53 126 156 29 364 As at Dec. 31, 2018 68 118 141 46 373 As at Dec. 31, 2019 32 132 143 11 318 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 2019 2018 Hydro 258 259 Wind and Solar 176 175 Energy Marketing 30 30 Total goodwill 464 464

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of financial assets [abstract]
Disclosure of components in other assets	The components of other assets are as follows: As at Dec. 31 2019 2018 South Hedland prepaid transmission access and distribution costs 67 72 Deferred licence fees 9 11 Project development costs 19 47 Deferred service costs — 12 Long-term prepaids and other assets 56 55 Loan receivable 47 37 Total other assets 198 234

Decommissioning and Other Pro_2

Decommissioning and Other Provisions (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2017 437 33 470 Liabilities incurred 5 17 22 Liabilities settled (31) (10) (41) Accretion 24 — 24 Acquisition of liabilities (Big Level) — 8 8 Revisions in estimated cash flows 2 3 5 Revisions in discount rates (37) — (37) Reversals — (5) (5) Change in foreign exchange rates 7 3 10 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 16 — 16 Reversals — (1) (1) Change in foreign exchange rates (7) — (7) Balance, Dec. 31, 2019 501 45 546 (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, described in Note 3(A)(IV), the discount rates used for the Canadian coal and mining operations decommissioning provisions were changed. The use of a lower inflation rate decreased the corresponding liabilities. Decommissioning and Other Total Balance, Dec. 31, 2018 407 49 456 Current portion 35 35 70 Non-current portion 372 14 386 Balance, Dec. 31, 2019 501 45 546 Current portion 36 22 58 Non-current portion 465 23 488

Credit Facilities, Long-Term _2

Credit Facilities, Long-Term Debt, and Finance Lease Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Subclassifications of assets, liabilities and equities [abstract]
Disclosure of borrowings outstanding	The amounts outstanding are as follows: As at Dec. 31 2019 2018 Carrying Face Interest (1) Carrying Face Interest (1) Credit facilities (2) 220 220 3.5 % 339 339 3.8 % Debentures 647 651 5.8 % 647 651 5.8 % Senior notes (3) 905 914 5.4 % 943 955 5.4 % Non-recourse (4) 1,144 1,157 4.3 % 1,236 1,250 4.4 % Other (5) 154 162 7.1 % 39 39 9.2 % 3,070 3,104 3,204 3,234 Finance lease obligations 142 63 3,212 3,267 Less: current portion of long-term debt (494) (130) Less: current portion of finance lease obligations (19) (18) Total current long-term debt and finance lease (513) (148) Total credit facilities, long-term debt and finance 2,699 3,119 (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, 2019 - US$0.7 billion (Dec. 31, 2018 - US$0.7 billion). (4) Includes US$1 million at Dec. 31, 2019 (Dec. 31, 2018 - US$1 million). (5) Includes US$117 at Dec. 31, 2019 (Dec. 31, 2018 - US$21 million) of tax equity financing.
Disclosure of principal repayments	2020 2021 2022 2023 2024 2025 and thereafter Total Principal repayments (1) 494 98 625 372 105 1,410 3,104 Lease obligations 19 14 9 6 4 90 142 (1) Excludes impact of derivatives.

Exchangeable Securities (Tables

Exchangeable Securities (Tables)	12 Months Ended
	Dec. 31, 2019
Exchangeable Securities [Abstract]
Disclosure of borrowing costs [text block]	$350 Million Unsecured Subordinated Debentures As at Dec. 31, 2019 Carrying value Face value Interest Exchangeable debentures – due May 1, 2039 326 350 7%

Defined Benefit Obligation an_2

Defined Benefit Obligation and Other Long-Term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
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 2019 2018 Defined benefit obligation (Note 30) 268 227 Long-term incentive accruals (Note 29) 4 9 Other 29 51 Total 301 287

Common Shares (Tables)

Common Shares (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 284.6 3,059 287.9 3,094 Purchased and cancelled under the NCIB (7.7) (83) (3.3) (35) Stock options exercised 0.1 2 — — Issued and outstanding, end of year 277.0 2,978 284.6 3,059 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 2019 2018 Total shares purchased (1) 7,716,300 3,264,500 Average purchase price per share $ 8.80 $ 7.02 Total cost 68 23 Weighted average book value of shares cancelled 83 35 Amount recorded in deficit 15 12 All preferred shares issued and outstanding are non-voting cumulative redeemable fixed rate first preferred shares. As at Dec. 31 2019 2018 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 2019 2018 2017 Net earnings (loss) attributable to common shareholders 52 (248) (190) Basic and diluted weighted average number of common shares outstanding (millions) 283 287 288 Net earnings (loss) per share attributable to common shareholders, basic and diluted 0.18 (0.86) (0.66)

Preferred Shares (Tables)

Preferred Shares (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 284.6 3,059 287.9 3,094 Purchased and cancelled under the NCIB (7.7) (83) (3.3) (35) Stock options exercised 0.1 2 — — Issued and outstanding, end of year 277.0 2,978 284.6 3,059 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 2019 2018 Total shares purchased (1) 7,716,300 3,264,500 Average purchase price per share $ 8.80 $ 7.02 Total cost 68 23 Weighted average book value of shares cancelled 83 35 Amount recorded in deficit 15 12 All preferred shares issued and outstanding are non-voting cumulative redeemable fixed rate first preferred shares. As at Dec. 31 2019 2018 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, 2019, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over Benchmark (per cent) Convertible to A Fixed 0.67725 March 31, 2021 2.03 B B Floating 0.93575 March 31, 2021 2.03 A C Fixed 1.00675 June 30, 2022 3.10 D D Floating — — 3.10 C E Fixed 1.29850 Sept. 30, 2022 3.65 F F Floating — — 3.65 E G Fixed 1.32500 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 preferred share dividends declared in 2019, 2018 and 2017: Total dividends declared Series 2019 2018 2017 A 5 9 5 B 1 1 1 C 8 14 9 E 9 15 8 G 7 11 7 Total for the year 30 50 30

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2018
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: 2019 2018 Currency translation adjustment Opening balance, Jan. 1 17 (26) Gains (losses) on translating net assets of foreign operations, net of reclassifications to net earnings, (59) 84 Gains (losses) on financial instruments designated as hedges of foreign operations, net of 21 (41) Balance, Dec. 31 (21) 17 Cash flow hedges Opening balance, Jan. 1 508 562 Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and to non-financial assets, net of tax (1) 19 (54) Balance, Dec. 31 527 508 Employee future benefits Opening balance, Jan. 1 (29) (44) Net actuarial gains (losses) on defined benefit plans, net of tax (2) (26) 15 Balance, Dec. 31 (55) (29) Other Opening balance, Jan. 1 (15) (3) Change in ownership of TransAlta Renewables 1 4 Intercompany investments at FVOCI 17 (16) Balance, Dec. 31 3 (15) Accumulated other comprehensive income 454 481 (1) Net of income tax of $6 million for the year ended Dec. 31, 2019 (2018 - $12 million). (2) Net of income tax of $7 million for the year ended Dec. 31, 2019 (2018 - $5 million).

Share-Based Payment Plans (Tabl

Share-Based Payment Plans (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2019, are outlined below: Options outstanding Range of exercise prices (1) ($ per share) Number of options (millions) Weighted average remaining contractual life (years) Weighted average exercise price ($ per share) 5.00 - 9.00 3.3 4.7 6.34 22.00 - 30.00 0.5 0.1 23.44 5.00 - 30.00 3.8 4.2 8.41
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, 2019, are outlined below: Options outstanding Range of exercise prices (1) ($ per share) Number of options (millions) Weighted average remaining contractual life (years) Weighted average exercise price ($ per share) 5.00 - 9.00 3.3 4.7 6.34 22.00 - 30.00 0.5 0.1 23.44 5.00 - 30.00 3.8 4.2 8.41 (1) Options currently exercisable as at Dec. 31, 2019.

Employee Future Benefits (Table

Employee Future Benefits (Tables)	12 Months Ended
	Dec. 31, 2019
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, 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 Year ended Dec. 31, 2017 Registered Supplemental Other Total Current service cost 7 2 1 10 Administration expenses 2 — — 2 Interest cost on defined benefit obligation 20 3 1 24 Interest on plan assets (15) — — (15) Defined benefit expense 14 5 2 21 Defined contribution expense 11 — — 11 Net expense 25 5 2 32 The expected employer contributions for 2020 for the defined benefit pension and other post-employment benefit plans are as follows: Registered Supplemental Other Total Expected employer contributions 4 5 1 10
Defined Benefit Obligation	The status of the defined benefit pension and other post-employment benefit plans is as follows: As at 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) As at Dec. 31, 2018 Registered Supplemental Other Total Fair value of plan assets 368 13 — 381 Present value of defined benefit obligation (514) (80) (25) (619) Funded status – plan deficit (146) (67) (25) (238) Amount recognized in the consolidated financial statements: Accrued current liabilities (5) (5) (1) (11) Other long-term liabilities (141) (62) (24) (227) Total amount recognized (146) (67) (25) (238) 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, 2017 561 87 27 675 Current service cost 9 2 1 12 Interest cost 18 3 1 22 Benefits paid (42) (5) (1) (48) Actuarial gain arising from demographic assumptions — — — — Actuarial loss arising from financial assumptions (35) (7) (2) (44) Actuarial gain (loss) arising from experience adjustments — — (1) (1) Effect of translation on US plans 3 — — 3 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 loss arising from demographic assumptions — — (2) (2) Actuarial (gain) 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
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, 2017 416 12 — 428 Interest on plan assets 13 — — 13 Net return on plan assets (25) — — (25) Contributions 5 6 1 12 Benefits paid (42) (5) (1) (48) Administration expenses (1) — — (1) Effect of translation on US plans 2 — — 2 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 The fair value of the Corporation’s defined benefit plan assets by major category is as follows: 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 Year ended Dec. 31, 2018 Level I Level II Level III Total Equity securities Canadian — 65 — 65 US — 26 — 26 International — 101 — 101 Private — — 1 1 Bonds AAA — 48 — 48 AA — 64 — 64 A — 39 — 39 BBB 1 21 — 22 Below BBB — 3 — 3 Money market and cash and cash equivalents (2) 14 — 12 Total (1) 381 1 381
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, 2019 Registered Supplemental Other Pension Other 1% decrease in the discount rate 84 15 2 3 1 1% increase in the salary scale 14 — — — — 1% increase in the health-care cost trend rate — — 2 — — 10% improvement in mortality rates 22 3 — 1 —

Cash Flow Information (Tables)

Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of cash flow statement [Abstract]
Disclosure of non-cash operating working capital	Year ended Dec. 31 2019 2018 2017 (Use) source: Accounts receivable 261 58 (228) Prepaid expenses — 19 (75) Income taxes receivable (6) — 8 Inventory (13) (21) (7) Accounts payable, accrued liabilities and provisions (130) (97) 186 Income taxes payable 9 (3) 2 Change in non-cash operating working capital 121 (44) (114)
Cash flows from (used in) operating activities [Text Block]	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 activities 3,325 195 133 (35) 64 (42) (65) 3,575 Balance Net cash flows New leases Dividends declared Foreign exchange impact Other Balance Long-term debt and finance lease 3,707 (540) 10 — 95 (5) 3,267 Dividends payable (common and 34 (86) — 107 — 3 58 Total liabilities from financing activities 3,741 (626) 10 107 95 (2) 3,325

Capital (Tables)

Capital (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 Common shares (millions) Amount Common shares (millions) Amount Issued and outstanding, beginning of year 284.6 3,059 287.9 3,094 Purchased and cancelled under the NCIB (7.7) (83) (3.3) (35) Stock options exercised 0.1 2 — — Issued and outstanding, end of year 277.0 2,978 284.6 3,059 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 2019 2018 Total shares purchased (1) 7,716,300 3,264,500 Average purchase price per share $ 8.80 $ 7.02 Total cost 68 23 Weighted average book value of shares cancelled 83 35 Amount recorded in deficit 15 12 (1) As at Dec. 31, 2019, includes 189,900 (2018 - 204,000) 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 2019 2018 2017 Net earnings (loss) attributable to common shareholders 52 (248) (190) Basic and diluted weighted average number of common shares outstanding (millions) 283 287 288 Net earnings (loss) per share attributable to common shareholders, basic and diluted 0.18 (0.86) (0.66) E. Dividends On Oct. 9, 2019, the Corporation declared a quarterly dividend of $0.04 per common share, payable on Jan. 1, 2020. On Jan. 16, 2020, the Corporation declared a quarterly dividend of $0.0425 per common share, payable on Apr. 1, 2020. 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 rate first preferred shares. As at Dec. 31 2019 2018 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, 2019. 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 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 five five ▪ Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. ▪ Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above. Characteristics specific to each first preferred share series as at Dec. 31, 2019, are as follows: Series Rate during term Annual dividend rate per share ($) Next Rate spread over Benchmark (per cent) Convertible to A Fixed 0.67725 March 31, 2021 2.03 B B Floating 0.93575 March 31, 2021 2.03 A C Fixed 1.00675 June 30, 2022 3.10 D D Floating — — 3.10 C E Fixed 1.29850 Sept. 30, 2022 3.65 F F Floating — — 3.65 E G Fixed 1.32500 Sept. 30, 2024 3.80 H H Floating — — 3.80 G B. Dividends The following table summarizes the value of preferred share dividends declared in 2019, 2018 and 2017: Total dividends declared Series 2019 2018 2017 A 5 9 5 B 1 1 1 C 8 14 9 E 9 15 8 G 7 11 7 Total for the year 30 50 30 TransAlta’s capital is comprised of the following: As at Dec. 31 2019 2018 Increase/ Long-term debt (1) 3,212 3,267 (55) Exchangeable securities 326 — 326 Equity Common shares 2,978 3,059 (81) Preferred shares 942 942 — Contributed surplus 42 11 31 Deficit (1,455) (1,496) 41 Accumulated other comprehensive income 454 481 (27) Non-controlling interests 1,101 1,137 (36) Less: available cash and cash equivalents (2) (411) (89) (322) Less: principal portion of restricted cash on TransAlta OCP Bonds (3) (10) (27) 17 Less: fair value asset of hedging instruments on long-term debt (4) (7) (10) 3 Total capital 7,172 7,275 (103) (1) Includes lease obligations, 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). In 2019, Moody's reaffirmed its issuer rating of Ba1 and revised their rating outlook to stable from positive. During 2019, Fitch Ratings downgraded the Corporation below investment grade to BB+ 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 downgraded the Corporation’s Unsecured Debt rating and Issuer Rating to 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 2019 2018 Target Funds from operations before interest to adjusted interest coverage (times) 4.5 4.8 4 to 5 Adjusted funds from operations to adjusted net debt (%) 19.0 20.8 20 to 25 Adjusted net debt to adjusted comparable earnings before interest, taxes, depreciation and amortization (times) 3.9 3.6 3.0 to 3.5
Disclosure of cash flow statement	For the years ended Dec. 31, 2019 and 2018, cash inflows and outflows are summarized below. The Corporation manages variations in working capital using existing liquidity under credit facilities. Year ended Dec. 31 2019 2018 Increase Cash flow from operating activities 849 820 29 Change in non-cash working capital (121) 44 (165) Cash flow from operations before changes in working capital 728 864 (136) Dividends paid on common shares (45) (46) 1 Dividends paid on preferred shares (40) (40) — Distributions paid to subsidiaries’ non-controlling interests (106) (165) 59 Property, plant and equipment expenditures (417) (277) (140) Inflow 120 336 (216)

Commitments and Contingencies_2

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of other provisions, contingent liabilities and contingent assets [Abstract]
Disclosure of commitments and future payments	In addition to commitments disclosed elsewhere in the financial statements, the Corporation has other contractual commitments, either directly or through its interests in joint operations. Approximate future payments under these agreements are as follows: 2020 2021 2022 2023 2024 2025 and thereafter Total Natural gas, transportation and 125 125 120 128 131 1,493 2,122 Transmission 9 5 4 3 — — 21 Coal supply and mining 147 16 16 16 8 14 217 Long-term service agreements 50 22 32 17 15 14 150 Operating leases 4 2 2 2 3 64 77 Growth 535 254 196 270 13 — 1,268 TransAlta Energy Transition Bill 6 6 6 6 — — 24 Total 876 430 376 442 170 1,585 3,879

Segment Disclosures (Tables)

Segment Disclosures (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure of entity's operating segments [Abstract]
Disclosure of operating segments	Earnings Information Year ended Dec. 31, 2019 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Revenues 816 571 209 160 312 156 129 (6) 2,347 Fuel, carbon compliance and 570 416 74 9 16 7 — (6) 1,086 Gross margin 246 155 135 151 296 149 129 — 1,261 Operations, maintenance and 138 67 44 37 50 36 30 73 475 Depreciation and amortization 233 83 41 48 124 32 2 27 590 Asset impairment charge 15 (10) — — — 2 — 18 25 Gain on termination of (88) — — — — — — — (88) Taxes, other than income taxes 13 3 1 — 8 3 — 1 29 Termination of Sundance B and (56) — — — — — — — (56) Net other operating expense (40) — (1) — (10) — — 2 (49) Operating income (loss) 31 12 50 66 124 76 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 Year ended Dec. 31, 2018 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Revenues 912 442 232 165 282 156 67 (7) 2,249 Fuel, carbon compliance and 666 314 96 8 17 6 — (7) 1,100 Gross margin 246 128 136 157 265 150 67 — 1,149 Operations, maintenance and 171 61 48 37 50 38 24 86 515 Depreciation and amortization 241 74 43 49 110 30 2 25 574 Asset impairment charge 38 — — — 12 — — 23 73 Taxes, other than income taxes 13 5 1 — 8 3 — 1 31 Termination of Sundance B and (157) — — — — — — — (157) Net other operating income (41) — — — (6) — — — (47) Operating income (loss) (19) (12) 44 71 91 79 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) Year ended Dec. 31, 2017 Canadian US Canadian Australian Wind Hydro Energy Corporate Total Revenues 999 435 261 135 287 121 69 — 2,307 Fuel, carbon compliance and 585 293 101 14 17 6 — — 1,016 Gross margin 414 142 160 121 270 115 69 — 1,291 Operations, maintenance and 192 51 50 31 48 37 24 84 517 Depreciation and amortization 317 73 38 37 111 31 2 26 635 Asset impairment reversals 20 — — — — — — — 20 Taxes, other than income taxes 13 4 1 — 8 3 — 1 30 Net other operating income (40) — (9) — — — — — (49) Operating income (loss) (88) 14 80 53 103 44 43 (111) 138 Finance lease income — — 11 43 — — — — 54 Net interest expense (247) Foreign exchange loss (1) Gain on sale of assets 2 Earnings before income taxes (54)
Disclosure of selected consolidated statements of financial position information	Selected Consolidated Statements of Financial Position Information As at Dec. 31, 2019 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total PP&E 2,540 352 392 489 1,947 469 1 17 6,207 Right of use assets 68 — — 4 56 6 — 12 146 Intangible assets 41 6 2 37 173 5 9 45 318 Goodwill — — — — 176 258 30 — 464 As at Dec. 31, 2018 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total PP&E 2,587 332 391 554 1,799 481 1 19 6,164 Intangible assets 81 7 4 41 173 4 11 52 373 Goodwill — — — — 175 259 30 — 464
Disclosure of components in other non-current assets	Additions to non-current assets are as follows: Year ended Dec. 31, 2019 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Additions to non-current assets: PP&E 114 8 36 6 229 23 — 1 417 Intangible assets 2 — — — — — — 12 14 Year ended Dec. 31, 2018 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Additions to non-current assets: PP&E 101 14 21 6 117 16 — 2 277 Intangible assets 3 — — — — — — 17 20 Year ended Dec. 31, 2017 Canadian US Canadian Australian Wind and Hydro Energy Corporate Total Additions to non-current assets: PP&E 116 35 31 114 20 16 — 6 338 Intangible assets 5 1 — 29 — — — 16 51
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 2019 2018 2017 Depreciation and amortization expense on the Consolidated Statements of 590 574 635 Depreciation included in fuel, carbon compliance and purchased power (Note 6) 119 136 73 Depreciation and amortization on the Consolidated Statements of Cash Flows 709 710 708
Disclosure of geographical areas	Revenues Year ended Dec. 31 2019 2018 2017 Canada 1,460 1,573 1,663 US 727 511 509 Australia 160 165 135 Total revenue 2,347 2,249 2,307 II. Non-Current Assets Property, plant and Right of use assets Intangible assets Other assets Goodwill As at Dec. 31 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 Canada 4,854 4,953 109 — 213 273 75 101 418 417 US 863 657 33 — 68 59 47 50 46 47 Australia 490 554 4 — 37 41 76 83 — — Total 6,207 6,164 146 — 318 373 198 234 464 464

Corporate Information Corporate

Corporate Information Corporate Information (Details)	Dec. 31, 2019segment
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, 2019
Coal generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	2 years
Coal generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	50 years
Gas generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	2 years
Gas generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	30 years
Hydro | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	2 years
Hydro | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	60 years
Wind Generation | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	2 years
Wind Generation | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	30 years
Mining property and equipment | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	2 years
Mining property and equipment | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	10 years
Capital spares and other | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	2 years
Capital spares and other | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	60 years
Facilities | Minimum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	30 years
Facilities | Maximum
Disclosure of detailed information about property, plant and equipment [line items]
PP&E useful life	60 years
Computer software | Minimum
Disclosure of detailed information about intangible assets [line items]
Intangible assets, useful life	2 years
Computer software | Maximum
Disclosure of detailed information about intangible assets [line items]
Intangible assets, useful life	7 years
Power sale contracts | Minimum
Disclosure of detailed information about intangible assets [line items]
Intangible assets, useful life	1 year
Power sale contracts | Maximum
Disclosure of detailed information about intangible assets [line items]
Intangible assets, useful life	15 years

Accounting Changes - Narrative

Accounting Changes - Narrative (Details) - CAD ($) $ in Millions	Jan. 01, 2019	Jun. 30, 2017	Sep. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2019
Disclosure of changes in accounting estimates [line items]
Impact of change in accounting policy (Note 3)					$ 3	$ (13)
Right-of-use assets				$ 146	0
Property, plant and equipment				6,207	6,164	6,578
Finance lease liabilities	$ 32
Depreciation and amortization				590	574	635
Contract liabilities (Note 5)				14	80
Deferred income tax liabilities (Note 11)				472	501
Non-controlling interests (Note 12)				1,101	1,137
Deficit				(1,455)	(1,496)
Lease liabilities	52
Non-cancellable operating leases	83			77	80
Revisions in discount rates				16	(37)
IFRS 16
Disclosure of changes in accounting estimates [line items]
Right-of-use assets	85			146	52
Property, plant and equipment					38
Assets under finance leases	(29)
Coal generation
Disclosure of changes in accounting estimates [line items]
Property, plant and equipment				2,120	2,172	2,457
Deficit
Disclosure of changes in accounting estimates [line items]
Impact of change in accounting policy (Note 3)					3	(14)
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				222			$ 141
Impairment loss				141
Alberta Mine | Change in Useful Lives Estimate
Disclosure of changes in accounting estimates [line items]
Depreciation and amortization					38	58
Sundance Unit 1
Disclosure of changes in accounting estimates [line items]
Impairment loss		$ 20
Sundance Unit 1 | Change in Useful Lives Estimate
Disclosure of changes in accounting estimates [line items]
Depreciation and amortization						26
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]
Depreciation and amortization						4
IFRS 15
Disclosure of changes in accounting estimates [line items]
IFRS 16 and 15 transition adjustments(1)				15	17
Contract liabilities (Note 5)				15	$ 88	$ 62
IFRS 16
Disclosure of changes in accounting estimates [line items]
Finance lease liabilities	63
Expense relating to leases of low-value assets for which recognition exemption has been used				(1)
Termination benefits expense				4
Undiscounted operating lease payments to be received				$ 83
Revisions in discount rates	(31)
Minimum | IFRS 16
Disclosure of changes in accounting estimates [line items]
Lease liabilities	42
Maximum | IFRS 16
Disclosure of changes in accounting estimates [line items]
Lease liabilities	$ 52

Accounting Changes - Disclosure

Accounting Changes - Disclosure of comparative information prepared under previous GAAP (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Disclosure of comparative information prepared under previous GAAP [line items]
Non-cancellable operating leases	$ 77	$ 80		$ 83
Profit (loss) [abstract]
Revenue from contracts with customers	2,347	2,249	$ 2,307
Fuel and purchased power	(1,086)	(1,100)	(1,016)
Interest expense	(179)	(250)	(247)
Net earnings (loss)	176	(90)	$ (118)
Statement of financial position [abstract]
Deferred income tax liabilities (Note 11)	472	501
Contract liabilities	14	80
Deficit	$ (1,455)	$ (1,496)

Significant Events - Clean Ener

Significant Events - Clean Energy Investment Plan (Details) $ in Millions	Oct. 30, 2019CAD ($)power_purchase_arrangementMW	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)
Investment [Line Items]
Property, plant and equipment expenditures		$ 417	$ 277	$ 338
Siemens F Class Gas Turbines And Related Equipment
Investment [Line Items]
Number of turbines acquired | power_purchase_arrangement	2
Capacity of facility (in megawatts) | MW	230
Property, plant and equipment expenditures	$ 84
Sundance Unit 5
Investment [Line Items]
Capacity of facility (in megawatts) | MW	730
Sundance Unit 5 | Minimum
Investment [Line Items]
Payments for development project expenditure		750
Sundance Unit 5 | Maximum
Investment [Line Items]
Payments for development project expenditure		$ 770

Significant Events - Agreement

Significant Events - Agreement to Construct and Own a Cogeneration Plant in Alberta (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)MW	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Oct. 01, 2019MW	Aug. 26, 2019CAD ($)	Mar. 29, 2018CAD ($)
Investment [Line Items]
Gains on disposals of investments	$ 88	$ 0	$ 0
Plant In Alberta
Investment [Line Items]
Capacity of facility (in megawatts) | MW				40
EBITDA	18
Plant In Alberta | Minimum
Investment [Line Items]
Payments for development project expenditure	105
Plant In Alberta | Maximum
Investment [Line Items]
Payments for development project expenditure	$ 115
Power Purchase Arrangement
Investment [Line Items]
Balancing pool compensation estimate, termination of contractual arrangement						$ 157
Termination of contractual arrangement, awarded amount					$ 56
SemCAMS | Plant In Alberta
Investment [Line Items]
Equity participation percentage	50.00%
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 paid (received)	$ (77)
Genesee Unit 3 | Capital Power
Investment [Line Items]
Equity participation percentage	10000.00%
Keephills 3
Investment [Line Items]
Capacity of facility (in megawatts) | MW	463
Equity participation percentage	100.00%
Proportion of ownership interest in joint operation	50.00%

Significant Events - Asset Acqu

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

Significant Events - Strategic

Significant Events - Strategic Investment by Brookfield (Details) - CAD ($) $ / shares in Units, $ in Millions	May 25, 2019	May 01, 2019	Mar. 25, 2019	Oct. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Investment [Line Items]
Proceeds on sale of Wintering Hills facility and Solomon disposition (Note 4)					$ 0	$ 2	$ 478
7% Unsecured Subordinated Debentures Due May 1, 2039
Investment [Line Items]
Interest rate		7.00%			7.00%
Investment Agreement
Investment [Line Items]
Consideration paid (received)					$ 7.5
Commitment fee					15
Capital commitments					$ 250
Investment Agreement | Brookfield Renewable Partners
Investment [Line Items]
Proceeds on sale of Wintering Hills facility and Solomon disposition (Note 4)	$ 750		$ 750
Other cash receipts from sales of equity or debt instruments of other entities, classified as investing activities		$ 350		$ 400
Proportion of ownership interests held by non-controlling interests					9.00%
Par value per share					$ 10
Fee expected to be paid for advice and recommendations in connection of operations					$ 1.5

Significant Events - Skookumchu

Significant Events - Skookumchuck Wind Energy Facility (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)MW	Dec. 31, 2019CAD ($)MW	Nov. 01, 2019MMcf	Dec. 17, 2018MMcf
Skookumchuck Wind Energy Facility
Investment [Line Items]
Proportion of ownership interest in joint operation	49.00%
Capacity of facility (in megawatts) | MW	136.8	136.8
Skookumchuck Wind Energy Facility | Minimum
Investment [Line Items]
Payments for development project expenditure	$ 150
Skookumchuck Wind Energy Facility | Maximum
Investment [Line Items]
Payments for development project expenditure	160
Tidewater Brazeau River Pipeline | Tidewater
Investment [Line Items]
Payments for development project expenditure	$ 83	$ 100
Future option to acquire pipeline, ownership percentage				50.00%
Natural gas pipeline capacity (mmcf) | MMcf			130	50

Significant Events - US Wind Pr

Significant Events - US Wind Projects (Details) $ in Millions, $ in Millions	Mar. 28, 2019CAD ($)	Mar. 28, 2019USD ($)	Feb. 20, 2018MW	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Jun. 28, 2018CAD ($)
Investment [Line Items]
Notes and debentures issued					$ 350
Issued preferred capital							$ 33
Receivables due from associates					52	$ 40
US Wind Projects - Big Level
Investment [Line Items]
Capacity of facility (in megawatts) | MW			90
Term of power purchase arrangement			15 years
Payments for development project expenditure	$ 7	$ 5
Value of equity consideration received				$ 85
US Wind Projects - Antrim
Investment [Line Items]
Capacity of facility (in megawatts) | MW			29
Term of power purchase arrangement			20 years
Consideration paid (received)	24
Loans and receivables	41
Investment property under construction or development	50
Intangible assets under development	$ 15
Value of equity consideration received				41
US Wind Projects
Investment [Line Items]
Notes and debentures issued					142	105
Issued preferred capital					$ 78	$ 59
US Wind Projects | Minimum
Investment [Line Items]
Payments for development project expenditure				250
US Wind Projects | Maximum
Investment [Line Items]
Payments for development project expenditure				$ 270

Significant Events - Normal Cou

Significant Events - Normal Course Issuer Bid (Details) - CAD ($) $ / shares in Units, $ in Millions	6 Months Ended	12 Months Ended
	Apr. 30, 2019	Dec. 31, 2019	May 27, 2019	Dec. 31, 2018	Mar. 09, 2018
Investment [Line Items]
Stock purchase agreement, Toronto Stock Exchange, twenty-five percent of daily trading volume	705,788
NCIB Program
Investment [Line Items]
Stock purchase agreement, number of shares authorized			14,000,000		14,000,000
Stock purchase agreement, maximum shares purchase for a single trading day		176,447
Number of shares issued and fully paid		7,716,300		3,264,500
Par value per share		$ 8.80		$ 7.02
Issued capital (Note 24)		$ 68		$ 23

Significant Events - Other Disc

Significant Events - Other Disclosures (Details) $ / shares in Units, $ in Millions, $ in Millions

Oct. 19, 2018MW

Aug. 02, 2018CAD ($)

Jul. 20, 2018CAD ($)

Jun. 28, 2018CAD ($)

Jun. 22, 2018CAD ($)$ / sharesshares

May 31, 2018CAD ($)MW

Mar. 15, 2018CAD ($)

Mar. 15, 2018USD ($)

Nov. 01, 2017USD ($)

Oct. 12, 2017CAD ($)

Oct. 02, 2017CAD ($)

Aug. 01, 2017USD ($)

Mar. 01, 2017CAD ($)

Nov. 18, 2016CAD ($)

Dec. 31, 2018CAD ($)MW

Jun. 30, 2018MW

Dec. 31, 2019CAD ($)

Dec. 31, 2018CAD ($)MW

Dec. 31, 2018USD ($)

Dec. 31, 2017CAD ($)MW

Dec. 31, 2016CAD ($)

Dec. 31, 2018USD ($)MW

Mar. 17, 2016shares

Investment [Line Items]

Transfer of equity from non-controlling interests

$ 1

Issued preferred capital

$ 33

Number of shares issued | shares

1,824,620

Net proceeds on sale of non-controlling interest in subsidiary (Note 4)

0

$ 144

$ 0

Bonds issued

$ 345

Borrowings, interest rate basis

4.509

Alberta Off-Coal Agreement

$ 40

40

40

$ 40

Alberta off-coal agreement, annual cash payments, net

$ 37

Borrowings

$ 3,267

3,212

3,267

Notional amount

$ 3,234

3,104

3,234

Reversal of unused provision

$ 1

$ 5

Force Majeure Relief Claim

Investment [Line Items]

Reversal of unused provision

$ 94

Kent Hills 3 Wind Project

Investment [Line Items]

Increase in contractual power capacity (in megawatts) | MW

167

Lakeswind

Investment [Line Items]

Impairment loss

12

Lakeswind | Property, plant and equipment

Investment [Line Items]

Impairment loss

11

Lakeswind | Intangible assets

Investment [Line Items]

Impairment loss

$ 1

Wintering Hills | Wind and Solar

Investment [Line Items]

Decrease through classified as held for sale, investment property

$ 28

Proceeds from sale of assets held for sale

$ 61

Windrise

Investment [Line Items]

Capacity of facility (in megawatts) | MW

207

207

207

Renewable electricity support agreement, term

20 years

Windrise | Minimum

Investment [Line Items]

Payments for development project expenditure

$ 270

Windrise | Maximum

Investment [Line Items]

Payments for development project expenditure

285

TransAlta Renewables

Investment [Line Items]

Number of shares issued | shares

11,860,000

Par value per share | $ / shares

$ 12.65

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 (Note 4)

$ 144

Number of shares outstanding | shares

161,000,000

Equity participation percentage

61.00%

TransAlta Renewables | Three Renewable Assets

Investment [Line Items]

Consideration paid (received)

$ 166

Value of equity consideration received

62

Portion of consideration paid (received) consisting of cash and cash equivalents

$ 104

TransAlta Renewables | Kent Breeze

Investment [Line Items]

Capacity of facility (in megawatts) | MW

20

TransAlta Renewables | Lakeswind Solar Projects

Investment [Line Items]

Capacity of facility (in megawatts) | MW

21

TransAlta Renewables | Lakeswind Wind Farm

Investment [Line Items]

Capacity of facility (in megawatts) | MW

50

New Brunswick Power Corporation | Kent Hills 3 Wind Project

Investment [Line Items]

Capacity of facility (in megawatts) | MW

17.25

Solomon Power Station | Fortescue Metals Group Limited

Investment [Line Items]

Consideration paid (received)

$ (335)

Portion of consideration paid (received) consisting of cash and cash equivalents

$ (325)

Kent Hills Wind L.P.

Investment [Line Items]

Interest rate

4.55%

Proportion of ownership interests held by non-controlling interests

17.00%

Kent Hills Wind L.P. | Kent Hills 3 Wind Project

Investment [Line Items]

Increase in contractual power capacity (in megawatts) | MW

17.25

Kent Hills Wind L.P. | Kent Hills 3 Wind Project | Natural Forces Technologies Inc.

Investment [Line Items]

Proportion of ownership interests held by non-controlling interests

17.00%

Debentures

Investment [Line Items]

Interest rate

6.40%

6.40%

Borrowings

$ 400

$ 647

$ 647

647

Redemption of noncurrent borrowings

425

Redemption of prepayment premium recognized in net interest expense

19

Notional amount

$ 651

651

$ 651

Accrued and unpaid interest

$ 6

Debentures | Minimum

Investment [Line Items]

Interest rate

5.00%

5.00%

5.00%

Debentures | Maximum

Investment [Line Items]

Interest rate

7.30%

7.30%

7.30%

Debentures | Canadian Hydro Developers Inc.

Investment [Line Items]

Redemption of noncurrent borrowings

$ 201

Redemption of prepayment premium recognized in net interest expense

6

Redemption of unsecured debt, principal

$ 191

Accrued and unpaid interest

$ 4

6.65% Senior notes, due May 2018

Investment [Line Items]

Interest rate

6.65%

6.65%

6.65%

6.65%

Borrowings

$ 500

$ 500

Redemption of noncurrent borrowings

$ 617

$ 516

$ 617

$ 516

Redemption of prepayment premium recognized in net interest expense

$ 5

5

Accrued and unpaid interest

$ 14

Bond, 4.454%, November 2033 maturity | Kent Hills Wind L.P.

Investment [Line Items]

Interest rate

4.454%

Notional amount

$ 260

Revenue (Details)

Revenue (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Canadian Coal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	$ 452
Canadian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	18
Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	2,095
Wind and Solar
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	8
Hydro
Disclosure of disaggregation of revenue from contracts with customers [line items]
Transaction price allocated to remaining performance obligations	72
Later than one year | Canadian Coal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	116
2023 | Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	223
Minimum | Canadian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	4
Minimum | Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	80
Minimum | Wind and Solar
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	1
Minimum | 2024 | Canadian Coal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	5
Minimum | More than five years | Canadian Coal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	40
Maximum | Canadian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	6
Maximum | Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	110
Maximum | Wind and Solar
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	2
Maximum | 2024 | Canadian Coal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	10
Maximum | More than five years | Canadian Coal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from performance obligations satisfied or partially satisfied in previous periods	$ 45

Revenue Disaggregation of Reven

Revenue Disaggregation of Revenue (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	$ 2,347	$ 2,249	$ 2,307
Goods or services transferred at point in time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	78	65
Goods or services transferred over time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	1,005	1,114
Contract With Customers [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	1,083	1,179
Lease Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	130	170
Contingent rents recognised as income, classified as operating lease			$ 247
Derivatives Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	296	165
Government Incentives [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	8	16
Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	830	719
Canadian Coal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	816	912
Canadian Coal | Goods or services transferred at point in time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	41	38
Canadian Coal | Goods or services transferred over time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	354	479
Canadian Coal | Contract With Customers [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	395	517
Canadian Coal | Lease Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	65	68
Canadian Coal | Derivatives Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	(17)	(1)
Canadian Coal | Government Incentives [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Canadian Coal | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	373	328
United States Coal
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	571	442
United States Coal | Goods or services transferred at point in time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	10	9
United States Coal | Goods or services transferred over time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
United States Coal | Contract With Customers [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	10	9
United States Coal | Lease Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
United States Coal | Derivatives Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	160	115
United States Coal | Government Incentives [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
United States Coal | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	401	318
Canadian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	209	232
Canadian Gas | Goods or services transferred at point in time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Canadian Gas | Goods or services transferred over time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	205	224
Canadian Gas | Contract With Customers [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	205	224
Canadian Gas | Lease Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Canadian Gas | Derivatives Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	2	4
Canadian Gas | Government Incentives [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Canadian Gas | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	2	4
Australian Gas
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	160	165
Australian Gas | Goods or services transferred at point in time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Australian Gas | Goods or services transferred over time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	87	91
Australian Gas | Contract With Customers [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	87	91
Australian Gas | Lease Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	65	68
Australian Gas | Derivatives Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Australian Gas | Government Incentives [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Australian Gas | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	8	6
Wind and Solar
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	312	282
Wind and Solar | Goods or services transferred at point in time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	27	18
Wind and Solar | Goods or services transferred over time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	217	188
Wind and Solar | Contract With Customers [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	244	206
Wind and Solar | Lease Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	27
Wind and Solar | Derivatives Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	18	(20)
Wind and Solar | Government Incentives [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	8	16
Wind and Solar | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	42	53
Hydro
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	156	156
Hydro | Goods or services transferred at point in time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Hydro | Goods or services transferred over time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	142	132
Hydro | Contract With Customers [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	142	132
Hydro | Lease Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	7
Hydro | Derivatives Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Hydro | Government Incentives [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Hydro | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	14	17
Energy Marketing
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	129	67
Energy Marketing | Goods or services transferred at point in time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Energy Marketing | Goods or services transferred over time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Energy Marketing | Contract With Customers [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Energy Marketing | Lease Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Energy Marketing | Derivatives Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	129	67
Energy Marketing | Government Incentives [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Energy Marketing | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Corporate
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	(6)	(7)
Corporate | Goods or services transferred at point in time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Corporate | Goods or services transferred over time [member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Corporate | Contract With Customers [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Corporate | Lease Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Corporate | Derivatives Income [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	4	0
Corporate | Government Incentives [Member]
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	0	0
Corporate | Others
Disclosure of disaggregation of revenue from contracts with customers [line items]
Revenue from contracts with customers	$ (10)	$ (7)

Revenue Contract Balances (Deta

Revenue Contract Balances (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Changes in Contract Liabilities [Roll Forward]
Contract liabilities at beginning of period	$ 80
Current contract liabilities	1	$ 8
Contract liabilities at end of period	14	80
IFRS 15
Changes in Contract Liabilities [Roll Forward]
Contract liabilities at beginning of period	88	62
IFRS 16 and 15 transition adjustments(1)	15	17
Amounts transferred to revenue included in opening balance	(10)	(10)
Consideration received	5	13
Increases due to interest accrued and expensed during the period	5	6
Contract termination associated with the purchase of Keephills 3 (Note 4(D))	(88)	0
Contract liabilities at end of period	$ 15	$ 88

Expenses by Nature - Expenses C

Expenses by Nature - Expenses Classified by Nature (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of products and services [line items]
Mine depreciation	$ 119	$ 136	$ 73
Salaries and benefits(1)	28	32	32
Other operating expenses	2	0	0
Total	1,086	1,100	1,016
Adjustments for increase (decrease) in employee benefit liabilities			90
Fuel and purchased power
Disclosure of products and services [line items]
Fuel(1)	669	656	685
Purchased power	246	210	162
Mine depreciation	119	136	73
Salaries and benefits(1)	52	98	96
Other operating expenses	0	0	0
Total	1,086	1,100	1,016
Operations, maintenance and administration
Disclosure of products and services [line items]
Fuel(1)	0	0	0
Purchased power	0	0	0
Mine depreciation	0	0	0
Salaries and benefits(1)	228	245	248
Other operating expenses	247	270	269
Total	$ 475	$ 515	$ 517

Asset Impairment Charges and _2

Asset Impairment Charges and Reversals (Details) - CAD ($) $ in Millions	Jun. 28, 2018	Dec. 31, 2019	Jun. 30, 2017	Sep. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2016	Dec. 31, 2012
Disclosure of impairment loss recognised or reversed [line items]
Write-downs (reversals of write-downs) of property, plant and equipment					$ 18	$ 23
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
Sundance Unit 1
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss			$ 20
Wintering Hills | Wind and Solar
Disclosure of impairment loss recognised or reversed [line items]
Decrease through classified as held for sale, investment property							$ 28
Property, plant and equipment | Centralia Plant CGU
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss								$ 347
Reversal of impairment loss					151
Provision for decommissioning, restoration and rehabilitation costs		$ 141			$ 141
Property, plant and equipment | Lakeswind
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss	11
Intangible assets | Lakeswind
Disclosure of impairment loss recognised or reversed [line items]
Impairment loss	$ 1

Finance Lease Receivables (Deta

Finance Lease Receivables (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	$ 220	$ 250
Present value of minimum lease receipts	191	215
Less: unearned finance lease income	29	35
Less: unearned finance lease income, present value	0	0
Total finance lease receivables	191	215
Current finance lease receivables	15	24
Long-term portion of finance lease receivable	176	191
Within one year
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	20	30
Present value of minimum lease receipts	20	29
Second to fifth years inclusive
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	80	80
Present value of minimum lease receipts	74	74
More than five years
Disclosure of recognised finance lease as assets by lessee [line items]
Minimum lease receipts	120	140
Present value of minimum lease receipts	$ 97	$ 112

Net Other Operating (Income) _3

Net Other Operating (Income) Losses Analysis of income and expenses (Details) - CAD ($) $ in Millions	Jul. 20, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Analysis of income and expenses [Line Items]
Alberta Off-Coal Agreement	$ (40)	$ (40)	$ (40)	$ (40)
Mississauga cogeneration facility NUG Contract		(1)	0	(9)
Insurance recoveries		(10)	(7)	0
Other operating expenses		2	0	0
Net other operating income		$ (49)	$ (47)	$ (49)

Net Other Operating (Income) _4

Net Other Operating (Income) Losses (Details) - CAD ($) $ in Millions	Jul. 20, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of types of insurance contracts [line items]
Alberta off-coal agreement, annual cash payments, gross	$ 40	$ 40	$ 40	$ 40
Alberta off-coal agreement, annual cash payments, net	$ 37
Mississauga cogeneration facility NUG Contract		1	0	9
Insurance recoveries		$ 10	7	$ 0
Canadian Coal | 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

Net Interest Expense (Details)

Net Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Analysis of income and expenses [Line Items]
Interest on debt	$ 161	$ 184	$ 218
Interest on exchangeable securities	20	0	0
Interest income	(13)	(11)	(7)
Capitalized interest	(6)	(2)	(9)
Loss on redemption of bonds (Note 23)	0	24	6
Interest on finance lease obligations	4	3	3
Credit facility fees, bank charges and other interest	15	13	18
Tax shield on tax equity financing	(35)	0	0
Other	10	15	(3)
Accretion of provisions	23	24	21
Interest expense	179	$ 250	$ 247
Project level financing that is no longer practicable
Analysis of income and expenses [Line Items]
Other	$ 5

Income Taxes - Rate Reconciliat

Income Taxes - Rate Reconciliations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Abstract]
Earnings before income taxes	$ 193	$ (96)	$ (54)
Net earnings attributable to non-controlling interests not subject to tax	(26)	(19)	(35)
Adjusted earnings before income taxes	$ 167	$ (115)	$ (89)
Statutory Canadian federal and provincial income tax rate	26.50%	26.80%	26.80%
Expected income tax expense (recovery)	$ 44	$ (31)	$ (24)
Increase (decrease) in income taxes resulting from:
Differences in effective foreign tax rates	5	(3)	(11)
Writedown (reversal of writedown) of deferred income tax assets	(9)	27	(15)
Statutory and other rate differences	(31)	0	110
Other	8	1	4
Income tax expense (recovery)	$ 17	$ (6)	$ 64
Effective tax rate	10.00%	5.00%	72.00%

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disposal Groups, Including Discontinued Operations [Line Items]
Current income tax expense(1)	$ 35	$ 28	$ 79
Deferred income tax expense (recovery) related to the origination and reversal of temporary differences	22	(61)	(110)
Deferred income tax expense resulting from changes in tax rates or laws	(31)	0	110
Writedown (reversal of writedown) of deferred income tax assets	(9)	27	(15)
Current income tax expense	35	28	79
Deferred income tax recovery	(18)	(34)	(15)
Income tax expense (recovery)	17	$ (6)	$ 64
Net deferred tax assets	6
Tax Cuts and Jobs Act of 2017, change in rage, deferred tax asset, income tax expense (benefit)	104
Tax Cuts and Jobs Act of 2017, change in tax Rate, deferred tax liability, income tax (expense) benefit	110
Deferred tax expense (income) recognised in profit or loss	1
Tax Cuts and Jobs Act of 2017, change in tax rate, deferred tax recovery	$ 111
Corporate tax rate	26.50%	26.80%	26.80%
Solomon Power Station
Disposal Groups, Including Discontinued Operations [Line Items]
Current income tax expense(1)			$ 56

Income Taxes - Aggregate Curren

Income Taxes - Aggregate Current and Deferred Income Tax Charged to Equity (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Abstract]
Net impact related to cash flow hedges	$ 6	$ (12)	$ (108)
Net impact related to net investment hedges	0	0	(7)
Net actuarial gains (losses)	(7)	5	(4)
Income tax expense reported in equity	$ (1)	$ (7)	$ (119)

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Income Tax Assets (Liabilities) (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Writedown of deferred income tax assets	$ (18)	$ (28)
Net deferred tax liabilities	(454)	(473)
Gross carrying amount | Net operating loss carryforwards
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	494	547
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)	122	113
Gross carrying amount | Property, plant and equipment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	(828)	(896)
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)	(141)	(145)
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)	56	68
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)	42	48
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)	40	35
Gross carrying amount | Deferred coal revenues
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	0	23
Gross carrying amount | Other deductible temporary differences
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	4	0
Accumulated impairment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Deferred tax liability (asset)	(211)	(207)
Writedown of deferred income tax assets	243	266
Net deferred tax liabilities	$ (454)	$ (473)

Income Taxes - Deferred Income

Income Taxes - Deferred Income Tax Liability Presentation (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Income Taxes [Abstract]
Deferred income tax assets	$ 18	$ 28
Deferred tax liabilities	(472)	(501)
Net deferred tax liabilities	$ (454)	$ (473)

Income Taxes - Contingencies (D

Income Taxes - Contingencies (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Uncertain tax positions
Disclosure of contingent liabilities [line items]
Provision for uncertain tax positions	$ 1	$ 0

Non-Controlling Interests - Sub

Non-Controlling Interests - Subsidiaries and Operations with Non-Controlling Interests (Details) shares in Millions

Oct. 19, 2018MW

Aug. 01, 2017shares

Jul. 31, 2017

Dec. 31, 2018

Jul. 30, 2018

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Nov. 29, 2018

Jun. 21, 2018

Dec. 31, 2019

Dec. 31, 2018

Jul. 31, 2017

TransAlta Cogeneration L.P.

Disclosure of subsidiaries [line items]

Proportion of ownership interests held by non-controlling interests

49.99%

49.99%

TransAlta Renewables

Disclosure of subsidiaries [line items]

Proportion of ownership interests held by non-controlling interests

39.60%

39.10%

Proportion of equity participation in subsidiary

60.90%

61.10%

60.40%

60.50%

60.60%

60.80%

61.00%

64.00%

59.80%

TransAlta Renewables | Kent Hills wind farm

Disclosure of subsidiaries [line items]

Proportion of ownership interests held by non-controlling interests

17.00%

TransAlta Renewables | Australian Assets

Disclosure of subsidiaries [line items]

Proportion of equity participation in subsidiary

64.00%

59.80%

TransAlta Renewables | Class B shares | Australian Assets

Disclosure of subsidiaries [line items]

Shares offered for conversion

26.1

TransAlta Renewables | Common shares | Australian Assets

Disclosure of subsidiaries [line items]

Equity securities received upon conversion of shares

26.4

Kent Hills 3 Wind Project

Disclosure of subsidiaries [line items]

Increase in contractual power capacity (in megawatts) | MW

167

Non-Controlling Interests - Sha

Non-Controlling Interests - Share of Ownership and Equity Participation in TransAlta Renewables (Details) - TransAlta Renewables	1 Months Ended		3 Months Ended				4 Months Ended	11 Months Ended	19 Months Ended
	Dec. 31, 2018	Jul. 30, 2018	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Nov. 29, 2018	Jun. 21, 2018	Jul. 31, 2017
Disclosure of subsidiaries [line items]
Equity participation percentage	60.90%	61.10%	60.40%	60.50%	60.60%	60.80%	61.00%	64.00%	64.00%
Proportion of equity participation in subsidiary	60.90%	61.10%	60.40%	60.50%	60.60%	60.80%	61.00%	64.00%	59.80%

Non-Controlling Interests - Ear

Non-Controlling Interests - Earnings of Subsidiaries with Non-Controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of subsidiaries [line items]
Revenues	$ 2,347	$ 2,249	$ 2,307
Net earnings (loss)	176	(90)	(118)
Total comprehensive income (loss)	131	(86)	(43)
Amounts attributable to the non-controlling interests:
Net earnings	94	108	42
Total comprehensive income	77	124	31
TransAlta Renewables
Disclosure of subsidiaries [line items]
Revenues	446	462	459
Net earnings (loss)	183	241	13
Total comprehensive income (loss)	138	281	(24)
Amounts attributable to the non-controlling interests:
Net earnings	73	94	11
Total comprehensive income	56	110	0
Distributions paid to non-controlling interests	69	79	85
TransAlta Cogeneration L.P.
Disclosure of subsidiaries [line items]
Revenues	181	185	175
Net earnings (loss)	43	29	61
Total comprehensive income (loss)	43	29	61
Amounts attributable to the non-controlling interests:
Net earnings	21	14	31
Total comprehensive income	21	14	31
Distributions paid to non-controlling interests	$ 37	$ 86	$ 87

Non-Controlling Interests - Fin

Non-Controlling Interests - Financial Position of Non-Controlling Interests (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of subsidiaries [line items]
Current assets	$ 1,341	$ 1,312
Current liabilities	(1,117)	(880)
Total equity	4,062	4,134	$ 4,385
Non-controlling interests (Note 12)	1,101	1,137
TransAlta Renewables
Disclosure of subsidiaries [line items]
Current assets	293	250
Long-term assets	3,409	3,497
Current liabilities	(152)	(159)
Long-term liabilities	(1,237)	(1,192)
Total equity	(2,313)	(2,396)
Non-controlling interests (Note 12)	$ (941)	$ (961)
Ownership and voting rights percentage	39.60%	39.10%
TransAlta Cogeneration L.P.
Disclosure of subsidiaries [line items]
Current assets	$ 41	$ 82
Long-term assets	328	354
Current liabilities	(27)	(54)
Long-term liabilities	(19)	(28)
Total equity	(323)	(354)
Non-controlling interests (Note 12)	$ (160)	$ (176)
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	5000.00%

Financial Instruments Carrying

Financial Instruments Carrying amounts and classifications of financial assets and liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of detailed information about financial instruments [line items]
Cash equivalents	$ 0	$ 0
Financial liabilities	3,212	3,267
Accounts payable and accrued liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	413	496
Accounts payable and accrued liabilities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	413	496
Dividends payable
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	37	58
Dividends payable | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	37	58
Credit facilities, long-term debt and finance lease obligations(2)
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,212	3,267
Credit facilities, long-term debt and finance lease obligations(2) | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	3,212	3,267
Exchangeable securities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	326
Exchangeable securities | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	326
Within one year | Risk management liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	81	90
Within one year | Derivatives | Risk management liabilities | Trading securities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	80	89
Within one year | Derivatives | Risk management liabilities | Hedging Liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	1	1
Later than one year | Risk management liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	29	41
Later than one year | Derivatives | Risk management liabilities | Trading securities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	28	40
Later than one year | Derivatives | Risk management liabilities | Hedging Liabilities
Disclosure of detailed information about financial instruments [line items]
Financial liabilities	1	1
Cash and cash equivalents
Disclosure of detailed information about financial instruments [line items]
Financial assets	411	89
Cash and cash equivalents | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	411	89
Restricted cash
Disclosure of detailed information about financial instruments [line items]
Financial assets	32	66
Restricted cash | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	32	66
Trade and other receivables
Disclosure of detailed information about financial instruments [line items]
Financial assets	462	756
Trade and other receivables | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	462	731
Trade and other receivables | Other financial assets (FVTPL)
Disclosure of detailed information about financial instruments [line items]
Financial assets		25
Long-term portion of finance lease receivable
Disclosure of detailed information about financial instruments [line items]
Financial assets	176	191
Long-term portion of finance lease receivable | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	176	191
Risk management assets | Within one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	166	146
Risk management assets | Later than one year
Disclosure of detailed information about financial instruments [line items]
Financial assets	640	662
Risk management assets | Hedging Asset | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	71	60
Risk management assets | Hedging Asset | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	607	629
Risk management assets | Trading securities | Within one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	95	86
Risk management assets | Trading securities | Later than one year | Derivatives
Disclosure of detailed information about financial instruments [line items]
Financial assets	33	33
Other assets
Disclosure of detailed information about financial instruments [line items]
Financial assets	47	52
Other assets | Amortized cost
Disclosure of detailed information about financial instruments [line items]
Financial assets	$ 47	37
Other assets | Other financial assets (FVTPL)
Disclosure of detailed information about financial instruments [line items]
Financial assets		$ 15

Financial Instruments Sensitivi

Financial Instruments Sensitivity ranges for the base fair values (Details) number in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	$ 3,104	$ 3,234
Long-term power sale – US | Long-term contracts
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	737	801
Unit contingent power purchases
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	(6)	18
Structured products – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	7	6
Full requirements – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	10	0
Long-term wind energy sale – Eastern US
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	(28)	(39)
Others
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Base fair value	$ 0	$ 9
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, financial instruments	(46)	(116)
Maximum | Unit contingent power purchases
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption, financial instruments	(1)	(4)
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, financial instruments	(2)	(5)
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, financial instruments	(3)	0
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, financial instruments	(20)	(21)
Maximum | Others
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption, financial instruments	(7)	(3)
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, financial instruments	139	116
Minimum | Unit contingent power purchases
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption, financial instruments	1	4
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, financial instruments	2	5
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, financial instruments	3	0
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, financial instruments	20	21
Minimum | Others
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity ranges for the base fair value, reasonably possible change in risk assumption, financial instruments	7	3

Financial Instruments (Details)

Financial Instruments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)MW	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)MW	Dec. 31, 2018CAD ($)	Dec. 31, 2019CAD ($)MW	Dec. 31, 2018CAD ($)MW	Dec. 31, 2017CAD ($)
Disclosure of detailed information about financial instruments [line items]
Risk management assets					$ 166	$ 146
Increase (decrease) in derivative forward power prices, reasonable possible	$ 9		$ 6
Decrease in base fair value				$ (11)
Decrease in sensitivity values		$ (2)
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
Unit contingent power purchases | Minimum
Disclosure of detailed information about financial instruments [line items]
Volume discount ranges, percent	2.20%	2.20%	2.20%	2.20%
Sensitivity analysis in derivative, price discount, percent	1.00%	1.00%	1.10%	1.10%
Sensitivity analysis in derivative, volume discount ranges, percent	8.60%	8.60%	8.60%	8.60%
Unit contingent power purchases | Maximum
Disclosure of detailed information about financial instruments [line items]
Volume discount ranges, percent	2.80%	2.80%	16.90%	16.90%
Sensitivity analysis in derivative, price discount, percent	2.00%	2.00%	1.90%	1.90%
Sensitivity analysis in derivative, volume discount ranges, percent	10.50%	10.50%	27.30%	27.30%
Structured products – Eastern US
Disclosure of detailed information about financial instruments [line items]
Sensitivity Analysis In Derivative, Implied Correlations, Percent	0.00%	0.00%
Sensitivity Analysis In Derivative, Implied Volatility And Correlation, Percent			3000.00%	3000.00%
Structured products – Eastern US | Minimum
Disclosure of detailed information about financial instruments [line items]
Basis relationship, percent	91.00%	91.00%	75.00%	75.00%
Non-standard shape factors, percent	63.00%	63.00%	63.00%	63.00%
Sensitivity analysis in derivative, basis relationship, percent	4.00%	4.00%	4.20%	4.20%
Sensitivity analysis in derivative, non-standard shape factors, percent	4.00%	4.00%	4.00%	4.00%
Implied volatility for shares, significant unobservable inputs, entity's own derivative	0.00%	0.00%	25.00%	25.00%
Implied correlations for shares, significant unobservable inputs, entity's own derivative			70.00%	70.00%
Sensitivity Analysis In Derivative, Implied Volatility, Percent	0.00%	0.00%	37.00%	37.00%
Structured products – Eastern US | Maximum
Disclosure of detailed information about financial instruments [line items]
Basis relationship, percent	112.00%	112.00%	109.00%	109.00%
Non-standard shape factors, percent	116.00%	116.00%	104.00%	104.00%
Sensitivity analysis in derivative, basis relationship, percent	6.00%	6.00%	6.90%	6.90%
Sensitivity analysis in derivative, non-standard shape factors, percent	10.00%	10.00%	9.30%	9.30%
Implied volatility for shares, significant unobservable inputs, entity's own derivative			84.00%	84.00%
Implied correlations for shares, significant unobservable inputs, entity's own derivative	0.00%	0.00%
Sensitivity Analysis In Derivative, Implied Volatility, Percent			49.00%	49.00%
Long-term wind energy sale – Eastern US
Disclosure of detailed information about financial instruments [line items]
Sensitivity Analysis In Derivative, Implied Correlations, Percent	10.00%	10.00%	10.00%	10.00%
Long-term contracts | UNITED STATES | Fixed-price contracts | Minimum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh	$ 20		$ 20
Long-term contracts | UNITED STATES | Fixed-price contracts | Maximum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh	28		35
Level III | Long-term contracts | Fixed-price contracts
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh	1		1
Level III | Long-term contracts | Fixed-price contracts | Minimum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh			7
Level III | Long-term contracts | Fixed-price contracts | Maximum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh	9		8
Level III | Long-term contracts | Forward contract
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh	6		6
Level III | Long-term contracts | Forward contract | Minimum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh	38		42
Level III | Long-term contracts | Forward contract | Maximum
Disclosure of detailed information about financial instruments [line items]
Forward power price ranges per MWh	$ 60		$ 68
Recurring fair value measurement | Level I
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic					$ (3)	$ 3
Recurring fair value measurement | Level III
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic					$ 686	$ 695	$ 771

Financial Instruments Fair valu

Financial Instruments Fair value of the commodity risk management assets and liabilities by classification level (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of risk management strategy related to hedge accounting [line items]
Foreign exchange gain (loss)	$ (15)	$ (15)	$ (1)
Gains recognized in other comprehensive income	(53)	(57)	(138)
Gains (losses) on cash flow hedges, before tax	77	(9)	136
Other
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic		(2)
Commodity risk management
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic		679
Recurring fair value measurement | Level I
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	(3)	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	9	(19)
Recurring fair value measurement | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Risk exposure associated with instruments sharing characteristic	686	695	771
Market price changes	(76)	(132)
Foreign exchange gain (loss)	(32)	72
Transfers into Level 3 of fair value hierarchy, assets	0	(4)
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	4	(2)
Non-recurring fair value measurement [member] | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Gains recognized in other comprehensive income	46	60
Gains (losses) on cash flow hedges, before tax	78	90
Unrealized gains included in earnings before income taxes relating to met assets held	2	(42)
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	678	689	719
Market price changes	(57)	(90)
Foreign exchange gain (loss)	(31)	67
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 recognized in other comprehensive income	46	60
Gains (losses) on cash flow hedges, before tax	57	90
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	8	6	$ 52
Market price changes	(19)	(42)
Foreign exchange gain (loss)	(1)	5
Transfers into Level 3 of fair value hierarchy, assets	0	(4)
Non-Hedges | Non-recurring fair value measurement [member] | Level III
Disclosure of risk management strategy related to hedge accounting [line items]
Gains recognized in other comprehensive income	0	0
Gains (losses) on cash flow hedges, before tax	21	0
Unrealized gains included in earnings before income taxes relating to met assets held	2	(42)
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	85	(16)
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	77	(7)
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	8	(9)
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	14	4
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	$ 14	$ 4

Financial Instruments Fair va_2

Financial Instruments Fair value of financial assets and liabilities measured at other than fair value (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	$ 3,212	$ 3,267
Long-term debt
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	3,070	3,204
Exchangeable securities
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	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	3,157	3,181
Recurring fair value measurement | Exchangeable securities | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	342
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	3,157	$ 3,181
Recurring fair value measurement | Level II | Exchangeable securities | Financial liabilities at fair value through profit or loss, category [member]
Disclosure of fair value measurement of liabilities [line items]
Financial liabilities	$ 342

Financial Instruments Inception

Financial Instruments Inception Gains And Losses (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ 49	$ 105	$ 148
New inception gains (losses)	3	(14)	12
Change in foreign exchange rates	0	5	(7)
Amortization recorded in net earnings during the year	(43)	(47)	(48)
Unamortized net gain at end of year	$ 9	$ 49	$ 105

Risk Management Activities - Ne

Risk Management Activities - Net Risk Management Assets and Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Financial Assets
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	$ 696	$ 677
Not designated as a hedge | Financial Liabilities
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	20
Not designated as a hedge | Financial Assets
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(10)
Commodity risk management
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		679
Commodity risk management | Financial Assets
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	692
Commodity risk management | Current
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	85	59
Commodity risk management | Long-term
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	607	620
Commodity risk management | Not designated as a hedge
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(8)
Commodity risk management | Not designated as a hedge | Financial Liabilities
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	16
Commodity risk management | Not designated as a hedge | Current
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	15
Commodity risk management | Not designated as a hedge | Long-term
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	1	(8)
Commodity risk management | Not designated as a hedge | Current
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		0
Other
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(2)
Other | Financial Assets
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	4
Other | Current
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	0	(3)
Other | Long-term
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	4	1
Other | Not designated as a hedge | Financial Liabilities
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(2)
Other | Not designated as a hedge | Current
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		(3)
Other | Not designated as a hedge | Long-term
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		1
Other | Not designated as a hedge | Financial Assets
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	4
Other | Not designated as a hedge | Current
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	0
Other | Not designated as a hedge | Long-term
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	4
Cash flow hedges | Designated as a hedge | Financial Assets
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	676	687
Cash flow hedges | Commodity risk management | Designated as a hedge
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		687
Cash flow hedges | Commodity risk management | Designated as a hedge | Financial Assets
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	676
Cash flow hedges | Commodity risk management | Designated as a hedge | Current
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	70	59
Cash flow hedges | Commodity risk management | Designated as a hedge | Long-term
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	606	628
Cash flow hedges | Other | Designated as a hedge
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic		0
Cash flow hedges | Other | Designated as a hedge | Financial Assets
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	0
Cash flow hedges | Other | Designated as a hedge | Current
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	0	0
Cash flow hedges | Other | Designated as a hedge | Long-term
Disclosure of detailed information about financial instruments [line items]
Risk exposure associated with instruments sharing characteristic	$ 0	$ 0

Risk Management Activities - _2

Risk Management Activities - Netting Arrangements (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current financial liabilities
Disclosure of detailed information about financial instruments [line items]
Gross financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	$ (191)	$ (116)
Gross financial assets set off against financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	140	53
Net financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	(51)	(63)
Long-term financial liabilities
Disclosure of detailed information about financial instruments [line items]
Gross financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	(100)	(42)
Gross financial assets set off against financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements	42	6
Net financial liabilities subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	(58)	(36)
Current financial assets
Disclosure of detailed information about financial instruments [line items]
Gross financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	316	224
Gross financial liabilities set off against financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	(140)	(53)
Net financial assets subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	176	171
Long-term financial assets
Disclosure of detailed information about financial instruments [line items]
Gross financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	631	657
Gross financial liabilities set off against financial assets subject to offsetting, enforceable master netting arrangements or similar agreements	(42)	(6)
Net financial assets subject to offsetting, enforceable master netting arrangements or similar agreements in statement of financial position	$ 589	$ 651

Risk Management Activities - He

Risk Management Activities - Hedging Instruments (Details) $ in Thousands, $ in Thousands, $ in Millions, kJ in Billions	12 Months Ended
	Dec. 31, 2019CAD ($)MWh	Dec. 31, 2018CAD ($)MWh	Dec. 31, 2017CAD ($)	Dec. 31, 2019J	Dec. 31, 2019kJ	Dec. 31, 2019	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2019AUD ($)	Dec. 31, 2018J	Dec. 31, 2018kJ	Dec. 31, 2018	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018AUD ($)
Disclosure of detailed information about financial instruments [line items]
Collateral paid (Note 15)								$ 42,000						$ 105,000
Notional amount								3,104,000						3,234,000
Hedging instrument, assets								7,000						10,000
Unrealized pre-tax gains (losses)	$ 1,000	$ 4,000	$ 2,000
Borrowings subject to floating interest rates						11.00%						14.00%
Gains (losses) on exchange differences on translation, net of tax	$ (38,000)	$ 43,000
Electricity | Non-Hedges | Commodity risk management
Disclosure of detailed information about financial instruments [line items]
Notional amount sold | MWh	16,097,000	58,885,000
Notional amount purchased | MWh	7,204,000	37,023,000
Electricity | Cash flow hedges | Commodity risk management
Disclosure of detailed information about financial instruments [line items]
Notional amount sold | MWh	222,000	2,128,000
Notional amount purchased | MWh	0	0
Long-term debt | Net investment hedges
Disclosure of detailed information about financial instruments [line items]
Notional amount							$ 370,000						$ 400,000
Long-term debt | Fair value hedges | Interest rate risk
Disclosure of detailed information about financial instruments [line items]
Notional amount							50,000						50,000
Physical power sales | Cash flow hedges | Commodity risk management
Disclosure of detailed information about financial instruments [line items]
Notional amount							400
Hedging instrument, assets								678,000						687,000
Notional amount purchased | MWh	23,000
Gain (loss) on hedge ineffectiveness	$ 47,000	$ 60,000
Reserve of cash flow hedges								527,000						508,000
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk
Disclosure of detailed information about financial instruments [line items]
Hedging instrument, assets														(7,000)
Hedging instrument, liabilities								0						5,000
Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Cash flow hedges | Currency risk
Disclosure of detailed information about financial instruments [line items]
Notional amount sold								124,000						0
Derivative, Notional Amount Purchased							95,000						0
Foreign Exchange Forward Contracts, Foreign-Denominated Debt [Member] | Discontinued Hedge Positions | Currency risk
Disclosure of detailed information about financial instruments [line items]
Notional amount sold								191,000						124,000
Derivative, Notional Amount Purchased							150,000						100
Hedging instrument, assets								6,000
Hedging instrument, liabilities														(10,000)
Natural gas | Non-Hedges | Commodity risk management
Disclosure of detailed information about financial instruments [line items]
Notional amount sold				38,062,000	80,413					80,413,000	74,194
Notional amount purchased				55,023,000	110,488					110,488,000	103,805
Transmission | Non-Hedges | Commodity risk management
Disclosure of detailed information about financial instruments [line items]
Notional amount sold | MWh	0	29,000
Notional amount purchased | MWh	1,818,000	11,163,000
Foreign-denominated debt | Net Investment Hedge | Currency risk
Disclosure of detailed information about financial instruments [line items]
Hedging instrument, assets								483,000						546
Gain (loss) on hedge ineffectiveness	$ 21,000	$ (41,000)
Minimum | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk
Disclosure of detailed information about financial instruments [line items]
Derivative, Notional Amount Purchased								139,000						205,000
Maximum | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk
Disclosure of detailed information about financial instruments [line items]
Derivative, Notional Amount Purchased								266,000						$ 214,000
Hedging instrument, liabilities								$ 4,000
U.S. Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk
Disclosure of detailed information about financial instruments [line items]
Notional amount sold							$ 108,000						$ 164,000
Australia, Dollars | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Discontinued Hedge Positions | Currency risk
Disclosure of detailed information about financial instruments [line items]
Notional amount sold									$ 286						$ 218
Reserve of exchange differences on translation
Disclosure of detailed information about financial instruments [line items]
Gains (losses) on exchange differences on translation, net of tax	$ 59,000	$ (84,000)

Risk Management Activities - Ef

Risk Management Activities - Effect on Cash Flow Hedges (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about financial instruments [line items]
Gains (losses) on cash flow hedges, before tax	$ 77	$ (9)	$ 136
Other comprehensive income that will be reclassified to profit or loss, net of tax	(19)	(11)	82
Gain (loss) on hedge ineffectiveness recognised in other comprehensive income	(53)	(57)	(138)
Gain (loss) on hedge ineffectiveness recognised in profit or loss	0	0	0
Accumulated other comprehensive income (Note 26)	454	481
Reserve of exchange differences on translation
Disclosure of detailed information about financial instruments [line items]
Accumulated other comprehensive income (Note 26)	(21)	17	(26)
Commodity contracts
Disclosure of detailed information about financial instruments [line items]
Gains (losses) on cash flow hedges, before tax	77	(9)	163
Foreign exchange forwards on project hedges
Disclosure of detailed information about financial instruments [line items]
Gains (losses) on cash flow hedges, before tax			(1)
Foreign exchange forwards on US debt
Disclosure of detailed information about financial instruments [line items]
Gains (losses) on cash flow hedges, before tax		0	0
Cross-currency swaps
Disclosure of detailed information about financial instruments [line items]
Gains (losses) on cash flow hedges, before tax			(26)
Forward starting interest rate swaps
Disclosure of detailed information about financial instruments [line items]
Gains (losses) on cash flow hedges, before tax	0	0	0
Revenue | Commodity contracts
Disclosure of detailed information about financial instruments [line items]
Gain (loss) on hedge ineffectiveness recognised in other comprehensive income	(59)	(67)	(172)
Gain (loss) on hedge ineffectiveness recognised in profit or loss	0	0	0
Property, plant and equipment | Foreign exchange forwards on project hedges
Disclosure of detailed information about financial instruments [line items]
Gain (loss) on hedge ineffectiveness recognised in other comprehensive income			0
Gain (loss) on hedge ineffectiveness recognised in profit or loss			0
Profit (Loss)
Disclosure of detailed information about financial instruments [line items]
Gain (loss) on hedge ineffectiveness recognised in profit or loss			31
Interest expense | Forward starting interest rate swaps
Disclosure of detailed information about financial instruments [line items]
Gain (loss) on hedge ineffectiveness recognised in other comprehensive income	6	7	7
Gain (loss) on hedge ineffectiveness recognised in profit or loss	0	0	0
Foreign exchange (gain) loss
Disclosure of detailed information about financial instruments [line items]
Gain (loss) on hedge ineffectiveness recognised in profit or loss			15
Foreign exchange (gain) loss | Foreign exchange forwards on US debt
Disclosure of detailed information about financial instruments [line items]
Gain (loss) on hedge ineffectiveness recognised in other comprehensive income		3	3
Gain (loss) on hedge ineffectiveness recognised in profit or loss		$ 0	0
Foreign exchange (gain) loss | Cross-currency swaps
Disclosure of detailed information about financial instruments [line items]
Gain (loss) on hedge ineffectiveness recognised in other comprehensive income			24
Gain (loss) on hedge ineffectiveness recognised in profit or loss			$ 0
Scenario, Forecast
Disclosure of detailed information about financial instruments [line items]
Other comprehensive income that will be reclassified to profit or loss, net of tax	$ 68

Risk Management Activities - No

Risk Management Activities - Non-Hedges (Details) $ in Millions, kJ in Billions	12 Months Ended
	Dec. 31, 2019CAD ($)MWh	Dec. 31, 2018CAD ($)MWh	Dec. 31, 2017CAD ($)	Dec. 31, 2019kJ	Dec. 31, 2019t	Dec. 31, 2019J	Dec. 31, 2019MW	Dec. 31, 2018kJ	Dec. 31, 2018t	Dec. 31, 2018J	Dec. 31, 2018MW
Disclosure of nature and extent of risks arising from financial instruments [line items]
Gains (losses) on change in fair value of derivatives | $	$ 33	$ 29	$ 45
Gains on change in fair value of derivatives | $	24	3	28
Unrealised Loss On Change In Fair Value Of Derivatives | $	6	4	(2)
Unrealised Gains On Change In Fair Value Of Derivatives | $	$ 18	$ (1)	$ 30
Electricity | Non-Hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount sold | MWh	16,097,000	58,885,000
Notional amount purchased | MWh	7,204,000	37,023,000
Natural gas | Non-Hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount sold				80,413		38,062,000		74,194		80,413,000
Notional amount purchased				110,488		55,023,000		103,805		110,488,000
Transmission | Non-Hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount sold | MWh	0	29,000
Notional amount purchased | MWh	1,818,000	11,163,000
Emissions | Non-Hedges | Commodity risk management
Disclosure of nature and extent of risks arising from financial instruments [line items]
Notional amount sold | MW							184,000				0
Notional amount purchased | MW							138,000				0
Notional amount sold | t					2,436,000				3,134,000
Notional amount purchased | t					2,446,000				2,948,000

Risk Management Activities - Fo

Risk Management Activities - Foreign Currency Rate Risk Management (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Financial Instruments [Abstract]
Gains (losses) on derivatives designated as cash flow hedges, net of tax	[1]	$ 61	$ (8)	$ 214
[1]	(5) Net of income tax expense of $16 million for the year ended Dec. 31, 2019 (2018 - $1 million recovery, 2017 - $77 million recovery).

Risk Management Activities - Ad

Risk Management Activities - Additional Information (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of nature and extent of risks arising from financial instruments [line items]
Collateral paid (Note 15)	$ 42	$ 105
Financial assets pledged as collateral for liabilities or contingent liabilities	3	17
Derivative, contingent feature, additional collateral requirement	51	120
Asset-backed debt instruments held	920
Debt instruments held	1,217
Commodity Price Risk - Proprietary Trading [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	1	2	$ 5
Commodity Price Risk - Generation [Member]
Disclosure of nature and extent of risks arising from financial instruments [line items]
Value at risk	25	18	16
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	8	13	$ 5
Letter of credit
Disclosure of nature and extent of risks arising from financial instruments [line items]
Collateral posted on derivative liabilities	$ 112	$ 120

Risk Management Activities - In

Risk Management Activities - Interest Rate Risk (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest rate risk
Disclosure of nature and extent of risks arising from financial instruments [line items]
Sensitivity Analysis For Types Of Market Risk, Reasonably Possible Change In Risk Variable, Percent	0.15%	0.15%	0.15%

Risk Management Activities - Se

Risk Management Activities - Sensitivity Analysis For Management Assessment (Details) - Currency risk - CAD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity analysis, Net earnings increase (decrease)	$ (24,000,000)	$ (20,000,000)	$ (12,000,000)
Sensitivity analysis, OCI gain	2,000,000	0	0
Sensitivity analysis, management assessment	0.04	0.04	0.04
U.S. Dollars
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity analysis, Net earnings increase (decrease)	(18,000,000)	(13,000,000)	(5,000,000)
Sensitivity analysis, OCI gain	2,000,000	0	0
Australia, Dollars
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Sensitivity analysis, Net earnings increase (decrease)	(6,000,000)	(7,000,000)	(7,000,000)
Sensitivity analysis, OCI gain	$ 0	$ 0	$ 0

Risk Management Activities - Cr

Risk Management Activities - Credit Risk (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of credit risk exposure [line items]
Maximum exposure to credit risk	$ 5	$ 13
Trade and other receivables	462	$ 756
Credit risk
Disclosure of credit risk exposure [line items]
Maximum exposure to credit risk	$ 1,491
Credit risk | Trade and other receivables
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Credit risk | Long-term portion of finance lease receivable
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Maximum exposure to credit risk	$ 176
Credit risk | Risk management assets
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Maximum exposure to credit risk	$ 806
Credit risk | Amortized cost
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Maximum exposure to credit risk	$ 47
Credit risk | Investment Grade [Member] | Trade and other receivables
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	85.00%
Credit risk | Investment Grade [Member] | Long-term portion of finance lease receivable
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Credit risk | Investment Grade [Member] | Risk management assets
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	99.00%
Credit risk | Investment Grade [Member] | Amortized cost
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	0.00%
Credit risk | Non-Investment Grade [Member] | Trade and other receivables
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	15.00%
Credit risk | Non-Investment Grade [Member] | Long-term portion of finance lease receivable
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	0.00%
Credit risk | Non-Investment Grade [Member] | Risk management assets
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	1.00%
Credit risk | Non-Investment Grade [Member] | Amortized cost
Disclosure of credit risk exposure [line items]
Credit risk, allocation percentage	100.00%
Trade and other receivables | Credit risk
Disclosure of credit risk exposure [line items]
Maximum exposure to credit risk	$ 462

Risk Management Activities - Ma

Risk Management Activities - Maturity (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)MWh$ / shares$ / shares	Jan. 01, 2019CAD ($)	Dec. 31, 2018CAD ($)
Disclosure of financial liabilities [line items]
Accounts payable and accrued liabilities	$ 413		$ 496
Borrowings	3,212		3,267
Exchangeable securities	326		0
Finance lease liabilities		$ 32
Dividends payable (Note 24 and 25)	37		$ 58
Liabilities	4,756
2020
Disclosure of financial liabilities [line items]
Liabilities	1,061
2021
Disclosure of financial liabilities [line items]
Liabilities	186
2022
Disclosure of financial liabilities [line items]
Liabilities	638
2023
Disclosure of financial liabilities [line items]
Liabilities	363
2024
Disclosure of financial liabilities [line items]
Liabilities	85
2025
Disclosure of financial liabilities [line items]
Liabilities	2,423
Gross carrying amount
Disclosure of financial liabilities [line items]
Accounts payable and accrued liabilities	413
Borrowings	3,104
Exchangeable securities	350
Derivative financial liabilities	(4)
Finance lease liabilities	142
Interest income on debt instruments held	1,283
Interest expense on borrowings	123
Dividends payable (Note 24 and 25)	37
Gross carrying amount | 2020
Disclosure of financial liabilities [line items]
Accounts payable and accrued liabilities	413
Borrowings	494
Exchangeable securities	0
Derivative financial liabilities	1
Finance lease liabilities	19
Interest income on debt instruments held	161
Interest expense on borrowings	25
Dividends payable (Note 24 and 25)	37
Gross carrying amount | 2021
Disclosure of financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	98
Exchangeable securities	0
Derivative financial liabilities	0
Finance lease liabilities	14
Interest income on debt instruments held	138
Interest expense on borrowings	25
Dividends payable (Note 24 and 25)	0
Gross carrying amount | 2022
Disclosure of financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	625
Exchangeable securities	0
Derivative financial liabilities	(6)
Finance lease liabilities	9
Interest income on debt instruments held	128
Interest expense on borrowings	25
Dividends payable (Note 24 and 25)	0
Gross carrying amount | 2023
Disclosure of financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	372
Exchangeable securities	0
Derivative financial liabilities	2
Finance lease liabilities	6
Interest income on debt instruments held	98
Interest expense on borrowings	24
Dividends payable (Note 24 and 25)	0
Gross carrying amount | 2024
Disclosure of financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	105
Exchangeable securities	0
Derivative financial liabilities	0
Finance lease liabilities	4
Interest income on debt instruments held	87
Interest expense on borrowings	24
Dividends payable (Note 24 and 25)	0
Gross carrying amount | 2025
Disclosure of financial liabilities [line items]
Accounts payable and accrued liabilities	0
Borrowings	1,410
Exchangeable securities	350
Derivative financial liabilities	(1)
Finance lease liabilities	90
Interest income on debt instruments held	671
Interest expense on borrowings	0
Dividends payable (Note 24 and 25)	0
Commodity risk management | Gross carrying amount
Disclosure of financial liabilities [line items]
Derivative financial liabilities	(692)
Commodity risk management | Gross carrying amount | 2020
Disclosure of financial liabilities [line items]
Derivative financial liabilities	(89)
Commodity risk management | Gross carrying amount | 2021
Disclosure of financial liabilities [line items]
Derivative financial liabilities	(89)
Commodity risk management | Gross carrying amount | 2022
Disclosure of financial liabilities [line items]
Derivative financial liabilities	(143)
Commodity risk management | Gross carrying amount | 2023
Disclosure of financial liabilities [line items]
Derivative financial liabilities	(139)
Commodity risk management | Gross carrying amount | 2024
Disclosure of financial liabilities [line items]
Derivative financial liabilities	(135)
Commodity risk management | Gross carrying amount | 2025
Disclosure of financial liabilities [line items]
Derivative financial liabilities	$ (97)
Non-Hedges | Electricity | Commodity risk management | 2020
Disclosure of financial liabilities [line items]
Notional amount | MWh	3,465,000
Average Power Prices | $ / shares	$ 67.82
Non-Hedges | Electricity | Commodity risk management | 2021
Disclosure of financial liabilities [line items]
Notional amount | MWh	3,424,000
Average Power Prices | $ / shares	$ 71.06
Non-Hedges | Electricity | Commodity risk management | 2022
Disclosure of financial liabilities [line items]
Notional amount | MWh	3,329,000
Average Power Prices | $ / shares	$ 73.55
Non-Hedges | Electricity | Commodity risk management | 2023
Disclosure of financial liabilities [line items]
Notional amount | MWh	3,329,000
Average Power Prices | $ / shares	$ 75.39
Non-Hedges | Electricity | Commodity risk management | 2024
Disclosure of financial liabilities [line items]
Notional amount | MWh	3,338,000
Average Power Prices | $ / shares	$ 77.28
Non-Hedges | Electricity | Commodity risk management | 2025
Disclosure of financial liabilities [line items]
Notional amount | MWh	2,628,000
Average Power Prices | $ / shares	$ 79.20
Non-Hedges | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Commodity risk management | 2020
Disclosure of financial liabilities [line items]
Notional amount | MWh	116,000,000
Average foreign exchange rate | $ / shares	0.7672
Non-Hedges | Foreign exchange forward contracts – foreign-denominated receipts/expenditures | Commodity risk management | 2021
Disclosure of financial liabilities [line items]
Notional amount | MWh	8,000,000
Average foreign exchange rate | $ / shares	0.7686

Risk Management Activities - Co

Risk Management Activities - Commodity Risk Management (Details) - Commodity risk management kJ in Billions	Dec. 31, 2019MWh	Dec. 31, 2019J	Dec. 31, 2019kJ	Dec. 31, 2019MW	Dec. 31, 2018MWh	Dec. 31, 2018J	Dec. 31, 2018kJ	Dec. 31, 2018MW
Electricity | Cash flow hedges
Disclosure of detailed information about hedges [line items]
Notional amount sold	222,000				2,128,000
Notional amount purchased	0				0
Electricity | Non-Hedges
Disclosure of detailed information about hedges [line items]
Notional amount sold	16,097,000				58,885,000
Notional amount purchased	7,204,000				37,023,000
Natural gas | Non-Hedges
Disclosure of detailed information about hedges [line items]
Notional amount sold		38,062,000	80,413			80,413,000	74,194
Notional amount purchased		55,023,000	110,488			110,488,000	103,805
Transmission | Non-Hedges
Disclosure of detailed information about hedges [line items]
Notional amount sold	0				29,000
Notional amount purchased	1,818,000				11,163,000
Emissions | Non-Hedges
Disclosure of detailed information about hedges [line items]
Notional amount sold | MW				184,000				0
Notional amount purchased | MW				138,000				0

Property, Plant, and Equipmen_3

Property, Plant, and Equipment (Details) - CAD ($) $ in Millions	Oct. 01, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Disclosure of detailed information about property, plant and equipment [line items]
Right-of-use assets		$ 146	$ 0
Property, plant and equipment expenditures		417	277	$ 338
Gains (losses) on disposals of property, plant and equipment		17
Other cash and cash equivalents		15
Interest costs capitalised		$ 6	$ 2	$ 9
Capitalisation rate of borrowing costs eligible for capitalisation		5.90%	4.50%
US Wind Projects
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures		$ 169
Pioneer Pipeline
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment expenditures		100
Genesee Unit 3
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		5
Keephills 3
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment	$ 308	308
IFRS 16
Disclosure of detailed information about property, plant and equipment [line items]
Assets under finance leases					$ (29)
Right-of-use assets		146	$ 52		$ 85
Mining property and equipment
Disclosure of detailed information about property, plant and equipment [line items]
Assets under finance leases		0	65
Gains (losses) on disposals of property, plant and equipment		18
Coal generation | Keephills 3
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		300
Property, plant and equipment subject to operating leases | IFRS 16
Disclosure of detailed information about property, plant and equipment [line items]
Right-of-use assets		33
Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		522	284
Gross carrying amount | Mining property and equipment
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		0	0
Gross carrying amount | Coal generation
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		0	0
Gross carrying amount | Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		$ 407	275
Gross carrying amount | Assets under construction | US Wind Projects - Big Level
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment			$ 7

Property, Plant, and Equipmen_4

Property, Plant, and Equipment - Reconciliation of the changes in the carrying amount of PP&E (Details) - CAD ($) $ in Millions	12 Months Ended
	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	$ 6,164	$ 6,578
Property, plant and equipment, end of the period	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	13,202	12,973
Additions other than through business combinations, property, plant and equipment	522	284
Acquisitions	439
Disposals	(704)	(7)
Retirement of assets	(201)	(90)
Change in foreign exchange rates	(134)	131
Transfers	(29)	(18)
Property, plant and equipment, end of the period	13,395	13,202
Gross carrying amount | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	(108)
Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(7,038)	(6,395)
Disposals	(439)	(5)
Impairment reversals	(297)
Retirement of assets	(190)	(83)
Change in foreign exchange rates	(76)	92
Transfers	(26)	(10)
Depreciation	(630)	(649)
Property, plant and equipment, end of the period	(7,188)	(7,038)
Accumulated depreciation | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	(46)
Land
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	94	95
Property, plant and equipment, end of the period	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	94	95
Additions other than through business combinations, property, plant and equipment	0	0
Acquisitions	0
Disposals	(2)	(3)
Retirement of assets	0	0
Change in foreign exchange rates	(1)	2
Transfers	0	0
Property, plant and equipment, end of the period	91	94
Land | Gross carrying amount | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	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	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
Land | Accumulated depreciation | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	0
Coal generation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	2,172	2,457
Property, plant and equipment, end of the period	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	5,937	5,888
Additions other than through business combinations, property, plant and equipment	0	0
Acquisitions	300
Disposals	(389)	0
Retirement of assets	(158)	(47)
Change in foreign exchange rates	(63)	105
Transfers	103	41
Property, plant and equipment, end of the period	6,116	5,937
Coal generation | Gross carrying amount | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	0
Coal generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(3,765)	(3,431)
Disposals	(170)	0
Impairment reversals	(297)
Retirement of assets	(158)	(56)
Change in foreign exchange rates	(52)	84
Transfers	10	0
Depreciation	(304)	(306)
Property, plant and equipment, end of the period	(3,996)	(3,765)
Coal generation | Accumulated depreciation | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	0
Gas generation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	836	910
Property, plant and equipment, end of the period	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	1,964	1,982
Additions other than through business combinations, property, plant and equipment	0	0
Acquisitions	0
Disposals	(260)	0
Retirement of assets	(26)	(17)
Change in foreign exchange rates	(40)	(13)
Transfers	22	13
Property, plant and equipment, end of the period	1,671	1,964
Gas generation | Gross carrying amount | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	0
Gas generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(1,128)	(1,072)
Disposals	(255)	0
Impairment reversals	0
Retirement of assets	(23)	(13)
Change in foreign exchange rates	(16)	(3)
Transfers	(11)	(7)
Depreciation	(77)	(79)
Property, plant and equipment, end of the period	(900)	(1,128)
Gas generation | Accumulated depreciation | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	0
Renewable generation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	2,125	2,191
Property, plant and equipment, end of the period	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	3,286	3,228
Additions other than through business combinations, property, plant and equipment	0	1
Acquisitions	0
Disposals	0	0
Retirement of assets	(7)	(6)
Change in foreign exchange rates	(17)	26
Transfers	319	51
Property, plant and equipment, end of the period	3,574	3,286
Renewable generation | Gross carrying amount | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	(7)
Renewable generation | Accumulated depreciation
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	(1,161)	(1,037)
Disposals	0	0
Impairment reversals	0
Retirement of assets	(3)	(2)
Change in foreign exchange rates	(4)	6
Transfers	(3)	(3)
Depreciation	(136)	(123)
Property, plant and equipment, end of the period	(1,284)	(1,161)
Renewable generation | Accumulated depreciation | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	(3)
Mining property and equipment
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	508	602
Property, plant and equipment, end of the period	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	1,338	1,315
Additions other than through business combinations, property, plant and equipment	0	0
Acquisitions	0
Disposals	(34)	(1)
Retirement of assets	(10)	(16)
Change in foreign exchange rates	(3)	7
Transfers	25	39
Property, plant and equipment, end of the period	1,226	1,338
Mining property and equipment | Gross carrying amount | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	(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	(830)	(713)
Disposals	(14)	(1)
Impairment reversals	0
Retirement of assets	(6)	(12)
Change in foreign exchange rates	(2)	5
Transfers	(22)	0
Depreciation	(97)	(125)
Property, plant and equipment, end of the period	(840)	(830)
Mining property and equipment | Accumulated depreciation | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	(43)
Assets under construction
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	200	95
Property, plant and equipment, end of the period	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	200	95
Additions other than through business combinations, property, plant and equipment	407	275
Acquisitions	139
Disposals	0	0
Retirement of assets	0	0
Change in foreign exchange rates	(4)	4
Transfers	(514)	(174)
Property, plant and equipment, end of the period	228	200
Assets under construction | Gross carrying amount | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	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	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
Assets under construction | Accumulated depreciation | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	0
Capital spares and other
Disclosure of detailed information about property, plant and equipment [line items]
Property, plant and equipment, beginning of the period	229	228
Property, plant and equipment, end of the period	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	383	370
Additions other than through business combinations, property, plant and equipment	115	8
Acquisitions	0
Disposals	(19)	(3)
Retirement of assets	0	(4)
Change in foreign exchange rates	(6)	0
Transfers	16	12
Property, plant and equipment, end of the period	489	383
Capital spares and other | Gross carrying amount | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	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	(154)	(142)
Disposals	0	(4)
Impairment reversals	0
Retirement of assets	0	0
Change in foreign exchange rates	(2)	0
Transfers	0	0
Depreciation	(16)	(16)
Property, plant and equipment, end of the period	(168)	(154)
Capital spares and other | Accumulated depreciation | Increase (Decrease) Due To Application of IFRS 16 [Member]
Disclosure of detailed information about property, plant and equipment [line items]
Increase (decrease) in property, plant and equipment	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	(23)	(32)
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	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	(62)	(12)
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	11	(1)
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	2	(3)
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	26	(16)
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	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	0	0
Poplar Creek | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges		(49)
Poplar Creek | Land | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges		0
Poplar Creek | Coal generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges		(38)
Poplar Creek | Gas generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges		0
Poplar Creek | Renewable generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges		(11)
Poplar Creek | Mining property and equipment | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges		0
Poplar Creek | Assets under construction | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges		0
Poplar Creek | Capital spares and other | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges		0
Wintering Hills | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	431
Wintering Hills | Land | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	0
Wintering Hills | Coal generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	448
Wintering Hills | Gas generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	0
Wintering Hills | Renewable generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	(2)
Wintering Hills | Mining property and equipment | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	(15)
Wintering Hills | Assets under construction | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	0
Wintering Hills | Capital spares and other | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Impairment charges	$ 0
Finance lease receivables | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		10
Finance lease receivables | Land | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		0
Finance lease receivables | Coal generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		0
Finance lease receivables | Gas generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		0
Finance lease receivables | Renewable generation | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		0
Finance lease receivables | Mining property and equipment | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		10
Finance lease receivables | Assets under construction | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		0
Finance lease receivables | Capital spares and other | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		0
US Wind Projects - Big Level | Assets under construction | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Additions other than through business combinations, property, plant and equipment		$ 7

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, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets	$ 146	$ 0
Property, plant and equipment	6,207	6,164	$ 6,578
Change in foreign exchange rates	0	5	(7)
Land
Disclosure of quantitative information about right-of-use assets [line items]
Property, plant and equipment	91	94	$ 95
IFRS 16
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets	146	52		$ 85
Right-of-use assets, increase (decrease) in revaluation surplus		(5)
Property, plant and equipment		38
Additions to right-of-use assets	81
Depreciation, right-of-use assets	(18)
Change in foreign exchange rates	(1)
Right-Of-Use Assets, Transfer	(1)
IFRS 16 | Land
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets	58	29		28
Right-of-use assets, increase (decrease) in revaluation surplus		(1)
Property, plant and equipment		0
Additions to right-of-use assets	32
Depreciation, right-of-use assets	(1)
Change in foreign exchange rates	(1)
Right-Of-Use Assets, Transfer	0
IFRS 16 | Buildings
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets	16	22		18
Right-of-use assets, increase (decrease) in revaluation surplus		(4)
Property, plant and equipment		0
Additions to right-of-use assets	2
Depreciation, right-of-use assets	(4)
Change in foreign exchange rates	0
Right-Of-Use Assets, Transfer	0
IFRS 16 | Vehicles
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets	2	1		4
Right-of-use assets, increase (decrease) in revaluation surplus		0
Property, plant and equipment		3
Additions to right-of-use assets	0
Depreciation, right-of-use assets	(2)
Change in foreign exchange rates	0
Right-Of-Use Assets, Transfer	0
IFRS 16 | Equipment
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets	25	0		35
Right-of-use assets, increase (decrease) in revaluation surplus		0
Property, plant and equipment		35
Additions to right-of-use assets	2
Depreciation, right-of-use assets	(11)
Change in foreign exchange rates	0
Right-Of-Use Assets, Transfer	(1)
IFRS 16 | Pipeline
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets	45	0		$ 0
Right-of-use assets, increase (decrease) in revaluation surplus		0
Property, plant and equipment		$ 0
Additions to right-of-use assets	45
Depreciation, right-of-use assets	0
Change in foreign exchange rates	0
Right-Of-Use Assets, Transfer	$ 0

Right of Use Assets - Narrative

Right of Use Assets - Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets	$ 146		$ 0
Lease liabilities		$ 52
Payments of lease liabilities, classified as financing activities	25
Interest expense on lease liabilities	4
Lease commitments for short-term leases for which recognition exemption has been used	2
Expense relating to variable lease payments not included in measurement of lease liabilities	6
IFRS 16
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use assets	146	$ 85	$ 52
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	Jun. 28, 2018	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		$ 373	$ 364
Ending balance		318	373
Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		807	744
Additions		14	53
Retirements and disposals(2)			(2)
Change in foreign exchange rates		(6)	3
Transfers		0	9
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		(5)
Acquisition		16
Disposals		(38)
Ending balance		788	807
Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		434	380
Retirements and disposals(2)			1
Change in foreign exchange rates		(1)	2
Transfers		0	3
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		(3)
Disposals		(10)
Amortization		50	50
Ending balance		470	434
Coal rights
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		68	53
Ending balance		32	68
Coal rights | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		185	178
Additions		0	0
Retirements and disposals(2)			0
Change in foreign exchange rates		0	0
Transfers		1	7
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		0
Acquisition		0
Disposals		(37)
Ending balance		149	185
Coal rights | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		117	125
Retirements and disposals(2)			0
Change in foreign exchange rates		0	0
Transfers		1	(17)
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		0
Disposals		(9)
Amortization		8	9
Ending balance		117	117
Software and other
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		118	126
Ending balance		132	118
Software and other | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		339	314
Additions		0	0
Retirements and disposals(2)			(2)
Change in foreign exchange rates		(4)	3
Transfers		48	24
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		(5)
Acquisition		1
Disposals		(1)
Ending balance		378	339
Software and other | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		221	188
Retirements and disposals(2)			1
Change in foreign exchange rates		(1)	2
Transfers		(1)	0
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		(3)
Disposals		(1)
Amortization		31	32
Ending balance		246	221
Power sale contracts
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		141	156
Ending balance		143	141
Power sale contracts | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		237	223
Additions		0	0
Retirements and disposals(2)			0
Change in foreign exchange rates		(1)	0
Transfers		14	14
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		0
Acquisition		0
Disposals		0
Ending balance		250	237
Power sale contracts | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		96	67
Retirements and disposals(2)			0
Change in foreign exchange rates		0	0
Transfers		0	(20)
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		0
Disposals		0
Amortization		11	9
Ending balance		107	96
Intangibles under development
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		46	29
Ending balance		11	46
Intangibles under development | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		46	29
Additions		14	53
Retirements and disposals(2)			0
Change in foreign exchange rates		(1)	0
Transfers		63	(36)
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		0
Acquisition		15
Disposals		0
Ending balance		11	46
Intangibles under development | Accumulated amortization
Reconciliation of changes in intangible assets other than goodwill [abstract]
Beginning balance		0	0
Retirements and disposals(2)			0
Change in foreign exchange rates		0	0
Transfers		0	0
Assets transferred to right of use assets on implementation of IFRS 16 (Note 3 and 18)		0
Disposals		0
Amortization		0	0
Ending balance		0	$ 0
US Wind Projects - Big Level | Gross carrying amount
Reconciliation of changes in intangible assets other than goodwill [abstract]
Additions		$ 33
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, 2019CAD ($)MWh	Dec. 31, 2018CAD ($)MWh
Disclosure of detailed information about intangible assets [line items]
Goodwill	$ 464	$ 464
Hydro
Disclosure of detailed information about intangible assets [line items]
Goodwill	258	259
Wind and Solar
Disclosure of detailed information about intangible assets [line items]
Goodwill	176	175
Energy Marketing
Disclosure of detailed information about intangible assets [line items]
Goodwill	$ 30	$ 30
Minimum
Disclosure of detailed information about intangible assets [line items]
Electricity prices | MWh	5	6
Discount rate used to calculate goodwill impairment	3.60%	5.30%
Maximum
Disclosure of detailed information about intangible assets [line items]
Electricity prices | MWh	183	179
Discount rate used to calculate goodwill impairment	7.00%	6.60%

Other Assets (Details)

Other Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure of financial assets [abstract]
South Hedland prepaid transmission access and distribution costs	$ 67	$ 72
Deferred licence fees	9	11
Project development costs	19	47
Deferred service costs	0	12
Long-term prepaids and other assets	56	55
Loan receivable	47	37
Total other assets	$ 198	$ 234

Other Assets Narrative (Details

Other Assets Narrative (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of joint operations [line items]
Loan receivable	$ 47	$ 37
Kent Hills Wind L.P.
Disclosure of joint operations [line items]
Loan receivable	$ 47	$ 37
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, 2019	Dec. 31, 2018
Reconciliation of changes in other provisions [abstract]
Balance	$ 456	$ 470
Liabilities incurred	14	22
Liabilities settled	(43)	(41)
Accretion	(23)	24
Acquisition of liabilities	19	8
Revisions in estimated cash flows	103	5
Revisions in discount rates	16	(37)
Reversals	(1)	(5)
Change in foreign exchange rates	(7)	10
Liabilities disposed	(32)
Balance	546	456
Decommissioning and restoration
Reconciliation of changes in other provisions [abstract]
Balance	407	437
Liabilities incurred	7	5
Liabilities settled	(34)	(31)
Accretion	(23)	24
Acquisition of liabilities	16	0
Revisions in estimated cash flows	96	2
Revisions in discount rates	16	(37)
Reversals	0	0
Change in foreign exchange rates	(7)	7
Liabilities disposed	(23)
Balance	501	407
Other
Reconciliation of changes in other provisions [abstract]
Balance	49	33
Liabilities incurred	7	17
Liabilities settled	(9)	(10)
Accretion	0	0
Acquisition of liabilities	3	8
Revisions in estimated cash flows	7	3
Revisions in discount rates	0	0
Reversals	(1)	(5)
Change in foreign exchange rates	0	3
Liabilities disposed	(9)
Balance	$ 45	$ 49

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of other provisions [line items]
Balance	$ 546	$ 456	$ 470
Current portion	58	70
Non-current portion	488	386
Decommissioning and restoration
Disclosure of other provisions [line items]
Balance	501	407	437
Current portion	36	35
Non-current portion	465	372
Other
Disclosure of other provisions [line items]
Balance	45	49	$ 33
Current portion	22	35
Non-current portion	$ 23	$ 14

Decommissioning and Other Pro_5

Decommissioning and Other Provisions - Decommissioning and Restoration (Details) $ in Millions, $ in Millions	Dec. 31, 2019CAD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2018USD ($)
Disclosure of detailed information about borrowings [line items]
Undiscounted cash flows required for future removal of facilities	$ 1,300
Centralia Coal Mine | Surety Bonds
Disclosure of detailed information about borrowings [line items]
Bonds issued		$ 147		$ 139
Alberta Mine | Letters Of Credit [Member]
Disclosure of detailed information about borrowings [line items]
Bonds issued	$ 128		$ 122

Credit Facilities, Long-Term _3

Credit Facilities, Long-Term Debt, and Finance Lease Obligations - Amounts Outstanding (Details) $ in Millions, $ in Millions	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Aug. 02, 2018CAD ($)	Jul. 20, 2018
Disclosure of detailed information about borrowings [line items]
Carrying value		$ 3,212		$ 3,267
Notional amount		3,104		3,234
Less: current portion of long-term debt		(494)		(130)
Less: current portion of finance lease obligations		(19)		(18)
Total current long-term debt and finance lease obligations		(513)		(148)
Credit facilities, long-term debt, and finance lease obligations (Note 22)		2,699		3,119
All Borrowings Except Finance Lease Obligations [Member]
Disclosure of detailed information about borrowings [line items]
Carrying value		3,070		3,204
Credit facilities
Disclosure of detailed information about borrowings [line items]
Carrying value		220		339
Notional amount		220		339
Debentures
Disclosure of detailed information about borrowings [line items]
Carrying value		647		647	$ 400
Notional amount		651		651
Interest rate					6.40%	6.40%
Senior notes
Disclosure of detailed information about borrowings [line items]
Carrying value		905		943
Notional amount		914		955
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		1,144		1,236
Notional amount		1,157		1,250
Non-recourse | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Notional amount	1		1
Other
Disclosure of detailed information about borrowings [line items]
Carrying value		154		39
Notional amount		162		39
Other | U.S. Dollars
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 117		$ 21
Finance lease obligation
Disclosure of detailed information about borrowings [line items]
Carrying value		$ 142		$ 63
Weighted average [member] | Credit facilities
Disclosure of detailed information about borrowings [line items]
Interest rate	3.50%	3.50%	3.80%	3.80%
Weighted average [member] | Debentures
Disclosure of detailed information about borrowings [line items]
Interest rate	5.80%	5.80%	5.80%	5.80%
Weighted average [member] | Senior notes
Disclosure of detailed information about borrowings [line items]
Interest rate	5.40%	5.40%	5.40%	5.40%
Weighted average [member] | Non-recourse
Disclosure of detailed information about borrowings [line items]
Interest rate	4.30%	4.30%	4.40%	4.40%
Weighted average [member] | Other
Disclosure of detailed information about borrowings [line items]
Interest rate	7.10%	7.10%	9.20%	9.20%

Credit Facilities, Long-Term _4

Credit Facilities, Long-Term Debt, and Finance Lease Obligations - Credit Facilities (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)
Disclosure of detailed information about borrowings [line items]
Line of credit facility, cancelled capacity			$ 200
Notional amount		$ 3,104		$ 3,234
Borrowings		3,212		3,267
Cash and cash equivalents		411		89	$ 314	$ 305
Restricted cash		32		66
US Wind Projects - Big Level
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)		15
Borrowing costs incurred		122
Tax equity funding	$ 85
Proceeds from tax equity funding		91
US Wind Projects - Antrim
Disclosure of detailed information about borrowings [line items]
Tax equity funding	$ 41
Accelerated tax depreciation		35
Lakeswind
Disclosure of detailed information about borrowings [line items]
Borrowing costs incurred		23
Syndicated Bank Credit Facility [Member]
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit		1,300
Committed Bilateral Credit Facilities Expiring In 2019 [Member]
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit		240
Credit facilities | Committed credit facilities
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit		2,200		2,000
Undrawn borrowing capacity under line of credit		1,300		900
Actual drawings on borrowings		220		339
Long-term Line Of Credit		900		1,100
Letter of credit | Committed credit facilities
Disclosure of detailed information about borrowings [line items]
Long-term Line Of Credit		690		720
Corporation and TransAlta Renewables | Syndicated Bank Credit Facility [Member]
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit		2,000		1,800
Line of credit facility, increase (decrease)				250
Line of credit facility, increase (decrease)				250
TransAlta Renewables | Syndicated Bank Credit Facility [Member]
Disclosure of detailed information about borrowings [line items]
Maximum borrowing capacity under line of credit		700		500
Line of credit facility, increase (decrease)		200
Line of credit facility, increase (decrease)		200
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)		17		35
Restricted cash and cash equivalents, principal amount		(10)
Restricted cash		$ 10		$ 27

Credit Facilities, Long-Term _5

Credit Facilities, Long-Term Debt, and Finance Lease Obligations - Debentures (Details) - CAD ($) $ in Millions	Aug. 02, 2018	Jul. 20, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about borrowings [line items]
Notional amount			$ 3,104	$ 3,234
Borrowings			3,212	3,267
Alberta off-coal agreement, annual cash payments, gross		$ 40	40	40	$ 40
Alberta off-coal agreement, annual cash payments, net		$ 37
Debentures
Disclosure of detailed information about borrowings [line items]
Notional amount			651	651
Redemption of unsecured debt	$ 425
Redemption of prepayment premium recognized in net interest expense	19
Accrued and unpaid interest	$ 6
Interest rate	6.40%	6.40%
Borrowings	$ 400		$ 647	$ 647
Debentures | Minimum
Disclosure of detailed information about borrowings [line items]
Interest rate				5.00%
Debentures | Maximum
Disclosure of detailed information about borrowings [line items]
Interest rate				7.30%

Credit Facilities, Long-Term _6

Credit Facilities, Long-Term Debt, and Finance Lease Obligations - Senior Notes (Details) $ in Millions, $ in Millions	Mar. 15, 2018USD ($)	Mar. 15, 2018CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD ($)
Disclosure of detailed information about borrowings [line items]
Notional amount					$ 3,104	$ 3,234
Borrowings					$ 3,212	$ 3,267
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%		6.65%			6.65%
Borrowings	$ 500		$ 500
Redemption of noncurrent borrowings	$ 516	$ 617	$ 516	$ 617
Redemption of prepayment premium recognized in net interest expense		$ 5		5
Accrued and unpaid interest				$ 14
4.75% Senior Notes due 2015 | Senior notes
Disclosure of detailed information about borrowings [line items]
Interest rate							1.90%	1.90%
Notional amount							$ 400
Borrowings								$ 434
Non-Recourse Bonds
Disclosure of detailed information about borrowings [line items]
Interest rate			4.509%			4.509%

Credit Facilities, Long-Term _7

Credit Facilities, Long-Term Debt, and Finance Lease Obligations - Non-Recourse Debt (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Jul. 20, 2018CAD ($)
Disclosure of detailed information about borrowings [line items]
Notional amount		$ 3,104	$ 3,234
Borrowings		$ 3,212	$ 3,267
Bonds issued				$ 345
Non-Recourse Bonds
Disclosure of detailed information about borrowings [line items]
Interest rate			4.509%
Principal payment	$ 25
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		6.03%
TransAlta OCP | Non-Recourse Bonds
Disclosure of detailed information about borrowings [line items]
Notional amount			$ 345
TAPC Holdings | Variable Rate Bond due 2030 | Non-recourse debt | Canadian Dollar Offered Rate
Disclosure of detailed information about borrowings [line items]
Borrowings, adjustment to interest rate basis			3.95%

Credit Facilities, Long-Term _8

Credit Facilities, Long-Term Debt, and Finance Lease Obligations - Other (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about borrowings [line items]
Notional amount	$ 3,104	$ 3,234
Property, plant and equipment	6,207	6,164	$ 6,578
Intangible assets	318	$ 373	$ 364
Other | 5.9% Unsecured Commercial Loan Obligation due 2023
Disclosure of detailed information about borrowings [line items]
Interest rate		5.90%
Non-recourse
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)	42	$ 33
Non-recourse | Secured by first rate ranking charge over subsidiaries
Disclosure of detailed information about borrowings [line items]
Notional amount	719	766
Non-recourse | Secured by equity interests of the issuer
Disclosure of detailed information about borrowings [line items]
Notional amount	119	127
Renewable generation facilities
Disclosure of detailed information about borrowings [line items]
Property, plant and equipment	967	1,021
Intangible assets	63	70
TransAlta OCP
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)	17	35
TransAlta OCP | Secured Debt
Disclosure of detailed information about borrowings [line items]
Notional amount	305	342
Kent Hills Wind L.P.
Disclosure of detailed information about borrowings [line items]
Restricted cash (Note 22)	$ 0	$ 31
Interest rate	4.55%

Credit Facilities, Long-Term _9

Credit Facilities, Long-Term Debt, and Finance Lease Obligations - Restrictions on Non-Recourse Debt and Security (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Jul. 20, 2018	Dec. 31, 2017
Disclosure of detailed information about borrowings [line items]
Debentures issued	$ 350
Other borrowings	326	$ 0
Borrowings	3,212	3,267
Property, plant and equipment	6,207	6,164		$ 6,578
Bonds issued			$ 345
Non-recourse debt
Disclosure of detailed information about borrowings [line items]
Other borrowings	1,143	1,235
Restricted cash (Note 22)	42	33
Renewable generation facilities
Disclosure of detailed information about borrowings [line items]
Property, plant and equipment	$ 967	$ 1,021

Credit Facilities, Long-Term_10

Credit Facilities, Long-Term Debt, and Finance Lease Obligations - Principal Repayments (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Disclosure of detailed information about borrowings [line items]
Borrowings	$ 3,212		$ 3,267
Finance lease liabilities		$ 32
Gross carrying amount
Disclosure of detailed information about borrowings [line items]
Borrowings	3,104
Finance lease liabilities	142
Gross carrying amount | 2020
Disclosure of detailed information about borrowings [line items]
Borrowings	494
Finance lease liabilities	19
Gross carrying amount | 2021
Disclosure of detailed information about borrowings [line items]
Borrowings	98
Finance lease liabilities	14
Gross carrying amount | 2022
Disclosure of detailed information about borrowings [line items]
Borrowings	625
Finance lease liabilities	9
Gross carrying amount | 2023
Disclosure of detailed information about borrowings [line items]
Borrowings	372
Finance lease liabilities	6
Gross carrying amount | 2024
Disclosure of detailed information about borrowings [line items]
Borrowings	105
Finance lease liabilities	4
Gross carrying amount | 2025
Disclosure of detailed information about borrowings [line items]
Borrowings	1,410
Finance lease liabilities	$ 90

Credit Facilities, Long-Term_11

Credit Facilities, Long-Term Debt, and Finance Lease Obligations - Letters of Credit (Details) - CAD ($)	Dec. 31, 2019	Dec. 31, 2018
Letter of credit
Disclosure of detailed information about borrowings [line items]
Exposure to credit risk on loan commitments and financial guarantee contracts	$ 690,000,000	$ 720,000,000
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
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 ($) $ in Millions	May 25, 2019	May 01, 2019	Mar. 25, 2019	Oct. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of detailed information about borrowings [line items]
Proceeds on sale of Wintering Hills facility and Solomon disposition (Note 4)					$ 0	$ 2	$ 478
Notes and debentures issued					350
Gross carrying amount
Disclosure of detailed information about borrowings [line items]
Notes and debentures issued					$ 326
7% Unsecured Subordinated Debentures Due May 1, 2039
Disclosure of detailed information about borrowings [line items]
Interest rate		7.00%			7.00%
Brookfield Renewable Partners | Investment Agreement
Disclosure of detailed information about borrowings [line items]
Proceeds on sale of Wintering Hills facility and Solomon disposition (Note 4)	$ 750		$ 750
Other cash receipts from sales of equity or debt instruments of other entities, classified as investing activities		$ 350		$ 400

Defined Benefit Obligation an_3

Defined Benefit Obligation and Other Long-Term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Subclassifications of assets, liabilities and equities [abstract]
Defined benefit obligation (Note 28)	$ 268	$ 227
Long-term incentive accruals (Note 27)	4	9
Other	29	51
Total	$ 301	$ 287

Common Shares - Issued and Outs

Common Shares - Issued and Outstanding (Details) - CAD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of classes of share capital [line items]
Proceeds from exercise of options	$ 2	$ 0
Common shares
Dilutive effect of share options on number of ordinary shares	0.1	0
Common shares
Disclosure of classes of share capital [line items]
Issued and outstanding, end of year	$ 3,059	$ 3,094
Proceeds from issuing shares	(83)	(35)
Issued Capital, Amount Before Receivables Under Employee Share Purchase Plan	2,978	3,059
Issued and outstanding, end of year	$ 2,978	$ 3,059
Common shares
Issued and outstanding, beginning of year	284.6	287.9
Shares issued	(7.7)	(3.3)
Issued and outstanding, end of year	277	284.6

Common Shares - The effects of

Common Shares - The effects of the Corporation's purchase and cancellation of the common shares (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of classes of share capital [line items]
Deficit	$ (1,455)	$ (1,496)
NCIB Program
Disclosure of classes of share capital [line items]
Number of shares issued and fully paid	7,716,300	3,264,500
Par value per share	$ 8.80	$ 7.02
Issued capital (Note 24)	$ 68	$ 23
Weighted average share price	83	35
Deficit	15	12
Common shares
Disclosure of classes of share capital [line items]
Issued capital (Note 24)	$ 2,978	$ 3,059	$ 3,094

Common Shares - Shareholder Rig

Common Shares - Shareholder Rights Plan (Details)	12 Months Ended
	Dec. 31, 2019
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, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings per share [abstract]
Net earnings (loss) attributable to common shareholders	$ 52	$ (248)	$ (190)
Basic and diluted weighted average number of common shares outstanding (millions)	283	287	288
Net earnings (loss) per share attributable to common shareholders, basic and diluted (in CAD per share)	$ 0.18	$ (0.86)	$ (0.66)

Common Shares - Dividends (Deta

Common Shares - Dividends (Details) - $ / shares	Jan. 26, 2020	Oct. 09, 2019	Dec. 14, 2018
Share Capital, Reserves And Other Equity Interest [Abstract]
Dividends declared per share	$ 0.0425	$ 0.04	$ 0.04

Preferred Shares - Issued and O

Preferred Shares - Issued and Outstanding (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Mar. 17, 2016
Disclosure of classes of share capital [line items]
Number of shares issued and outstanding			1,824,620
Preferred Shares
Disclosure of classes of share capital [line items]
Number of shares outstanding	38,600,000	38,600,000
Number of shares issued and outstanding	38,600,000	38,600,000
Issued capital (Note 25)	$ 942	$ 942
Series A
Disclosure of classes of share capital [line items]
Number of shares outstanding	10,200,000	10,200,000	12,000,000
Number of shares issued and outstanding	10,200,000	10,200,000
Issued capital (Note 25)	$ 248	$ 248
Series B
Disclosure of classes of share capital [line items]
Number of shares outstanding	1,800,000	1,800,000
Number of shares issued and outstanding	1,800,000	1,800,000
Issued capital (Note 25)	$ 45	$ 45
Series C
Disclosure of classes of share capital [line items]
Number of shares outstanding	11,000,000	11,000,000
Number of shares issued and outstanding	11,000,000	11,000,000
Issued capital (Note 25)	$ 269	$ 269
Series E
Disclosure of classes of share capital [line items]
Number of shares outstanding	9,000,000	9,000,000
Number of shares issued and outstanding	9,000,000	9,000,000
Issued capital (Note 25)	$ 219	$ 219
Series G
Disclosure of classes of share capital [line items]
Number of shares outstanding	6,600,000	6,600,000
Number of shares issued and outstanding	6,600,000	6,600,000
Issued capital (Note 25)	$ 161	$ 161

Preferred Shares - Series A Cum

Preferred Shares - Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion (Details) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Mar. 17, 2016
Disclosure of classes of share capital [line items]
Number of shares issued upon conversion				1,824,620
Series A
Disclosure of classes of share capital [line items]
Number of shares converted into other classes of shares				1,824,620
Number of shares issued upon conversion	10,200,000	10,200,000
Number of shares outstanding	10,200,000	10,200,000		12,000,000
Payment period for cumulative preferential cash dividends	5 years
Annualized fixed dividend rate	2.709%
Series F
Disclosure of classes of share capital [line items]
Shares Required To Cause Conversion of Securities, Trigger	1,000,000
Series B
Disclosure of classes of share capital [line items]
Number of shares issued upon conversion	1,800,000	1,800,000
Number of shares outstanding	1,800,000	1,800,000
Payment period for cumulative preferential cash dividends	5 years
Annualized fixed dividend rate	2.03%
Series E
Disclosure of classes of share capital [line items]
Number of shares converted into other classes of shares			0
Number of shares issued upon conversion	9,000,000	9,000,000
Number of shares outstanding	9,000,000	9,000,000
Annualized fixed dividend rate	5.194%
Series D
Disclosure of classes of share capital [line items]
Shares Required To Cause Conversion of Securities, Trigger	1,000,000
Series C
Disclosure of classes of share capital [line items]
Number of shares converted into other classes of shares			0
Number of shares issued upon conversion	11,000,000	11,000,000
Number of shares outstanding	11,000,000	11,000,000
Annualized fixed dividend rate	4.027%
Series G
Disclosure of classes of share capital [line items]
Number of shares issued upon conversion	6,600,000	6,600,000
Shares Required To Cause Conversion of Securities, Trigger	1,000,000
Number of shares outstanding	6,600,000	6,600,000
Annualized fixed dividend rate	4.988%

Preferred Shares - Preferred Sh

Preferred Shares - Preferred Share Series Information (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Aug. 30, 2019	Sep. 17, 2017	Jun. 16, 2017
Series E
Disclosure of classes of share capital [line items]
Convertible preferred shares tendered for conversion			133,969
Annualized fixed dividend rate	5.194%
Bond yield	1.544%
Dividend rate on preference shares, term	3.65%
Preferred Shares
Disclosure of classes of share capital [line items]
Fixed rate reset term	5 years
Amount per share redeemable at reset date	$ 25
Series C
Disclosure of classes of share capital [line items]
Convertible preferred shares tendered for conversion				827,628
Annualized fixed dividend rate	4.027%
Bond yield	0.927%
Dividend rate on preference shares, term	3.10%
Series G
Disclosure of classes of share capital [line items]
Convertible preferred shares tendered for conversion		140,730
Annualized fixed dividend rate	4.988%
Bond yield	1.188%
Dividend rate on preference shares, term	3.80%

Preferred Shares - Characterist

Preferred Shares - Characteristics Specific to Series of Preferred Shares (Details)	12 Months Ended
	Dec. 31, 2019$ / shares
Series A
Disclosure of classes of share capital [line items]
Annual dividend rate per share	$ 0.67725
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	$ 0.93575
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	$ 1.00675
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	$ 1.29850
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	$ 1.32500
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 ($) $ / shares in Units, $ in Millions	Jan. 26, 2020	Oct. 09, 2019	Dec. 14, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of classes of share capital [line items]
Dividends declared per share	$ 0.0425	$ 0.04	$ 0.04
Series A
Disclosure of classes of share capital [line items]
Dividends declared				$ 5	$ 9	$ 5
Series B
Disclosure of classes of share capital [line items]
Dividends declared				1	1	1
Series C
Disclosure of classes of share capital [line items]
Dividends declared				8	14	9
Series E
Disclosure of classes of share capital [line items]
Dividends declared				9	15	8
Series G
Disclosure of classes of share capital [line items]
Dividends declared				7	11	7
Preferred Shares
Disclosure of classes of share capital [line items]
Dividends declared				$ 30	$ 50	$ 30

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		$ 481
Currency translation adjustment
Losses on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		38	$ (43)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax	[1]	21	(41)	$ 50
Cash flow hedges
Gains (losses) on derivatives designated as cash flow hedges, net of tax	[2]	61	(8)	214
Other
Intercompany FVOCI investments		0	0
Accumulated other comprehensive income, end of the period		454	481
Income tax relating to hedges of net investments in foreign operations of other comprehensive income		0	0	2
Net impact related to cash flow hedges		6	(12)	(108)
Income tax relating to net actuarial gains (losses)		(7)	5	(4)
Reserve of exchange differences on translation
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		17	(26)
Currency translation adjustment
Losses on translating net assets of foreign operations, net of reclassifications to net earnings, net of tax		(59)	84
Gains (losses) on financial instruments designated as hedges of foreign operations, net of tax		21	(41)
Other
Accumulated other comprehensive income, end of the period		(21)	17	(26)
Reserve of cash flow hedges [member]
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		508	562
Cash flow hedges
Gains (losses) on derivatives designated as cash flow hedges, net of tax		19	(54)
Other
Accumulated other comprehensive income, end of the period		527	508	562
Net impact related to cash flow hedges		(6)	12
Reserve of remeasurements of defined benefit plans [member]
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(29)	(44)
Employee future benefits
Net actuarial gains (losses) on defined benefit plans, net of tax		(26)	15
Other
Accumulated other comprehensive income, end of the period		(55)	(29)	(44)
Income tax relating to net actuarial gains (losses)		7	5
Other reserves [member]
Components and changes in accumulated other comprehensive Income (loss)
Accumulated other comprehensive income, beginning of the period		(15)	(3)
Other
Change in ownership of TransAlta Renewables		1	4
Intercompany FVOCI investments	[3]	17
Intercompany Available-For-Sale Investments			(16)
Accumulated other comprehensive income, end of the period		$ 3	$ (15)	$ (3)
[1]	(3) Net of income tax expense of nil for the year ended Dec. 31, 2019 (2018 - nil, 2017 - $2 million expense).
[2]	(5) Net of income tax expense of $16 million for the year ended Dec. 31, 2019 (2018 - $1 million recovery, 2017 - $77 million recovery).
[3]	(1) Refer to Note 28 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, 2019CAD ($)shares$ / shares	Dec. 31, 2018CAD ($)shares	Dec. 31, 2017CAD ($)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
Executive officers
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of share options granted (in shares) | shares	1.4
Exercise price of share options granted (in dollars per share)	$ 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)	$ 19,000,000	8,000,000	$ 15,000,000
Vesting period	3 years
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
Vesting period	3 years
DSUs
Disclosure of terms and conditions of share-based payment arrangement [line items]
Compensation expense (reversal)	$ 2,000,000	0	1,000,000
Stock Options
Disclosure of terms and conditions of share-based payment arrangement [line items]
Number of shares authorized (in shares) | shares				13
Stock Options | Executive officers
Disclosure of terms and conditions of share-based payment arrangement [line items]
Vesting period	3 years
Compensation expense (reversal)	$ 1,000,000	$ 1,000,000	$ 1,000,000
Number of share options granted (in shares) | shares		0.7	0.7
Exercise price of share options granted (in dollars per share)			$ 7.25
Expiration period of shares granted	7 years
Vesting period	3 years
Expiration period of shares granted	7 years

Share-Based Payment Plans - Sto

Share-Based Payment Plans - Stock Options (Details) shares in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)shares
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Number of options (in shares) | shares	3.8
Weighted average remaining contractual life (in years)	4 years 2 months 12 days
Weighted average exercise price (in dollars per share)	$ 8.41
Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in dollars per share)	5
Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in dollars per share)	$ 30
5.00 - 9.00
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Number of options (in shares) | shares	3.3
Weighted average remaining contractual life (in years)	4 years 8 months 12 days
Weighted average exercise price (in dollars per share)	$ 6.34
5.00 - 9.00 | Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in dollars per share)	5
5.00 - 9.00 | Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in dollars per share)	$ 9
22.00 - 30.00
Disclosure of number and weighted average remaining contractual life of outstanding share options [line items]
Number of options (in shares) | shares	0.5
Weighted average remaining contractual life (in years)	1 month 6 days
Weighted average exercise price (in dollars per share)	$ 23.44
22.00 - 30.00 | Minimum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in dollars per share)	22
22.00 - 30.00 | Maximum
Disclosure of range of exercise prices of outstanding share options [line items]
Exercise price of outstanding share options (in dollars per share)	$ 30

Employee Future Benefits (Detai

Employee Future Benefits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)age	Dec. 31, 2019CAD ($)	Dec. 31, 2019CAD ($)year	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)
Disclosure of defined benefit plans [line items]
Administration expenses		$ 2			$ 1	$ 2
Weighted average duration of defined benefit obligation | year			15.6
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		2			1	2
Registered | Letter of credit
Disclosure of defined benefit plans [line items]
Letter of credit, posted	$ 83	83	$ 83	$ 83
Registered | Related parties [member]
Disclosure of defined benefit plans [line items]
Administration expenses		0			0.1
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, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	$ 10	$ 12	$ 10
Administration expenses	2	1	2
Defined benefit expense	19	22	21
Defined contribution expense	9	10	11
Net expense	28	32	32
Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	23	22	24
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	(13)	(13)	(15)
Curtailment and amendment gain	(3)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	7	9	7
Administration expenses	2	1	2
Defined benefit expense	13	15	14
Defined contribution expense	9	10	11
Net expense	22	25	25
Registered | Defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	7	9
Interest cost	19	18	20
Curtailment and amendment gain	(3)
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	(12)	(13)	(15)
Curtailment and amendment gain	(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	5	5
Defined contribution expense	0	0	0
Net expense	4	5	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
Supplemental Pension Plan | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	(1)	0	0
Curtailment and amendment gain	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
Other | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Interest cost	0	$ 0	$ 0
Curtailment and amendment gain	$ 0

Employee Future Benefits - Stat

Employee Future Benefits - Status of Plans (Details) - CAD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	$ (278)	$ (238)
Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(10)	(11)
Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(268)	(227)
Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	386	381	$ 428
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(664)	(619)
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(170)	(146)
Registered | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(3)	(5)
Registered | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(167)	(141)
Registered | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	373	368	416
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(543)	(514)	(561)
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(86)	(67)
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)	(81)	(62)
Supplemental Pension Plan | Fair value of plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	13	13	12
Supplemental Pension Plan | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(99)	(80)	(87)
Other
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(22)	(25)
Other | Accrued current liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(2)	(1)
Other | Other long-term liabilities
Disclosure of net defined benefit liability (asset) [line items]
Net defined benefit liability (asset)	(20)	(24)
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)	$ (22)	$ (25)	$ (27)

Employee Future Benefits - Fair

Employee Future Benefits - Fair Value of Plan Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	$ (238)
Administration expenses	(2)	$ (1)	$ (2)
Net asset, ending of period	(278)	(238)
Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	381	428
Interest on plan assets	13	13	15
Net return on plan assets	40	(25)
Contributions	11	12
Benefits paid	(56)	(48)
Effect of translation on US plans	(1)	2
Net asset, ending of period	386	381	428
Registered
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(146)
Administration expenses	(2)	(1)	(2)
Net asset, ending of period	(170)	(146)
Registered | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	368	416
Interest on plan assets	12	13	15
Net return on plan assets	40	(25)
Contributions	6	5
Benefits paid	(50)	(42)
Effect of translation on US plans	(1)	2
Net asset, ending of period	373	368	416
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(67)
Administration expenses	0	0	0
Net asset, ending of period	(86)	(67)
Supplemental Pension Plan | Plan assets
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	13	12
Interest on plan assets	1	0	0
Net return on plan assets	0	0
Contributions	4	6
Benefits paid	(5)	(5)
Effect of translation on US plans	0	0
Net asset, ending of period	13	13	12
Other
Disclosure of net defined benefit liability (asset) [line items]
Net asset, beginning of period	(25)
Administration expenses	0	0	0
Net asset, ending of period	(22)	(25)
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, 2019	Dec. 31, 2018
Disclosure of fair value of plan assets [line items]
Money market and cash and cash equivalents	$ 19	$ 12
Total	386	381
Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	66	65
US
Disclosure of fair value of plan assets [line items]
Equity securities	28	26
International
Disclosure of fair value of plan assets [line items]
Equity securities	102	101
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	40	48
AA
Disclosure of fair value of plan assets [line items]
Bonds	68	64
A
Disclosure of fair value of plan assets [line items]
Bonds	37	39
BBB
Disclosure of fair value of plan assets [line items]
Bonds	22	22
Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	3	3
Level I
Disclosure of fair value of plan assets [line items]
Money market and cash and cash equivalents	0	(2)
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	14
Total	384	381
Level II | Canadian
Disclosure of fair value of plan assets [line items]
Equity securities	66	65
Level II | US
Disclosure of fair value of plan assets [line items]
Equity securities	28	26
Level II | International
Disclosure of fair value of plan assets [line items]
Equity securities	102	101
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	40	48
Level II | AA
Disclosure of fair value of plan assets [line items]
Bonds	68	64
Level II | A
Disclosure of fair value of plan assets [line items]
Bonds	37	39
Level II | BBB
Disclosure of fair value of plan assets [line items]
Bonds	21	21
Level II | Below BBB
Disclosure of fair value of plan assets [line items]
Bonds	3	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, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	$ 238
Current service cost	10	$ 12	$ 10
Actuarial gain arising from demographic assumptions	(26)	15
Defined benefit obligation, ending of period	278	238
Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	619
Interest cost	23	22	24
Defined benefit obligation, ending of period	664	619
Registered
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	146
Current service cost	7	9	7
Defined benefit obligation, ending of period	170	146
Registered | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	514	561
Current service cost	7	9
Interest cost	19	18	20
Benefits paid	(51)	(42)
Curtailment and amendment gain	(3)
Actuarial gain arising from demographic assumptions	0	0
Actuarial loss arising from financial assumptions	57	(35)
Actuarial gain (loss) arising from experience adjustments	2	0
Effect of translation on US plans	(2)	3
Defined benefit obligation, ending of period	543	514	561
Supplemental Pension Plan
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	67
Current service cost	2	2	2
Defined benefit obligation, ending of period	86	67
Supplemental Pension Plan | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	80	87
Current service cost	2	2
Interest cost	3	3	3
Benefits paid	(4)	(5)
Curtailment and amendment gain	0
Actuarial gain arising from demographic assumptions	0	0
Actuarial loss arising from financial assumptions	9	(7)
Actuarial gain (loss) arising from experience adjustments	9	0
Effect of translation on US plans	0	0
Defined benefit obligation, ending of period	99	80	87
Other
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	25
Current service cost	1	1	1
Defined benefit obligation, ending of period	22	25
Other | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	25	27
Current service cost	1	1
Interest cost	1	1	1
Benefits paid	(1)	(1)
Curtailment and amendment gain	0
Actuarial gain arising from demographic assumptions	2	0
Actuarial loss arising from financial assumptions	2	(2)
Actuarial gain (loss) arising from experience adjustments	(4)	(1)
Effect of translation on US plans	0	0
Defined benefit obligation, ending of period	22	25	27
Total | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Defined benefit obligation, beginning of period	619	675
Current service cost	10	12
Interest cost	23	22
Benefits paid	(56)	(48)
Curtailment and amendment gain	(3)
Actuarial gain arising from demographic assumptions	2	0
Actuarial loss arising from financial assumptions	68	(44)
Actuarial gain (loss) arising from experience adjustments	7	(1)
Effect of translation on US plans	(2)	3
Defined benefit obligation, ending of period	$ 664	$ 619	$ 675

Employee Future Benefits - Cont

Employee Future Benefits - Contributions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)
Registered
Disclosure of defined benefit plans [line items]
Expected employer contributions	$ 4
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	1
Total
Disclosure of defined benefit plans [line items]
Expected employer contributions	$ 10

Employee Future Benefits - Assu

Employee Future Benefits - Assumptions (Details)	12 Months Ended
	Dec. 31, 2019age	Dec. 31, 2019	Dec. 31, 2018
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 | UNITED STATES
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	300000.00%	300000.00%	390000.00%
Rate of compensation increase	280000.00%	280000.00%	250000.00%
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 | Supplemental Pension Plan
Disclosure of defined benefit plans [line items]
Discount rate	300000.00%	300000.00%	380000.00%
Rate of compensation increase	300000.00%	300000.00%	300000.00%
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	300000.00%	300000.00%	390000.00%
Rate of compensation increase	0.00%	0.00%	0.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	700000.00%	700000.00%	710.00%
Dental-care cost escalation	400000.00%	400000.00%	400000.00%
Other, through 2027 | Registered
Disclosure of defined benefit plans [line items]
Discount rate	390000.00%	390000.00%	330000.00%
Rate of compensation increase	250000.00%	250000.00%	260000.00%
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%
Provincial health-care premium escalation	0.00%	0.00%	0.00%
Other, through 2027 | Supplemental Pension Plan
Disclosure of defined benefit plans [line items]
Discount rate	380000.00%	380000.00%	330000.00%
Rate of compensation increase	300000.00%	300000.00%	300000.00%
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%
Provincial health-care premium escalation	0.00%	0.00%	0.00%
Other, through 2027 | Other, through 2027
Disclosure of defined benefit plans [line items]
Discount rate	390000.00%	390000.00%	340000.00%
Rate of compensation increase	0.00%	0.00%	0.00%
Assumed health-care cost trend rate
Health-care cost escalation(1)(3)	740000.00%	740000.00%	760.00%
Dental-care cost escalation	400000.00%	400000.00%	400000.00%
Provincial health-care premium escalation	0.00%	0.00%	0.00%

Employee Future Benefits - Sens

Employee Future Benefits - Sensitivity Analysis (Details) $ in Thousands	Dec. 31, 2019CAD ($)
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%
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%
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%
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%
Registered Pension Plan | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	$ 84,000
Registered Pension Plan | Canada | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	14,000
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	22,000
Registered Pension Plan | UNITED STATES | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	3,000
Registered Pension Plan | UNITED STATES | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Registered Pension Plan | UNITED STATES | 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 | UNITED STATES | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1,000
Supplemental Pension Plan | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	15,000
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	3,000
Other | Canada | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	2,000
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	2,000
Other | Canada | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Other | UNITED STATES | 1% decrease in the discount rate
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	1,000
Other | UNITED STATES | 1% increase in the salary scale
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	0
Other | UNITED STATES | 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 | UNITED STATES | 10% improvement in mortality rates
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase in defined benefit obligation	$ 0

Cash Flow Information (Details)

Cash Flow Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from (used in) operating activities [abstract]
Accounts receivable	$ 261	$ 58	$ (228)
Prepaid expenses	0	19	(75)
Income taxes receivable	(6)	0	8
Inventory	(13)	(21)	(7)
Accounts payable, accrued liabilities and provisions	(130)	(97)	186
Income taxes payable	9	(3)	2
Increase (decrease) in working capital	$ 121	$ (44)	$ (114)

Cash Flow Information Changes i

Cash Flow Information Changes in Liabilities from Financing Activities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	$ 3,325	$ 3,741
Net cash flows	195	(626)
New leases	133	10
Tax shield on tax equity financing	(35)
Dividends declared	64	107
Foreign exchange impact	(42)	95
Other	(65)	(2)
Balance at end of the period	3,575	3,325
Long-term debt and lease obligations
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	3,267	3,707
Net cash flows	(70)	(540)
New leases	133	10
Tax shield on tax equity financing	(35)
Dividends declared	0	0
Foreign exchange impact	(42)	95
Other	(41)	(5)
Balance at end of the period	3,212	3,267
Exchangeable securities
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	0
Net cash flows	350
New leases	0
Tax shield on tax equity financing	0
Dividends declared	0
Foreign exchange impact	0
Other	(24)
Balance at end of the period	326	0
Dividends payable (common and preferred)
Disclosure of reconciliation of liabilities arising from financing activities [line items]
Balance at beginning of the period	58	34
Net cash flows	(85)	(86)
New leases	0	0
Tax shield on tax equity financing	0
Dividends declared	64	107
Foreign exchange impact	0	0
Other	0	3
Balance at end of the period	$ 37	$ 58

Capital Disclosure of component

Capital Disclosure of components of capital (Details) - CAD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jun. 28, 2018	Dec. 31, 2016
Disclosure of components of capital [Line Items]
Long-term debt		$ 3,212	$ 3,267
Increase (decrease) in financial liabilities		(55)
Exchangeable securities		326	0
Increase (decrease) in exchangeable securities		326
Equity		4,062	4,134	$ 4,385
Preferred shares					$ 33
Contributed surplus		42	11
Deficit		(1,455)	(1,496)
Accumulated other comprehensive income		454	481
Non-controlling interests		1,101	1,137
Cash and cash equivalents		(411)	(89)	(314)		$ (305)
Increase (decrease) in cash and cash equivalents		(322)	225	(9)
Current restricted cash and cash equivalents		(32)	(66)
Fair value asset of hedging instruments on long-term debt		(7)	(10)
Increase (decrease) in hedging instruments, liabilities		3
Total capital		7,172	7,275
Increase (decrease) in capital		(103)
Common shares
Disclosure of components of capital [Line Items]
Equity		2,978	3,059
Increase (decrease) in equity		(81)
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		42	11	10
Increase (decrease) in equity		31
Deficit
Disclosure of components of capital [Line Items]
Equity		(1,455)	(1,496)	(1,209)
Increase (decrease) in equity		41
Accumulated other comprehensive income
Disclosure of components of capital [Line Items]
Equity	[1]	454	481	489
Increase (decrease) in equity		(27)
Non-controlling interests
Disclosure of components of capital [Line Items]
Equity		1,101	1,137	$ 1,059
Increase (decrease) in equity		(36)
TransAlta OCP
Disclosure of components of capital [Line Items]
Current restricted cash and cash equivalents		(10)	$ (27)
Increase (decrease) in restricted cash and cash equivalents		$ 17
[1]	(1) Refer to Note 28 for details on components of, and changes in, accumulated other comprehensive income (loss).

Capital Disclosure of cash flow

Capital Disclosure of cash flow statement (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of classes of share capital [line items]
Cash flows from (used in) operating activities	$ 849	$ 820	$ 626
Increase (decrease) in cash flow from (used in) operating activities	29
Change in non-cash operating working capital balances	(121)	44	114
Increase (decrease) in non cash working capital	(165)
Cash flow from operations before changes in working capital	728	864	740
Increase (decrease) in cash flow from operations before changes in working capital	(136)
Distributions paid to subsidiaries’ non-controlling interests	106	165	172
Increase (decrease) in dividends paid to non controlling interests	59
Property, plant and equipment expenditures	417	277	338
Increase (decrease) in property, plant and equipment expenditure	(140)
Net inflows (outflows) of cash	120	336
Increase (decrease) in net inflows (outflows) of cash	(216)
Common shares
Disclosure of classes of share capital [line items]
Dividends paid	45	46	46
Increase (decrease) in dividends paid	1
Preferred shares
Disclosure of classes of share capital [line items]
Dividends paid	40	$ 40	$ 40
Increase (decrease) in dividends paid	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Commitments (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2019USD ($)	Jan. 01, 2019CAD ($)	Dec. 17, 2018	Jul. 30, 2015USD ($)
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	$ 217
Long-term service agreements	150
Non-cancellable operating leases	77	$ 80			$ 83
Growth	1,268
TransAlta Energy Transition Bill	24						$ 55
Total	3,879
Sublease payments received (amounts less than)		$ 1	$ 1
Funded portion of Energy Bill commitment				$ 37
Litigation settlement, amount awarded from other party	27
Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	2,122
Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	21
2020
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	147
Long-term service agreements	50
Non-cancellable operating leases	4
Growth	535
TransAlta Energy Transition Bill	6
Total	876
2020 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	125
2020 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	9
2021
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	16
Long-term service agreements	22
Non-cancellable operating leases	2
Growth	254
TransAlta Energy Transition Bill	6
Total	430
2021 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	125
2021 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	5
2022
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	16
Long-term service agreements	32
Non-cancellable operating leases	2
Growth	196
TransAlta Energy Transition Bill	6
Total	376
2022 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	120
2022 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	4
2023
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	16
Long-term service agreements	17
Non-cancellable operating leases	2
Growth	270
TransAlta Energy Transition Bill	6
Total	442
2023 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	128
2023 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	3
2024
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	8
Long-term service agreements	15
Non-cancellable operating leases	3
Growth	13
TransAlta Energy Transition Bill	0
Total	170
2024 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	131
2024 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	0
2025
Disclosure of Commitments [Line Items]
Coal supply and mining agreements	14
Long-term service agreements	14
Non-cancellable operating leases	64
Growth	0
TransAlta Energy Transition Bill	0
Total	1,585
2025 | Natural gas, transportation and other contracts
Disclosure of Commitments [Line Items]
Purchase obligations	1,493
2025 | Transmission
Disclosure of Commitments [Line Items]
Purchase obligations	0
Line loss rule proceeding
Disclosure of Commitments [Line Items]
Estimated financial effect of contingent liabilities	$ 12
Tidewater Brazeau River Pipeline | Tidewater
Disclosure of Commitments [Line Items]
Future option to acquire pipeline, ownership percentage						50.00%

Segment Disclosures Disclosure

Segment Disclosures Disclosure of operating segments (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure of operating segments [line items]
Revenues	$ 2,347	$ 2,249	$ 2,307
Fuel and purchased power (Note 6)	1,086	1,100	1,016
Gross margin	1,261	1,149	1,291
Depreciation and amortization	590	574	635
Asset impairment charges (reversals) (Note 7)	25	73	20
Gains on termination of investments	56	157	0
Taxes, other than income taxes	29	31	30
Finance lease income	6	8	54
Gain on sale of assets and other (Note 4(D) and 17)	46	1	2
Net interest expense (Note 10)	(179)	(250)	(247)
Foreign exchange loss	(15)	(15)	(1)
Earnings (loss) before income taxes	193	(96)	(54)
Goodwill	464	464
Property, plant and equipment	6,207	6,164	6,578
Right-of-use assets	146	0
Intangible assets	318	373	364
Other assets	198	234
Property, plant and equipment expenditures	417	277	338
Purchase of intangible assets	14	20	51
Mine depreciation	119	136	73
Adjustments for depreciation and amortisation expense	709	710	708
Canada
Disclosure of operating segments [line items]
Revenues	1,460	1,573	1,663
Goodwill	418	417
Property, plant and equipment	4,854	4,953
Right-of-use assets	109	0
Intangible assets	213	273
Other assets	75	101
US
Disclosure of operating segments [line items]
Revenues	727	511	509
Goodwill	46	47
Property, plant and equipment	863	657
Right-of-use assets	33	0
Intangible assets	68	59
Other assets	47	50
Australia
Disclosure of operating segments [line items]
Revenues	160	165	135
Goodwill	0	0
Property, plant and equipment	490	554
Right-of-use assets	4	0
Intangible assets	37	41
Other assets	76	83
Reportable segments [member]
Disclosure of operating segments [line items]
Revenues	2,347	2,249	2,307
Fuel and purchased power (Note 6)	1,086	1,100	1,016
Gross margin	1,261	1,149	1,291
Operations, maintenance, and administration (Note 5)	475	515	517
Depreciation and amortization	590	574	635
Asset impairment charges (reversals) (Note 7)	25	73	20
Gains (losses) on disposals of investments	(88)
Gains on termination of investments	56	157
Taxes, other than income taxes	29	31	30
Profit (loss) from operating activities	(49)	(47)	(49)
Operating income	335	160	138
Finance lease income	6	8	54
Gain on sale of assets and other (Note 4(D) and 17)	46	1	2
Net interest expense (Note 10)	(179)	(250)	(247)
Foreign exchange loss	(15)	(15)	(1)
Earnings (loss) before income taxes	193	(96)	(54)
Goodwill	464	464
Property, plant and equipment	6,207	6,164
Right-of-use assets	146
Intangible assets	318	373
Property, plant and equipment expenditures	417	277	338
Purchase of intangible assets	14	20	51
Reportable segments [member] | Canadian Coal
Disclosure of operating segments [line items]
Revenues	816	912	999
Fuel and purchased power (Note 6)	570	666	585
Gross margin	246	246	414
Operations, maintenance, and administration (Note 5)	138	171	192
Depreciation and amortization	233	241	317
Asset impairment charges (reversals) (Note 7)	15	38	20
Gains (losses) on disposals of investments	(88)
Gains on termination of investments	56	157
Taxes, other than income taxes	13	13	13
Profit (loss) from operating activities	(40)	(41)	(40)
Operating income	31	(19)	(88)
Finance lease income	0	0	0
Goodwill	0	0
Property, plant and equipment	2,540	2,587
Right-of-use assets	68
Intangible assets	41	81
Property, plant and equipment expenditures	114	101	116
Purchase of intangible assets	2	3	5
Reportable segments [member] | United States Coal
Disclosure of operating segments [line items]
Revenues	571	442	435
Fuel and purchased power (Note 6)	416	314	293
Gross margin	155	128	142
Operations, maintenance, and administration (Note 5)	67	61	51
Depreciation and amortization	83	74	73
Asset impairment charges (reversals) (Note 7)	(10)	0	0
Gains (losses) on disposals of investments	0
Gains on termination of investments	0	0
Taxes, other than income taxes	3	5	4
Profit (loss) from operating activities	0	0	0
Operating income	12	(12)	14
Finance lease income	0	0	0
Goodwill	0	0
Property, plant and equipment	352	332
Right-of-use assets	0
Intangible assets	6	7
Property, plant and equipment expenditures	8	14	35
Purchase of intangible assets	0	0	1
Reportable segments [member] | Canadian Gas
Disclosure of operating segments [line items]
Revenues	209	232	261
Fuel and purchased power (Note 6)	74	96	101
Gross margin	135	136	160
Operations, maintenance, and administration (Note 5)	44	48	50
Depreciation and amortization	41	43	38
Asset impairment charges (reversals) (Note 7)	0	0	0
Gains (losses) on disposals of investments	0
Gains on termination of investments	0	0
Taxes, other than income taxes	1	1	1
Profit (loss) from operating activities	(1)	0	(9)
Operating income	50	44	80
Finance lease income	6	8	11
Goodwill	0	0
Property, plant and equipment	392	391
Right-of-use assets	0
Intangible assets	2	4
Property, plant and equipment expenditures	36	21	31
Purchase of intangible assets	0	0	0
Reportable segments [member] | Australian Gas
Disclosure of operating segments [line items]
Revenues	160	165	135
Fuel and purchased power (Note 6)	9	8	14
Gross margin	151	157	121
Operations, maintenance, and administration (Note 5)	37	37	31
Depreciation and amortization	48	49	37
Asset impairment charges (reversals) (Note 7)	0	0	0
Gains (losses) on disposals of investments	0
Gains on termination of investments	0	0
Taxes, other than income taxes	0	0	0
Profit (loss) from operating activities	0	0	0
Operating income	66	71	53
Finance lease income	0	0	43
Goodwill	0	0
Property, plant and equipment	489	554
Right-of-use assets	4
Intangible assets	37	41
Property, plant and equipment expenditures	6	6	114
Purchase of intangible assets	0	0	29
Reportable segments [member] | Wind and Solar
Disclosure of operating segments [line items]
Revenues	312	282	287
Fuel and purchased power (Note 6)	16	17	17
Gross margin	296	265	270
Operations, maintenance, and administration (Note 5)	50	50	48
Depreciation and amortization	124	110	111
Asset impairment charges (reversals) (Note 7)	0	12	0
Gains (losses) on disposals of investments	0
Gains on termination of investments	0	0
Taxes, other than income taxes	8	8	8
Profit (loss) from operating activities	(10)	(6)	0
Operating income	124	91	103
Finance lease income	0	0	0
Goodwill	176	175
Property, plant and equipment	1,947	1,799
Right-of-use assets	56
Intangible assets	173	173
Property, plant and equipment expenditures	229	117	20
Purchase of intangible assets	0	0	0
Reportable segments [member] | Hydro
Disclosure of operating segments [line items]
Revenues	156	156	121
Fuel and purchased power (Note 6)	7	6	6
Gross margin	149	150	115
Operations, maintenance, and administration (Note 5)	36	38	37
Depreciation and amortization	32	30	31
Asset impairment charges (reversals) (Note 7)	2	0	0
Gains (losses) on disposals of investments	0
Gains on termination of investments	0	0
Taxes, other than income taxes	3	3	3
Profit (loss) from operating activities	0	0	0
Operating income	76	79	44
Finance lease income	0	0	0
Goodwill	258	259
Property, plant and equipment	469	481
Right-of-use assets	6
Intangible assets	5	4
Property, plant and equipment expenditures	23	16	16
Purchase of intangible assets	0	0	0
Reportable segments [member] | Energy Marketing
Disclosure of operating segments [line items]
Revenues	129	67	69
Fuel and purchased power (Note 6)	0	0	0
Gross margin	129	67	69
Operations, maintenance, and administration (Note 5)	30	24	24
Depreciation and amortization	2	2	2
Asset impairment charges (reversals) (Note 7)	0	0	0
Gains (losses) on disposals of investments	0
Gains on termination of investments	0	0
Taxes, other than income taxes	0	0	0
Profit (loss) from operating activities	0	0	0
Operating income	97	41	43
Finance lease income	0	0	0
Goodwill	30	30
Property, plant and equipment	1	1
Right-of-use assets	0
Intangible assets	9	11
Property, plant and equipment expenditures	0	0	0
Purchase of intangible assets	0	0	0
Reportable segments [member] | Corporate
Disclosure of operating segments [line items]
Revenues	(6)	(7)	0
Fuel and purchased power (Note 6)	(6)	(7)	0
Gross margin	0	0	0
Operations, maintenance, and administration (Note 5)	73	86	84
Depreciation and amortization	27	25	26
Asset impairment charges (reversals) (Note 7)	18	23	0
Gains (losses) on disposals of investments	0
Gains on termination of investments	0	0
Taxes, other than income taxes	1	1	1
Profit (loss) from operating activities	2	0	0
Operating income	(121)	(135)	(111)
Finance lease income	0	0	0
Goodwill	0	0
Property, plant and equipment	17	19
Right-of-use assets	12
Intangible assets	45	52
Property, plant and equipment expenditures	1	2	6
Purchase of intangible assets	$ 12	$ 17	$ 16

Segment Disclosures Disclosur_2

Segment Disclosures Disclosure of entity's operating segments (Details) - segment	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
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%	1900.00%

Uncategorized Items - _IXDS

Label	Element	Value
UNITED STATES
Disclosure of employee benefits [text block]	ifrs-full_DisclosureOfEmployeeBenefitsExplanatory	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, 2019. The latest actuarial valuation for accounting purposes of the Highvale and Canadian pension plans was at Dec. 31, 2016. 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, 2019. 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 2019 for the amount of $83 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, 2016, and Jan. 1, 2018, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2019. 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, 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 Year ended Dec. 31, 2017 Registered Supplemental Other Total Current service cost 7 2 1 10 Administration expenses 2 — — 2 Interest cost on defined benefit obligation 20 3 1 24 Interest on plan assets (15) — — (15) Defined benefit expense 14 5 2 21 Defined contribution expense 11 — — 11 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: As at 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) As at Dec. 31, 2018 Registered Supplemental Other Total Fair value of plan assets 368 13 — 381 Present value of defined benefit obligation (514) (80) (25) (619) Funded status – plan deficit (146) (67) (25) (238) Amount recognized in the consolidated financial statements: Accrued current liabilities (5) (5) (1) (11) Other long-term liabilities (141) (62) (24) (227) Total amount recognized (146) (67) (25) (238) 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, 2017 416 12 — 428 Interest on plan assets 13 — — 13 Net return on plan assets (25) — — (25) Contributions 5 6 1 12 Benefits paid (42) (5) (1) (48) Administration expenses (1) — — (1) Effect of translation on US plans 2 — — 2 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 The fair value of the Corporation’s defined benefit plan assets by major category is as follows: 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 Year ended Dec. 31, 2018 Level I Level II Level III Total Equity securities Canadian — 65 — 65 US — 26 — 26 International — 101 — 101 Private — — 1 1 Bonds AAA — 48 — 48 AA — 64 — 64 A — 39 — 39 BBB 1 21 — 22 Below BBB — 3 — 3 Money market and cash and cash equivalents (2) 14 — 12 Total (1) 381 1 381 Plan assets do not include any common shares of the Corporation at Dec. 31, 2019, and Dec. 31, 2018. The Corporation charged the registered plan nil for administrative services provided for the year ended Dec. 31, 2019 (2018 - $0.1 million). 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, 2017 561 87 27 675 Current service cost 9 2 1 12 Interest cost 18 3 1 22 Benefits paid (42) (5) (1) (48) Actuarial gain arising from demographic assumptions — — — — Actuarial loss arising from financial assumptions (35) (7) (2) (44) Actuarial gain (loss) arising from experience adjustments — — (1) (1) Effect of translation on US plans 3 — — 3 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 loss arising from demographic assumptions — — (2) (2) Actuarial (gain) 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 The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2019, is 15.6 years. F. Contributions The expected employer contributions for 2020 for the defined benefit pension and other post-employment benefit plans are as follows: Registered Supplemental Other Total Expected employer contributions 4 5 1 10 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, 2019 As at Dec. 31, 2018 (per cent) Registered Supplemental Other Registered Supplemental Other Accrued benefit obligation Discount rate 3.0 3.0 3.0 3.9 3.8 3.9 Rate of compensation increase 2.8 3.0 — 2.5 3.0 — Assumed health-care cost trend rate Health-care cost escalation (1)(3) — — 7.0 — — 7.1 Dental-care cost escalation — — 4.0 — — 4.0 Benefit cost for the year Discount rate 3.9 3.8 3.9 3.3 3.3 3.4 Rate of compensation increase 2.5 3.0 — 2.6 3.0 — Assumed health-care cost trend rate Health-care cost escalation (2)(4) — — 7.4 — — 7.6 Dental-care cost escalation — — 4.0 — — 4.0 Provincial health-care premium escalation — — — — — — (1) 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. (2) 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 0.30% per year to 4.5% in 2027 for Canada. (3) 2018 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 0.30% per year to 4.5% in 2027 for Canada. (4) 2018 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 0.30% 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, 2019 Registered Supplemental Other Pension Other 1% decrease in the discount rate 84 15 2 3 1 1% increase in the salary scale 14 — — — — 1% increase in the health-care cost trend rate — — 2 — — 10% improvement in mortality rates 22 3 — 1 —
Disclosure of defined benefit plans [text block]	ifrs-full_DisclosureOfDefinedBenefitPlansExplanatory	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, 2019 As at Dec. 31, 2018 (per cent) Registered Supplemental Other Registered Supplemental Other Accrued benefit obligation Discount rate 3.0 3.0 3.0 3.9 3.8 3.9 Rate of compensation increase 2.8 3.0 — 2.5 3.0 — Assumed health-care cost trend rate Health-care cost escalation (1)(3) — — 7.0 — — 7.1 Dental-care cost escalation — — 4.0 — — 4.0 Benefit cost for the year Discount rate 3.9 3.8 3.9 3.3 3.3 3.4 Rate of compensation increase 2.5 3.0 — 2.6 3.0 — Assumed health-care cost trend rate Health-care cost escalation (2)(4) — — 7.4 — — 7.6 Dental-care cost escalation — — 4.0 — — 4.0 Provincial health-care premium escalation — — — — — — (1) 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. (2) 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 0.30% per year to 4.5% in 2027 for Canada. (3) 2018 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 0.30% per year to 4.5% in 2027 for Canada. (4) 2018 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 0.30% per year to 4.5% in 2027 for Canada.