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Financial Instruments
 12 Months Ended
Dec. 31, 2021
Disclosure of detailed information about financial instruments [abstract]  
Financial Instruments Financial Instruments
A. Financial Assets and Liabilities – Classification and Measurement
 
Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost. The following table outlines the carrying amounts and classifications of the financial assets and liabilities:
Carrying value as at Dec. 31, 2021
 Derivatives
used for
hedging		Derivatives
held for
trading (FVTPL)		Amortized costTotal
Financial assets    
Cash and cash equivalents(1)
— — 947 947 
Restricted cash— — 70 70 
Trade and other receivables— — 651 651 
Long-term portion of finance lease receivable— — 185 185 
Risk management assets    
Current36 272 — 308 
Long-term252 147 — 399 
Financial liabilities    
Accounts payable and accrued liabilities— — 689 689 
Dividends payable— — 62 62 
Risk management liabilities    
Current— 261 — 261 
Long-term— 145 — 145 
Credit facilities, long-term debt and lease liabilities(2)
— — 3,267 3,267 
Exchangeable securities (Note 25)
— — 735 735 
(1) Includes cash equivalents of nil.
(2) Includes current portion.

Carrying value as at Dec. 31, 2020
 Derivatives
used for
hedging		Derivatives
held for
trading (FVTPL)		Amortized costTotal
Financial assets    
Cash and cash equivalents(1)
— — 703 703 
Restricted cash— — 71 71 
Trade and other receivables— — 583 583 
Long-term portion of finance lease receivables— — 228 228 
Risk management assets
Current102 69 — 171 
Long-term471 50 — 521 
Other assets (Note 22)
— — 52 52 
Financial liabilities
Accounts payable and accrued liabilities— — 599 599 
Dividends payable— — 59 59 
Risk management liabilities
Current10 84 — 94 
Long-term— 68 — 68 
Credit facilities, long-term debt and lease liabilities(2)
— — 3,361 3,361 
Exchangeable securities (Note 25)
— — 730 730 

(1) Includes cash equivalents of nil.
(2) Includes current portion.
B. Fair Value of Financial Instruments
 
The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by reference to prices for that instrument in active markets to which the Company has access. In the absence of an active market, the Company determines fair values based on valuation models or by reference to other similar products in active markets.
Fair values determined using valuation models require the use of assumptions. In determining those assumptions, the Company looks primarily to external readily observable market inputs. However, if not available, the Company uses inputs that are not based on observable market data.  
I. Level I, II and III Fair Value Measurements
 
The Level I, II and III classifications in the fair value hierarchy utilized by the Company are defined below. The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the lowest level input that is significant to the derivation of the fair value.
a. Level I
 
Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date. In determining Level I fair values, the Company uses quoted prices for identically traded commodities obtained from active exchanges such as the New York Mercantile Exchange.
b. Level II
Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.

Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation and location differentials. 
The Company’s commodity risk management Level II financial instruments include over-the-counter derivatives with values based on observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and interpolation formulas, where the inputs are readily observable.
In determining Level II fair values of other risk management assets and liabilities, the Company uses observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, the Company relies on similar interest or currency rate inputs and other third-party information such as credit spreads.
c. Level III
 
Fair values are determined using inputs for the assets or liabilities that are not readily observable. 
The Company may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair values are determined using valuation techniques such as mark-to-forecast and mark-to-model. For mark-to-model valuations, derivative pricing models, regression-based models and historical bootstrap models may be employed. The model inputs may be based on historical data such as unit availability, transmission congestion, demand profiles for individual non-standard deals and structured products, and/or volatility and correlations between products derived from historical price relationships.

The Company also has various commodity contracts with terms that extend beyond a liquid trading period. As forward market prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these contracts are classified in Level III.
II. Commodity Risk Management Assets and Liabilities
 Commodity risk management assets and liabilities include risk management assets and liabilities that are used in the energy marketing and generation businesses in relation to trading activities and certain contracting activities. To the extent applicable, changes in net risk management assets and liabilities for non-hedge positions are reflected within earnings of these businesses.

Commodity risk management assets and liabilities classified by fair value levels as at Dec. 31, 2021, are as follows: Level I — $12 million net asset (Dec. 31, 2020 — $13 million net liability), Level II — $122 million net asset (Dec. 31, 2020 — $27 million net liability) and Level III — $159 million net asset (Dec. 31, 2020 — $582 million net asset).

Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2021, are primarily attributable to volatility in market prices on both existing contracts and new contracts as well as contract settlements.

The following tables summarize the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification during the years ended Dec. 31, 2021 and 2020, respectively:
Year ended Dec. 31, 2021Year ended Dec. 31, 2020
HedgeNon-hedgeTotalHedgeNon-hedgeTotal
Opening balance573 9 582 678 8 686 
Changes attributable to:
Market price changes on existing contracts(181)4 (177)(18)3 (15)
Market price changes on new contracts— (134)(134)— 7 7 
Contracts settled(107)(5)(112)(71)(10)(81)
Change in foreign exchange rates— — — (16)1 (15)
Net risk management assets (liabilities) at end of period285 (126)159 573 9 582 
Additional Level III information:
Losses recognized in other comprehensive earnings(181)— (181)(34)— (34)
Total gains (losses) included in earnings before income
  taxes		107 (130)(23)71 11 82 
Unrealized gains (losses) included in earnings before
  income taxes relating to net assets held at period end		— (135)(135)— 1 1 
The Company has a Commodity Exposure Management Policy that governs both the commodity transactions undertaken in its proprietary trading business and those undertaken to manage commodity price exposures in its generation business. This Policy defines and specifies the controls and management responsibilities associated with commodity trading activities, as well as the nature and frequency of required reporting of such activities. 
The Company's risk management department determines methodologies and procedures regarding commodity risk management Level III fair value measurements. Level III fair values are primarily calculated within the Company’s energy trading risk management system. These calculations are based on underlying contractual data as well as observable and non-observable inputs. Development of non-observable inputs requires the use of judgment. To ensure reasonability, system-generated Level III fair value measurements are reviewed and validated by the risk management and finance departments. Review occurs formally on a quarterly basis or more frequently if daily review and monitoring procedures identify unexpected changes to fair value or changes to key parameters.
As at Dec. 31, 2021, the total Level III risk management asset balance was $305 million (2020 — $615 million) and Level III risk management liability balance was $146 million (2020 — $33 million). The information on risk management contracts or groups of risk management contracts that are included in Level III measurements and the related unobservable inputs and sensitivities. These include the effects on fair value of discounting, liquidity and credit value adjustments; however, the potential offsetting effects of Level II positions are not considered. Sensitivity ranges for the base fair values are determined using reasonably possible alternative assumptions for the key unobservable inputs, which may include forward commodity prices, volatility in commodity prices and correlations, delivery volumes, escalation rates and cost of supply. During 2021, the sensitivities include the effects of liquidity and credit value adjustments.
As atDec. 31, 2021
DescriptionSensitivityValuation techniqueUnobservable inputReasonable possible change
Long-term power
   sale – US
+22
Long-term price forecastIlliquid future power prices (per MWh)
Price decrease of US$3 or price increase of US$20
-145
Coal
  transportation –
  US
+3
Numerical derivative valuationIlliquid future power prices (per MWh)
Price decrease of US$3 or price increase of US$20
Volatility
80% to 120%
-18
Rail rate escalation
zero to 4%
Full requirements
   – Eastern US
+9
Historical bootstrapVolume
95% to 105%
-9
Cost of supply
(+/-) US$1 per MWh
Long-term wind
  energy sale –
  Eastern US
+17
Long-term price forecastIlliquid future power prices (per MWh)
Price increase or decrease of US$6
-16
Illiquid future REC prices (per unit)
Price decrease of US$3 or increase of US$2
Long-term wind
  energy sale –
  Canada		+21Long-term price forecastIlliquid future power prices (per MWh)
Price decrease of C$24 or increase of C$5
-11 Wind discounts
 5% decrease or 5% increase
Long-term wind
  energy sale -
  Central US		+27 Long-term price forecastIlliquid future power prices (per MWh)
Price decrease of US$2 or increase of US$3
-15 Wind discounts
3% decrease or 3% increase
Others
+6
-6
As atDec. 31, 2020
DescriptionSensitivityValuation techniqueUnobservable inputReasonable possible change
Long-term power
   sale – US
+35
Long-term price forecastIlliquid future power prices (per MWh)
Price decrease of US$3 or a price increase of US$5
-59
Coal
  transportation –
   US
+3
Numerical derivative valuationIlliquid future power prices (per MWh)
Price decrease of US$3 or a price increase of US$5
Volatility
80% to 120%
-5
Rail rate escalation
zero to 4%
Full
  requirements –
  Eastern US
+3
Historical bootstrapVolume
95% to 105%
-3
Cost of supply
(+/-) US$1 per MWh
Long-term wind
  energy sale –
  Eastern US
+22
Long-term price forecastIlliquid future power prices (per MWh)
Price increase or decrease of US$6
-22
Illiquid future REC prices (per unit)
Price increase or decrease of US$1
Others
+5
-5

i. Long-Term Power Sale – US
The Company has a long-term fixed price power sale contract in the US for delivery of power at the following capacity levels: 380 MW through Dec. 31, 2024, and 300 MW through Dec. 31, 2025. The contract is designated as an all-in-one cash flow hedge.
For periods beyond 2023, market forward power prices are not readily observable. For these periods, fundamental-based forecasts and market indications have been used to determine proxies for base, high and low power price scenarios. The base price forecast has been developed by using a fundamental-based forecast (the provider is an independent and widely accepted industry expert for scenario and planning views).
The contract is denominated in US dollars. The US dollar relative to the Canadian dollar remained consistent from Dec. 31, 2020, to Dec. 31, 2021, resulting in the sensitivity values remaining consistent. The balance for this contract at Dec. 31, 2021 decreased mainly due to higher forward power prices compared to previously estimated prices.
ii. Coal Transportation - US
The Company has a coal rail transport agreement that includes an upside sharing mechanism, with a contract start date of Jan. 1, 2021, that extends until Dec. 31, 2025. Option pricing techniques have been utilized to value the obligation associated with this component of the deal.

The key unobservable inputs used in the valuation include non-liquid power prices, option volatility and rail rate escalation. Reasonably possible alternative inputs were used to determine sensitivity on the fair value measurements.

For periods beyond 2023, market forward power prices are not readily observable. For these periods, fundamental-based forecasts and market indications have been used to determine proxies for base, high and low power price scenarios. The base price forecast has been developed by using a fundamental-based forecast (the provider is an independent and widely accepted industry expert for scenario and planning views). Option volatility and rail rate escalation ranges have been determined based on historical data and professional judgment.

iii. Full Requirements – Eastern US
The Company has a portfolio of full requirement service contracts, whereby the Company agrees to supply specific utility customer needs for a range of products that may include electrical energy, capacity, transmission, ancillary services, renewable energy credits ("RECs") and independent system operator costs.

The key unobservable inputs used in the portfolio valuation include delivered volume and supply cost. Hourly shaping of consumption will result in a realized cost that may be at a premium (or discount) relative to the average settled price. Reasonable possible alternative inputs are used to determine sensitivity on the fair value measurement.

iv. Long-Term Wind Energy Sale – Eastern US
In relation to the Big Level wind facility, the Company has a long-term contract for differences whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh as well as the physical delivery of renewable energy credits based on proxy generation. Commercial operation of the facility was achieved in December 2019, with the contract commencing on July 1, 2019, and extending for 15 years after the commercial operation date. The contract is accounted for at fair value through profit or loss.

The key unobservable inputs used in the valuation of the contract are expected proxy generation volumes and non-liquid forward prices for power and RECs. 
v. Long-Term Wind Energy Sale – Canada
In relation to the Garden Plain wind project, the Company has entered into a virtual PPA whereby the Company receives the difference between the fixed contract price per MWh and the Alberta Electric System Operator ("AESO") settled pool price per MWh. The contract commences on commercial operation of the facility, which is expected by the end of 2022, and extending for 18 years past that date. The energy component of the contract is accounted for at fair value through profit or loss.

In addition to the virtual PPA contract, the Company has entered into a "bridge contract" that runs 16 months from Sept. 1, 2021 through Dec. 31, 2022, with the potential for extension at the virtual PPA price, depending on the commencement of commercial operations.

Under a separate agreement, Pembina has the option to purchase a 37.7 per cent interest in the project (49 per cent of the PPA). The option must be exercised no later than 30 days after commercial operational date.

The key unobservable inputs used in the valuation of the contracts are the non-liquid forward prices for power and monthly wind discounts.

vi. Long-Term Wind Energy Sale – Central US
On Dec. 22, 2021, TransAlta executed two long-term virtual PPAs for the off take of 100 per cent of the generation from its 300 MW White Rock East and White Rock West wind power projects (collectively, the "White Rock Wind Projects") to be located in Caddo County, Oklahoma. The Company receives the difference between the fixed contract price per MWh and the settled pool price per MWh. The contracts commence on commercial operation of the facilities, which is expected within the second half of 2023, and extend for 15 years past that date. The energy component of the contracts is accounted for at fair value through profit or loss.

The key unobservable inputs used in the valuation of the contracts are the non-liquid forward prices for power and monthly wind discounts.
III. Other Risk Management Assets and Liabilities
 
Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in managing exposures on non-energy marketing transactions such as interest rates, the net investment in foreign operations and other foreign currency risks. Hedge accounting is not always applied.
Other risk management assets and liabilities with a total net asset fair value of $8 million as at Dec. 31, 2021 (Dec. 31, 2020 – $12 million net liability) are classified as Level II fair value measurements. The significant changes in other net risk management assets and liabilities during the year ended Dec. 31, 2021, are primarily attributable to favourable market prices on existing contracts.
IV. Other Financial Assets and Liabilities
 
The fair value of financial assets and liabilities measured at other than fair value is as follows:
 
Fair value(1)
Total
carrying value(1)
 Level ILevel IILevel IIITotal
Exchangeable securities — Dec. 31, 2021— 770 — 770 735 
Long-term debt — Dec. 31, 2021— 3,272 — 3,272 3,167 
Exchangeable securities — Dec. 31, 2020— 769 — 769 730 
Long-term debt — Dec. 31, 2020— 3,480 — 3,480 3,227 
(1) Includes current portion.
The fair values of the Company’s debentures, senior notes and exchangeable securities are determined using prices observed in secondary markets. Non-recourse and other long-term debt fair values are determined by calculating an implied price based on a current assessment of the yield to maturity. 
The carrying amount of other short-term financial assets and liabilities (cash and cash equivalents, restricted cash, trade accounts receivable, collateral paid, accounts payable and accrued liabilities, collateral received and dividends payable) approximates fair value due to the liquid nature of the asset or liability. The fair values of the loan receivable (see Note 22) and the finance lease receivables (see Note 8) approximate the carrying amounts.
C. Inception Gains and Losses
The majority of derivatives traded by the Company are based on adjusted quoted prices on an active exchange or extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives are determined using inputs that are not readily observable. Refer to section B of this Note 15 above for fair value Level III valuation techniques used. In some instances, a difference may arise between the fair value of a financial instrument at initial recognition (the “transaction price”) and the amount calculated through a valuation model. This unrealized gain or loss at inception is recognized in net earnings (loss) only if the fair value of the instrument is evidenced by a quoted market price in an active market, observable current market transactions that are substantially the same, or a valuation technique that uses observable market inputs. Where these criteria are not met, the difference is deferred on the Consolidated Statements of Financial Position in risk management assets or liabilities, and is recognized in net earnings (loss) over the term of the related contract. The difference between the transaction price and the fair value determined using a valuation model, yet to be recognized in net earnings, and a reconciliation of changes is as follows:
As at Dec. 31202120202019
Unamortized net gain (loss) at beginning of year(33)9 49 
New inception gain (loss)(1)
(50)(13)3 
Amortization recorded in net earnings during the year(19)(29)(43)
Unamortized net gain (loss) at end of year(2)
(102)(33)9 
(1) During 2021, the Company entered into PPAs for the White Rock Wind Projects that resulted in a new inception loss due to the difference between the fixed PPA price and future estimated market prices. There are other key factors, such as project economics and incentives, that influence the long-term power price for renewable projects outside of the power price curve, which is not liquid for the majority of the duration of the power agreement contract period. During 2020, the Company entered into a coal rail transportation agreement that includes an upside sharing mechanism. Option pricing techniques have been utilized to value the obligation associated with this component of the deal.
(2) During 2020, the net inception gain on the long-term fixed price power sale contract in the US changed to a loss position based on the day one forward price curve at inception of the contract.