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

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