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. For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates.

As at December 31, 2018, the book value of the Company’s net assets was greater than its market capitalization; therefore, 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 Deep Basin segment. 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.

There were no goodwill impairments for the twelve months ended December 31, 2018.

The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of comparable asset transactions. 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, prepared by Cenovus’s IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2018 by the IQREs.

The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2019		2020		2021		2022		2023		Average Annual Increase Thereafter
WTI (US$/barrel)		58.58		64.60		68.20		71.00		72.81		2.0	%
WCS (C$/barrel)		51.55		59.58		65.89		68.61		70.53		2.1	%
Edmonton C5+ (C$/barrel)		70.10		79.21		83.33		86.20		88.16		2.0	%
AECO (C$/Mcf) ⁽¹⁾		1.88		2.31		2.74		3.05		3.21		2.0	%

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

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 is estimated at two percent.

2017 Upstream Impairments

As at December 31, 2017, the Company tested its Clearwater CGU for impairment due to a decline in forward commodity prices. As a result, an impairment loss of $56 million on the Clearwater CGU was recorded. The impairment was recorded as additional DD&A in the Deep Basin segment. As at December 31, 2017, the recoverable amount of the Clearwater CGU was estimated to be approximately $295 million, which excludes the Clearwater assets reclassified to assets held for sale.

There were no goodwill impairments for the twelve months ended December 31, 2017.

Key Assumptions

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, prepared by Cenovus’s IQREs (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Forward prices as at December 31, 2017 used to determine future cash flows from crude oil and natural gas reserves were:

	2018		2019		2020		2021		2022		Average Annual Increase Thereafter
WTI (US$/barrel)		57.50		60.90		64.13		68.33		71.19		2.1	%
WCS (C$/barrel)		50.61		56.59		60.86		64.56		66.63		2.1	%
Edmonton C5+ (C$/barrel)		72.41		74.90		77.07		81.07		83.32		2.1	%
AECO (C$/Mcf)		2.43		2.77		3.19		3.48		3.67		2.0	%

2016 Net Upstream Impairments

As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion. Previously, impairment losses of $564 million were recorded primarily due to a decline in long-term heavy crude oil prices and a slowing of the development plan. In the fourth quarter of 2016, the Company reversed $400 million of impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The reversal arose due to the increase in the CGU’s estimated recoverable amount caused by an average reduction in expected future operating costs of five percent and lower future development costs, partially offset by a decline in estimated reserves. The impairment losses and subsequent reversal were recorded as DD&A in the Conventional segment, which has been classified as a discontinued operation. The Northern Alberta CGU included the Pelican Lake and Elk Point producing assets and other emerging assets in the exploration and evaluation stage.

As at December 31, 2016, the recoverable amount of the Suffield CGU was estimated to be $548 million. Earlier in 2016, an impairment loss of $65 million was recognized due to lower long-term forward natural gas and heavy crude oil prices. In the fourth quarter of 2016, the Company reversed the full amount of the impairment losses, net of the DD&A that would have been recorded had no impairment been recorded ($62 million). The reversal arose due to a decline in expected future royalties increasing the estimated recoverable amount of the CGU. The impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment. The Suffield CGU includes production of natural gas and heavy crude oil in Alberta on the Canadian Forces Base.

There were no goodwill impairments for the twelve months ended December 31, 2016.

B) Asset Impairments and Write-downs

Exploration and Evaluation Assets

In the fourth quarter of 2018, Management completed a comprehensive review of the Deep Basin development plan 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 Deep Basin segment.

For the year ended December 31, 2017, Management wrote off certain E&E assets, as their carrying values were not considered to be recoverable. As a result, $888 million of previously capitalized E&E costs were written off and recorded as exploration expense. These assets reside primarily in the Borealis CGU within the Oil Sands segment. Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on these assets in recent years and the current business plan spending on the assets going forward. At this point, Management is not committing further material funding beyond that required to retain ownership of this significant resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability of these projects.

In 2016, $2 million of previously capitalized E&E costs were written off and recorded as exploration expense in the Oil Sands segment.

Property, Plant and Equipment, Net

For the year ended December 31, 2018, the Company recorded an impairment loss of $6 million in the Oil Sands segment for information technology assets that were written down to their recoverable amounts.

In 2017, the Company recorded an impairment loss of $21 million related to equipment that was written down to its recoverable amount. The impairment loss relates to the Oil Sands segment.

In 2016, the Company recorded an impairment loss of $20 million primarily related to equipment that was written down to its recoverable amount. This impairment was recorded as additional DD&A in the Conventional segment, which has been classified as a discontinued operation. The Company also recorded an impairment loss of $16 million related to preliminary engineering costs associated with a project that was cancelled and equipment that was written down to its recoverable amount. This impairment loss was recorded as additional DD&A in the Oil Sands segment. Leasehold improvements of $4 million were also written off and recorded as additional DD&A in the Corporate and Eliminations segment.