On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

During the three months ended March 31, 2020, the Company tested its upstream CGUs and CGUs with associated goodwill for impairment. As a result, the Company recorded an impairment loss of $315 million as additional DD&A in the Conventional segment due to the decline in forward crude oil and natural gas prices. As at March 31, 2020, there was no impairment of goodwill or Oil Sands CGUs.

As at December 31, 2020, indicators of impairment were noted for the Company’s Conventional assets due to a change in future development plans since the Company last tested for impairment as at March 31, 2020. Therefore, the Company tested its Conventional CGUs for impairment and determined that the carrying amount was greater than the recoverable amount for certain CGUs and recorded an additional impairment loss of $240 million as DD&A.

For the purpose of impairment testing, goodwill is allocated to the CGU of which it relates. There was no impairment of goodwill as at December 31, 2020.

The following table summarizes the year ended December 31, 2020 impairment losses and estimated recoverable amounts as at December 31, 2020 by CGU:

CGU	Impairment Amount		Recoverable Amount
Clearwater		260		160
Elmworth-Wapiti		120		259
Kaybob-Edson		175		384

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the determination of future cash flows from reserves include crude oil, NGLs and natural gas prices, costs to develop and the discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates at December 31, 2020. All reserves have been evaluated as at December 31, 2020 by the Company’s IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2021		2022		2023		2024		2025		Average Annual Increase Thereafter
WTI (US$/barrel) ⁽¹⁾		47.17		50.17		53.17		54.97		56.07		2.0	%
WCS (C$/barrel) ⁽²⁾		44.63		48.18		52.10		54.10		55.19		2.0	%
Edmonton C5+ (C$/barrel)		59.24		63.19		67.34		69.77		71.18		2.0	%
AECO (C$/Mcf) ⁽³⁾		2.88		2.80		2.71		2.75		2.80		2.0	%

(1)	West Texas Intermediate (“WTI”).

(2)	Western Canadian Select (“WCS”).

(3)	Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British thermal units per thousand cubic feet (“Mcf”).

Discount and Inflation Rates

Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation was estimated at approximately two percent.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount in the impairment testing completed as at December 31, 2020 for the following CGUs:

	Increase (Decrease) to Recoverable Amount
	One Percent Increase in the Discount Rate			One Percent Decrease in the Discount Rate		Five Percent Increase in the Forward Price Estimates		Five Percent Decrease in the Forward Price Estimates
Clearwater		(5	)		6		52		(97	)
Elmworth-Wapiti		(7	)		8		54		(96	)
Kaybob-Edson		(13	)		14		54		(106	)

2020 Refining Impairments

As at September 30, 2020, the recovery in demand for refined products from the impact of COVID-19 lagged expectations resulting in higher than anticipated inventory levels. These factors, along with low market crack spreads and crude oil processing runs for North American refineries, were identified as potential indicators of impairment for the Wood River and Borger CGUs. As at September 30, 2020, the carrying amount of the Borger CGU was determined to be greater than the recoverable amount and an impairment charge of $450 million was recorded as additional DD&A in the Refining and Marketing segment. The recoverable amount of the Borger CGU was estimated at $692 million, using a discounted cash flow method in accordance with IFRS. As at September 30, 2020, no impairment of the Wood River CGU was identified. As at December 31, 2020, there were no further indicators of impairment noted since the Company last tested as at September 30, 2020.

Key Assumptions

The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included forward crude oil prices, forward crack spreads, future capital expenditures, operating costs, terminal values and the discount rate. Forward crack spreads were based on quoted near-month contracts for WTI and spot prices for gasoline and diesel.

Crude Oil and Forward Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020, the forward prices used to determine future cash flows were:

•

WTI forward prices used for 2021 to 2022 ranged from US$36.36 per barrel to US$50.84 per barrel and 2023 to 2025 ranged from US$49.66 per barrel to US$58.74 per barrel.

•

WTI to West Texas Sour differential used for 2021 to 2022 ranged from US$0.37 per barrel to US$1.73 per barrel and 2023 to 2025 ranged from US$1.21 per barrel to US$1.81 per barrel.

•

Group 3 forward market crack spread used for 2021 to 2022 ranged from US$11.56 per barrel to US$13.23 per barrel and 2023 to 2025 ranged from US$11.79 per barrel to US$16.58 per barrel.

•

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035.

Discount Rates

Discounted future cash flows were determined by applying a discount rate of 10 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

Increase (Decrease) to Recoverable Amount

One Percent Increase in

the Discount Rate

One Percent Decrease in the Discount Rate

Five Percent Increase in

the Forward Price

Estimates

Five Percent Decrease in the Forward Price Estimates

Borger

(71

)

263

(264

)

2020 ROU Asset Impairments

As at March 31, 2020, the temporary suspension of the Company’s crude-by-rail program was considered to be an indicator of impairment for the railcar CGU. As a result, the CGU was tested for impairment and an impairment expense of $3 million was recorded as additional DD&A in the Refining and Marketing segment.

2019 Upstream Impairments

As at December 31, 2019, the Company tested its Conventional CGUs for impairment as there were indicators of impairment due to a decline in forward natural gas prices. As at December 31, 2019, there were no impairments of goodwill or the Company’s CGUs.

2018 Net Upstream Impairments

As at December 31, 2018, the Company tested its upstream CGUs for impairment. As at December 31, 2018, there was no impairment of goodwill or the Company’s CGUs. However, the impairment test provided evidence that previously recognized impairment losses should be reversed.

As at December 31, 2018, the recoverable amount of the Clearwater CGU was estimated to be $761 million. Earlier in 2018 and 2017, impairment losses of $100 million and $56 million, respectively, were recorded due to a decline in forward prices. The impairment was recorded as additional DD&A in the Conventional segment (formerly Deep Basin). In the fourth quarter of 2018, the Company reversed $132 million of impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The reversal was due to improved recovery, extensions and well performance and changes to the development plan.

B) Asset Impairments and Write-downs

Exploration and Evaluation Assets

For the year ended December 31, 2020, $9 million and $82 million of previously capitalized E&E costs were written off in the Oil Sands segment and Conventional segment, respectively, as the carrying value was not considered to be recoverable and recorded as exploration expense.

In 2019, $18 million and $64 million of previously capitalized E&E costs were written off in the Oil Sands segment and Conventional segment, respectively, as the carrying value was not considered to be recoverable and recorded as exploration expense.

In 2018, Management completed a comprehensive review of the Conventional development plan, formerly known as Deep Basin, considering factors such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital spending on the assets going forward. As such, previously capitalized E&E costs of $2.1 billion were written off as exploration expense in the Elmworth, Wapiti, Kaybob, Edson and Clearwater areas within the Conventional segment.

Property, Plant and Equipment, Net

For the year ended December 31, 2020, $48 million and $4 million of previously capitalized PP&E costs were written off in the Oil Sands segment and Conventional segment, respectively, as the carrying value was not considered to be recoverable. In addition, $52 million of previously capitalized PP&E costs relating to information technology assets were written off due to synergies identified as a result of the Arrangement. The impairment was recorded as additional DD&A in the Corporate and Eliminations segment.