CENOVUS ENERGY INC. (Form: 40-F, Received: 02/09/2021 16:19:22)

As of December 31, 2020, the Corporation’s remaining subsidiaries and partnerships each account for (i) less than 10 percent of the Corporation’s consolidated assets as at December 31, 2020 and (ii) less than 10 percent of the Corporation’s consolidated revenues for the year ended December 31, 2020. In aggregate, Cenovus’s subsidiaries and partnerships not listed above did not exceed 20 percent of the Corporation’s total consolidated assets or total consolidated revenues as at and for the year ended December 31, 2020.

On January 1, 2021, pursuant to a plan of arrangement under the Business Corporations Act (Alberta), Husky became a wholly-owned subsidiary of Cenovus (the “Husky Arrangement”) and will remain as such until completion of a planned amalgamation among the two entities. See “The Husky Arrangement” and “Description of the Business Following the Husky Arrangement” for further information.

A description of Husky’s significant subsidiaries and jointly-controlled entities is included in the Husky AIF, which is filed and available on SEDAR under Husky’s profile at sedar.com and on EDGAR at sec.gov.

As at December 31, 2020, Cenovus was an integrated energy company headquartered in Calgary, Alberta. Cenovus is in the business of developing, producing and marketing crude oil, natural gas and NGLs in Canada, and also conducts marketing activities and owns refining interests in the United States (“U.S.”).

As at December 31, 2020, all of Cenovus’s oil and natural gas reserves and production were located in Canada, within the provinces of Alberta and British Columbia. As at December 31, 2020, Cenovus had a land base of approximately 5.2 million net acres. The estimated proved plus probable reserves life index at December 31, 2020 was approximately 39 years.

As at December 31, 2020, the Corporation’s reportable segments were as follows:

Oil Sands

Cenovus’s Oil Sands segment includes the development and production of bitumen in northeast Alberta. Cenovus’s bitumen assets include Foster Creek and Christina Lake as well as Narrows Lake and other projects in the early stages of development.

Conventional

The Conventional segment includes approximately 3.6 million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and NGLs. The assets are located in Alberta and British Columbia and include interests in numerous natural gas processing facilities (collectively, the “Conventional Assets”).

Refining and Marketing

Cenovus’s Refining and Marketing segment includes transporting and selling crude oil, natural gas and NGLs and joint ownership of two refineries in the U.S. with the operator, Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a

crude-by-rail terminal in Alberta. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification.

Corporate and Eliminations

This segment primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative (“G&A”), financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Corporation’s rail terminal, crude oil production used as a feedstock by the Refining and Marketing segment and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices.

Three Year History

The following describes significant events and conditions that have influenced the development of Cenovus’s business during the last three financial years:

2018

•	Sale of Suffield assets. In the first quarter, Cenovus completed the sale of its Suffield crude oil and natural gas operations for cash proceeds of $512 million, before closing adjustments.

•	New Chief Financial Officer. In the second quarter, Jon McKenzie was appointed Cenovus’s Executive Vice-President & Chief Financial Officer.

•	Sale of Cenovus Pipestone Partnership. In the third quarter, Cenovus completed the sale of its general partnership that held the natural gas and liquids business in northwestern Alberta for cash proceeds of $625 million, before closing adjustments.

•	Debt reduction. In October, Cenovus redeemed US$800 million of its US$1.3 billion unsecured notes due October 2019. In December, Cenovus repurchased a principal amount of US$76 million of unsecured notes for US$69 million.

•	Sublease of excess office space. In the third quarter, Cenovus subleased an additional eight floors of The Bow tower in Calgary, Alberta, further reducing Cenovus’s long-term fixed real estate costs.

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Continued wide differentials. The differentials between West Texas Intermediate (“WTI”) and Western Canadian Select (“WCS”) averaged US$26.31 per barrel, a 120 percent increase compared with 2017, reaching a record of US$52.00 per barrel in the fourth quarter. Average WCS prices remained flat in 2018 in relation to 2017.

•	Government production curtailment. On December 2, 2018, the Government of Alberta announced a temporary mandatory oil production curtailment for Alberta producers, starting in January 2019, to, among other things, address the record-high differentials between WTI and WCS at Hardisty.

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Re-rated refinery processing capacity. As a result of consistently strong operating performance, higher utilization rates and optimizations executed in 2018, both U.S. refineries were re-rated to reflect higher processing capacity effective January 1, 2019. Crude capacity at the Wood River Refinery was re-rated to 333,000 barrels per day from 314,000 barrels per day, while capacity at the Borger Refinery was re-rated to 149,000 barrels per day from 146,000 barrels per day.

Cenovus Energy Inc.2020 Annual Information Form

2019

•	Debt reduction. In 2019, Cenovus repurchased a principal amount of US$1,276 million of unsecured notes for US$1,214 million. In October, Cenovus also repaid US$500 million in unsecured notes upon maturity.

•	Achieved first steam from Christina Lake phase G. In 2019, Cenovus began using steam from Christina Lake phase G to produce oil from other phases.

•	Ramped up crude-by-rail shipments. Using its fleet of railcars, Cenovus ramped up shipments of crude-by-rail over the course of 2019 to exit the year with December loaded volumes averaging 105,985 barrels per day and rail sales of 91,059 barrels per day.

•	Alberta government extended curtailment. In August, the Alberta government announced an extension of its mandatory oil production curtailment program to December 31, 2020.

•	Increased dividend by 25 percent. In October, Cenovus announced a 25 percent increase to its dividend for the fourth quarter of 2019.

•	Moved headquarters. In October, Cenovus completed the move of its headquarters in downtown Calgary, from The Bow tower to Brookfield Place.

•	Alberta government implemented Special Production Allowance program. Cenovus qualified for a Special Production Allowance to produce crude oil above curtailment for incremental increases in rail shipments.

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Re-rated Wood River Refinery processing capacity. As a result of consistently strong operating performance, higher utilization rates and optimization executed in 2019, the Wood River Refinery crude capacity was re-rated to 346,000 barrels per day from 333,000 barrels per day, to reflect higher processing capacity, effective January 1, 2020.

2020

•	Environmental, social and governance (ESG) targets. In the first quarter, Cenovus announced ESG targets in four key ESG focus areas: climate & greenhouse gas emissions, Indigenous engagement, land and wildlife and water stewardship.

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Response to the COVID-19 pandemic. In the first quarter, Cenovus took action to protect the health and safety of its staff and ensure the continuity of its business. Following the guidance of public health officials, the Corporation directed all staff who were able to do so to work from home, established mandatory self-isolation protocols and restricted travel policies as well as implemented active health screening, physical distancing and advanced cleaning and sanitation measures at its field operations.

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Reduction of capital spending and suspension of crude-by-rail program. On March 9, 2020, Cenovus announced a reduction to its 2020 capital program of approximately 32 percent in response to the significant decline in world benchmark crude oil prices. Cenovus also announced the temporary suspension of the crude-by-rail program and the deferral of final investment decisions on major growth projects.

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Further reduction of capital spending and suspension of the dividend. On April 2, 2020, Cenovus announced a further reduction to its 2020 capital program of $150 million, for a total year to date reduction in the 2020 capital program of 43 percent, along with additional cost-saving measures including the temporary suspension of its dividend.

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Temporary additional credit facility liquidity. In April, to further enhance its liquidity, the Corporation obtained commitments from several of its existing lenders for an additional $1.1 billion committed credit facility. On December 31, 2020, Cenovus cancelled the $1.1 billion committed credit facility prior to the closing of the Husky Arrangement.

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Used dynamic storage to shift production into stronger price environment. In the second quarter of 2020, Cenovus curtailed its oil sands production, storing mobilized oil in its reservoirs in response to the significant decline in crude oil prices. Production was ramped up by approximately 60,000 barrels per day in June and subsequent months in an improved price environment.

•	Senior note offering. On July 30, 2020, Cenovus completed a public offering in the U.S. of US$1,000,000,000 in 5.375% senior unsecured notes due 2025.

•	Agreement with Husky. On October 25, 2020 Cenovus and Husky announced the Husky Arrangement, an all-stock transaction valued at $23.6 billion, inclusive of debt, which would combine the two companies.

•	New leadership team. In the fourth quarter, Cenovus announced the new executive leadership team of the combined company. The new leadership team was appointed on January 1, 2021 following the closing of the Husky Arrangement.

•	Alberta government curtailment program put on hold. While the government’s regulatory authority to curtail oil production extends through 2021, starting in December 2020, Alberta’s government lifted monthly oil curtailment.

•	Marten Hills asset sale. On November 9, 2020, Cenovus announced the sale of its Marten Hills heavy oil assets to Headwater Exploration Inc. (“Headwater”) for a combination of cash, common share equity consideration and purchase warrants, while retaining a gross

Cenovus Energy Inc.2020 Annual Information Form

overriding royalty interest in the property. The sale closed December 2, 2020.

•	Cenovus amends articles to create series of First Preferred Shares. In connection with the Husky Arrangement, Cenovus’s articles were amended effective December 30, 2020, to create a series First Preferred Shares.

2021

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Cenovus acquires Husky. Effective January 1, 2021, Cenovus completed the Husky Arrangement and acquired all of the issued and outstanding Husky common shares and Husky preferred shares. As a result of completing the Husky Arrangement, Husky became a wholly-owned subsidiary of Cenovus. Pursuant to the Husky Arrangement, holders of Husky common shares received 0.7845 of a Cenovus common share (“Common Share”) and 0.0651 of a Cenovus warrant (“Cenovus Warrant”), in respect of each Husky common share held, resulting in the issuance of 788,517,905

Common Shares and 65,433,323 Cenovus Warrants, and holders of Husky preferred shares exchanged each Husky preferred share for one First Preferred Share with substantially identical terms. Each whole Cenovus Warrant entitles the holder to acquire one Common Share at an exercise price of $6.54 at any time up to January 1, 2026. In connection with the Husky Arrangement and pursuant to applicable securities laws, Cenovus will be filing a business acquisition report containing pro forma financial statements of the combined company as of December 31, 2020.

•	Reconstitution of the Board. Concurrently with the completion of the Husky Arrangement, Cenovus’s board of directors (the “Board”), and each committee of the Board, were reconstituted, with each of Canning K. N. Fok, Eva L. Kwok, Wayne E. Shaw and Frank J. Sixt being appointed to the Board.

Cenovus Energy Inc.2020 Annual Information Form

DESCRIPTION OF THE BUSINESS

PRIOR TO THE HUSKY ARRANGEMENT

OIL SANDS

Cenovus’s Oil Sands segment includes 100 percent ownership of the Foster Creek and Christina Lake assets, both of which are producing. In addition, the Corporation has several emerging projects in the early stages of development, including 100 percent owned projects at Narrows Lake and Telephone Lake. The Oil Sands segment also includes Cenovus’s Athabasca natural gas property. All of the gas produced from the Athabasca natural gas property since April 2018 is used as fuel at the adjacent Foster Creek operation.

As at December 31, 2020, Cenovus held bitumen rights of approximately 1.6 million gross acres (1.6 million net acres) within the Athabasca and Cold Lake areas, as well as the exclusive rights to lease an additional 536,000 gross acres on the Cold Lake Air Weapons Range, an active military base.

Development Approach

Cenovus uses steam-assisted gravity drainage (“SAGD”) technology to recover bitumen. The Corporation does not employ mining techniques for extraction and none of its reserves are suitable for extraction using mining techniques. SAGD involves injecting steam into the reservoir to enable bitumen to be pumped to the surface. Cenovus applies a manufacturing-like, phased approach to developing its oil sands assets. This approach incorporates learnings from previous phases into future growth plans, helping the Corporation to minimize costs.

Technology

Cenovus continues to focus on technologies which are targeted to lower its cost structure, improve margins, and reduce greenhouse gas emissions amid continuing price uncertainty, a lower carbon future, increased interest in corporate sustainability efforts and regulatory changes.

Foster Creek

Cenovus has a 100 percent working interest in Foster Creek. It is located on the Cold Lake Air Weapons Range and has a reservoir depth up to 500 meters below the surface. Foster Creek produces from the McMurray formation using SAGD technology.

The Corporation holds surface access rights from the governments of Canada and Alberta and bitumen rights from the Government of Alberta for exploration, development and transportation from areas within the Cold Lake Air Weapons Range. In addition, Cenovus holds exclusive rights to lease several hundred thousand acres of bitumen rights in other areas on the Cold Lake Air Weapons Range on the Corporation’s and/or its assignee’s behalf.

Production from phases A through G at Foster Creek averaged 163,210 barrels per day in 2020 (159,598 barrels per day in 2019).

Cenovus operates a 98-megawatt natural gas‑fired cogeneration facility in conjunction with Foster Creek. The steam and power generated by the facility is presently being used within the SAGD operation and any excess power generated is being sold into the Alberta power pool.

Christina Lake

Cenovus has a 100 percent working interest in Christina Lake. It is located approximately 120 kilometers south of Fort McMurray, Alberta and has a reservoir depth up to 375 meters below the surface. Christina Lake produces from the McMurray formation using SAGD technology.

Production from phases A through G at Christina Lake averaged 218,513 barrels per day in 2020 (194,659 barrels per day in 2019). Cenovus operates a 100-megawatt natural gas-fired cogeneration facility in conjunction with Christina Lake. The steam and power generated by the facility is presently being used within the SAGD operation and any excess power generated is being sold into the Alberta power pool. Phase G has an approved design capacity of 50,000 gross barrels per day. Cenovus began producing steam from phase G in 2019 and utilized the full facility in 2020.

Narrows Lake

Cenovus has a 100 percent working interest in Narrows Lake. Narrows Lake is located adjacent to Christina Lake and has a reservoir depth up to 375 meters below the surface.

In 2012, Cenovus received regulatory approval for 130,000 gross barrels per day of production capacity. Due to the low commodity price environment, and historically high price differentials, Cenovus had deferred new construction spending on phase A. Cenovus is now progressing development of the Narrows Lake resource by using existing infrastructure at Christina Lake.

Telephone Lake

Cenovus’s 100 percent owned Telephone Lake property is located in the Borealis Region in northeastern Alberta, approximately 90 kilometers northeast of Fort McMurray, Alberta.

Cenovus received approval from the Alberta Energy Regulator in late 2014 for a SAGD project with initial production capacity of 90,000 gross barrels per day. The Corporation continues to assess what may be the optimal development plan for the Telephone Lake asset.

Capital Investment

In 2020, capital investment in the Oil Sands segment was $427 million, focused on sustaining programs related to existing production at Foster Creek and Christina Lake as well as the stratigraphic test well program to determine pad placement for sustaining well pads and expansions. Other capital investment related to advancing key initiatives and technology development costs.

Cenovus Energy Inc.2020 Annual Information Form

CONVENTIONAL

Cenovus has western Canadian conventional crude oil and natural gas assets including undeveloped land, exploration and producing assets, and related infrastructure in Alberta and British Columbia. Cenovus’s Conventional Assets include approximately 3.6 million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, with an average 75 percent working interest. In addition, the Conventional Assets include interests in numerous natural gas processing plants with an estimated net processing capacity of 1.2 billion cubic feet per day. The Conventional Assets are expected to provide short-cycle development opportunities with high return potential that complement Cenovus’s long-term oil sands development. Conventional production is expected to provide an economic hedge for the natural gas required as a fuel source at both the Corporation’s oil sands and refining operations.

On January 1, 2020 the Marten Hills heavy oil assets were moved into the Conventional segment from the Oil Sands segment. In the fourth quarter of 2020, Cenovus completed the sale of its Marten Hills heavy oil assets to Headwater for a combination of cash, common share equity consideration and purchase warrants, while retaining a gross overriding royalty interest in the property.

Elmworth-Wapiti

Cenovus is one of the largest operators and producers in the Elmworth-Wapiti area, located in northwest Alberta and northeast British Columbia. As of December 31, 2020, Cenovus held leasehold rights of 1.16 million net acres in this area.

The Elmworth-Wapiti area provides production potential from more than 10 formations, with the most prospective being the Falher and Dunvegan. It is a mature area that was historically developed with conventional vertical well technology. Cenovus has shifted to horizontal drilling in its development programs with a view to unlock the vast resource potential in the tight sand plays.

The primary processing facility in the area is the Cenovus-operated Elmworth plant. The Corporation holds significant working interests in four other major natural gas processing facilities in the region. Net production in Elmworth-Wapiti averaged 30,898 barrels of oil equivalent per day in 2020 (31,992 barrels of oil equivalent per day in 2019).

Kaybob-Edson

As of December 31, 2020, Cenovus held leasehold rights of approximately 733,602 net acres in the Kaybob-Edson area, which is situated in west-central Alberta. Target development is in the Montney and Lower Cretaceous formations where successful industry drilling has proven the resource potential of those formations in lands offsetting Cenovus acreage. In the Kaybob-Edson area, natural gas processing is primarily controlled by midstream operators and other oil and gas companies.

Cenovus has secured longer term contracts to manage both existing base and new-development volumes. Additionally, Cenovus operates natural gas processing facilities in the area, including the Peco and Wolf plants. Net production in Kaybob-Edson averaged 29,085 barrels of oil equivalent per day in 2020 (34,751 barrels of oil equivalent per day in 2019).

Clearwater

The Clearwater area is situated in west-central Alberta, south of Kaybob-Edson. As of December 31, 2020, Cenovus held leasehold rights of approximately 765,136 net acres. Cenovus’s assets in the Clearwater area are characterized by multi-horizon, Cretaceous and Jurassic reservoirs at depths ranging from 1,900 meters to 3,000 meters, all with high NGL content in a predominantly gas prone area. This is a mature area historically developed with conventional vertical well technology, providing Cenovus with a series of lower risk horizontal drilling development programs. Cenovus operates natural gas processing facilities in the area, including the Sand Creek and Alder plants. Net production in Clearwater averaged 27,197 barrels of oil equivalent per day in 2020 (30,680 barrels of oil equivalent per day in 2019).

Capital Investment

In 2020, capital investment of $78 million in the Conventional segment focused on disciplined development, which encompassed maintaining safe and reliable operations, acquiring seismic data, start-up of a recompletion program to optimize existing production and commencement of a drilling program focusing on the Clearwater and Kaybob-Edson areas. The Kaybob-Edson area included the drilling of three net wells, completion of one net well, tie-in of one net well and other activities to maintain existing production and infrastructure. The Clearwater area focused on the drilling of three net wells and other activities to sustain existing production and infrastructure. The Elmworth-Wapiti area focused on activities to maintain existing production and infrastructure. Capital investment included expenditures on the Marten Hills heavy oil assets which were subsequently sold in the fourth quarter of 2020.

Cenovus Energy Inc.2020 Annual Information Form

REFINING AND MARKETING

Cenovus’s Refining and Marketing segment includes its U.S. refining non-operator ownership interests and operations involved in the coordination of Cenovus’s marketing and transportation initiatives to optimize the value received for its products.

Refining

The refining interests allow Cenovus to capture the value from crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility associated with regional North American light/heavy crude oil price differential fluctuations.

Through WRB, Cenovus has a 50 percent ownership interest in both the Wood River refinery located in Roxana, Illinois (the “Wood River Refinery”) and the Borger refinery located in Borger, Texas (the “Borger Refinery”). Phillips 66, an unrelated U.S. public company, is the operator and managing partner of WRB. WRB has a management committee, which is composed of three Cenovus representatives and three Phillips 66 representatives, with each company holding equal voting rights. The refineries have a combined stated processing capacity of approximately 495,000 gross barrels per day of crude oil in 2020.

The following table summarizes the key operational results for the refineries in the periods indicated:



Refinery Operations⁽¹⁾	2020	2019
Crude Oil Capacity (Mbbls/d)	495	482
Crude Oil Runs (Mbbls/d)	372	443
Heavy Oil	149	177
Light and Medium Oil	223	266
Crude Utilization (%)	75	92
Refined Products (Mbbls/d)
Gasoline	195	223
Distillates	127	167
Other	63	76
Total	385	466

(1)	Represents 100 percent of Wood River and Borger Refinery operations.

Wood River Refinery

Wood River Refinery ranks in the top 10 percent of approximately 130 refineries in the U.S., based on total crude oil capacity. It is located in Roxana, Illinois, approximately 25 kilometers northeast of St. Louis, Missouri. The Wood River Refinery processes light low-sulphur and heavy high-sulphur crude oil that it receives from North American crude oil pipelines to produce gasoline, diesel and jet fuel, petrochemical feedstock as well as petroleum coke and asphalt. The gasoline and diesel are transported via pipelines to markets in the upper U.S. Midwest. Other products are transported via pipeline, truck, barge and railcar to various markets.

Wood River Refinery’s stated crude oil processing capacity for 2020 was 346,000 gross barrels per day. In 2020, approximately 57 percent of the crude oil processed at the Wood River Refinery consisted of Canadian heavy crude oil.

Borger Refinery

Borger Refinery is located in Borger, Texas, approximately 80 kilometers north of Amarillo, Texas. Borger Refinery processes mainly medium and heavy high-sulphur crude oil that it receives from North American pipeline systems to produce gasoline, diesel and jet fuel, along with NGLs and solvents. The refined products are transported via pipelines to markets in Texas, New Mexico, Colorado and the U.S. Mid-Continent.

Borger Refinery’s stated crude oil processing capacity for 2020 was 149,000 gross barrels per day.

Capital Investment – Refining

In 2020, combined capital investment at both Wood River Refinery and Borger Refinery was $243 million net, focused on yield enhancement and reliability and maintenance projects.

Marketing

Cenovus’s marketing activities are focused on optimizing netbacks of its production and asset base across crude oil, condensate, natural gas, and NGLs.

As part of managing market risk arising from optimization activities, Cenovus may enter into financial transactions from time to time. Details of these transactions in 2020 are provided in the notes to the Corporation’s annual audited Consolidated Financial Statements for the year ended December 31, 2020.

Transportation

Cenovus continues to focus on near, mid, and long-term strategies to optimize netbacks for its production. As at December 31, 2020, Cenovus had entered into various transportation and storage commitments totaling $21 billion, $14 billion of which relates to pipelines that are in approval or construction phases but are not yet in service. With its committed capacity on pipeline projects, Cenovus has substantial potential future pipeline capacity to the Canadian West Coast and U.S. Gulf Coast.

The Corporation’s portfolio of transportation commitments includes feeder pipelines from its production areas to the major Alberta trade centres, major pipelines to markets downstream of these centres and rail transportation agreements, including contracts with rail companies to transport heavy

Cenovus Energy Inc.2020 Annual Information Form

crude oil from Alberta to various destinations on the U.S. Gulf Coast. Other transportation commitments are primarily related to diluent supply, railcar transportation as well as tankage and terminalling of both crude oil blend and condensate volumes.

Cenovus’s transportation portfolio also includes a crude-by-rail terminal located at Bruderheim, Alberta that is connected to the rail lines of Canadian National Railway and Canadian Pacific Railway, and allows crude oil to be delivered to major demand centres across Canada and the U.S. The Corporation has lifted the suspension of its crude-by-rail program after temporarily suspending the program during the second quarter of 2020 in response to improving market conditions. Volumes loaded at the Bruderheim terminal averaged 32,213 barrels per day (65,293 barrels per day in 2019).

Capital Investment ‑ Marketing

In 2020, Marketing capital investment was $33 million, focused on storage infrastructure projects.

THE HUSKY ARRANGEMENT

Pursuant to the Husky Arrangement, Husky became a wholly-owned subsidiary of Cenovus effective January 1, 2021 and will remain as such until completion of a planned amalgamation among the two entities. The combined company continues to operate as Cenovus, and remains headquartered in Calgary, Alberta.

For information regarding how the combined company’s business has been reorganized and segmented as of January 1, 2021, see “Description of the Business Following the Husky Arrangement”.

The following information describes the organization and segmentation of Husky’s business as at December 31, 2020. Husky’s business was organized under two business segments: (i) an integrated Canada-U.S. upstream and downstream corridor (the “Integrated Corridor”); and (ii) production located offshore the east coast of Canada (“Atlantic”) and offshore China and Indonesia (“Asia Pacific” and, collectively with Atlantic, “Offshore”).

Integrated Corridor

Husky’s business in the Integrated Corridor included (i) the Lloydminster Heavy Oil Value Chain; (ii) Oil Sands; (iii) Western Canada Production; (iv) U.S. Refining; and (v) Canadian Refined Products.

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The Lloydminster Heavy Oil Value Chain includes the exploration for, and development and production of, heavy crude oil and bitumen, and the production of ethanol. Blended heavy crude oil and bitumen are either sold directly to the Canadian market or transported utilizing the Husky Midstream Limited Partnership (“HMLP”) pipeline systems to the existing Keystone pipeline and other pipelines to be sold in the U.S. downstream market. Heavy crude oil can be upgraded at Husky’s upgrading facility located in Lloydminster, Saskatchewan (the “Lloydminster Upgrader”) and at Husky’s asphalt refinery in

Lloydminster, Alberta (the “Lloydminster Asphalt Refinery”) into synthetic crude oil, diesel fuel and asphalt. This business also includes the marketing and transportation of both Husky’s own production and third-party commodity trading volumes of heavy crude oil, synthetic crude oil, asphalt and ancillary products. The sale and transportation of Husky’s production and third-party commodity trading volumes are managed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. Husky is able to capture price differences between the two markets by utilizing infrastructure capacity to deliver production and/or third-party commodity trading volumes from Canada to the U.S. market.

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The Oil Sands business includes the exploration for, and development and production of, bitumen within Husky’s 50 percent owned and operated Sunrise Energy project in the Athabasca region of northern Alberta (the “Sunrise Energy Project”). It also includes the marketing and transportation of Husky’s and third-party production of bitumen through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S.

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The Western Canada Production business includes the exploration for, and development and production of, light crude oil, conventional natural gas and NGLs in Western Canada. Husky’s conventional natural gas and NGL production is marketed and transported with other third-party commodity trading volumes through access to capacity on third-party pipelines, export terminals and storage facilities which provides flexibility for market access.

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The U.S. Refining business includes the refining of crude oil at the crude oil refinery owned and operated by Husky and located in Lima, Ohio (the “Lima Refinery”), a non-operated interest in a crude oil refinery 50 percent owned by Husky and 50 percent owned and operated by BP Corporation North America Inc. (“BP”) and located in Toledo, Ohio (the “BP-Husky Toledo Refinery”), and the crude oil refinery owned by Husky and located in Superior, Wisconsin (the “Superior Refinery”) to produce diesel fuel, gasoline, asphalt and other products. Husky also markets its own and third-party volumes of refined petroleum products including gasoline and diesel fuel.

•	The Canadian Refined Products business includes the marketing of Husky’s and third-party volumes of refined petroleum products, including gasoline and diesel, through petroleum outlets.

Offshore

Husky’s Offshore business includes operations, development and exploration in Asia Pacific and Atlantic. The price received for Husky’s Asia Pacific production is largely based on long-term contracts and crude oil production from Atlantic is primarily driven by the price of Brent.

Cenovus Energy Inc.2020 Annual Information Form

Additional information concerning Husky’s business as of December 31, 2020 may be found in the Husky AIF, which is filed and available on SEDAR under Husky’s profile at sedar.com and on EDGAR at sec.gov.

INTEGRATED CORRIDOR

Third-Party Pipeline Commitments

In 2010, Husky commenced its pipeline commitment on the Keystone pipeline system, which ships Canadian crude oil from Hardisty, Alberta to Patoka, Illinois. Husky has the ability to utilize the portion of the Keystone pipeline system that continues to Cushing, Oklahoma, and Husky holds long-term firm capacity on the Enbridge Flanagan South pipeline and Southern Access Extension pipeline which connect Enbridge’s Mainline to the U.S. Gulf Coast and Patoka markets.

Due to Husky’s Keystone pipeline commitment, the Lima Refinery has the ability to access a significant amount of Canadian crude oil as part of its crude feedstock requirements. The Keystone pipeline has enabled Husky to transport crude oil through interconnecting pipeline systems to the Lima Refinery and/or sell it into the Cushing, Oklahoma market.

In 2017, Husky purchased the 50,000 barrel per-day Superior Refinery, which runs a combination of heavy Canadian crude and light crudes from Canada and the U.S. The Superior Refinery is located on the Enbridge Mainline crude system. As a seller and buyer of crude oils, Husky has a relatively balanced exposure to many location and grade differentials.

Lloydminster Heavy Oil Value Chain

Thermal and Non-Thermal Developments

Heavy Oil and Bitumen

The majority of Husky’s heavy oil assets are located in the Lloydminster region of Alberta and Saskatchewan, with lands consisting of approximately two million acres. The majority of Husky’s operations are 100 percent working interest. Husky’s operations are supported by a network of facilities and pipelines that transport heavy crude oil and bitumen from Husky’s field locations to the Lloydminster Asphalt Refinery, Lloydminster Upgrader and Husky’s other assets in the Integrated Corridor, providing Husky full integration.

Lloydminster Thermal Projects

Husky’s Lloydminster bitumen production consists of eleven thermal plants located in the Lloydminster region of Saskatchewan: Bolney/Celtic, Dee Valley, Edam East, Edam West, Paradise Hill, Pikes Peak South, Rush Lake 1 & 2, Sandall, Spruce Lake Central and Vawn. Each plant has a number of production pads and utilizes SAGD technology. Husky’s Lloydminster thermal production has been ramped up to full rates following a deliberate ramp down late in the first quarter of 2020 in response to market conditions. Production from Husky’s Lloydminster thermal projects averaged 81,000 barrels per day in 2020.

Husky has an inventory of thermal projects. These long-life developments are built with modular, repeatable designs and require low sustaining capital once brought online.

Tucker Thermal Project

Husky’s Tucker thermal project (the “Tucker Thermal Project”) is a SAGD oil sands project located 30 kilometers northwest of Cold Lake, Alberta. It commenced bitumen production at the end of 2006.

Bitumen production averaged 18,300 barrels per day in 2020.

A major plant turnaround was completed for the central processing facility and field in 2020.

Cold and Enhanced Oil Recovery (“EOR”)

Husky’s production from its Cold and EOR business consists of a combination of production technologies including, cold heavy oil productions with sand (“CHOPS”) and horizontal wells and EOR projects.

During 2020, Husky operated three CO2 injection EOR pilot projects and a CO2 capture and liquefaction plant at the Lloydminster Ethanol Plant. The liquefied CO2 is used in the ongoing EOR piloting program. Husky is also piloting a CO2 capture technology at its Pikes Peak South facility in Saskatchewan.

Production averaged 21,400 barrels per day of heavy crude oil, 1,400 barrels per day of medium crude oil and 11.2 million cubic feet per day of conventional natural gas in 2020.

Upgrading Operations

Husky owns and operates the Lloydminster Upgrader. The Lloydminster Upgrader is designed to process blended heavy crude oil feedstock, creating high quality, low-sulphur synthetic crude oil and ultra-low sulphur diesel and recovers diluent from the feedstock for return to, and reuse in, the field. Synthetic crude oil is used as refinery feedstock for the production of transportation fuels in Canada and the U.S.

The Lloydminster Upgrader’s current rated production capacity is 81,500 barrels per day of synthetic crude oil, diluent and ultra-low sulphur diesel.

Production at the Lloydminster Upgrader averaged 45,872 barrels per day of synthetic crude oil, 11,926 barrels per day of diluent and 6,043 barrels per day of ultra-low sulphur diesel in 2020. In addition, as by-products of its upgrading operations, the Lloydminster Upgrader produced approximately 297 long ton per day of sulphur and 774 long ton per day of petroleum coke during 2020. These products are sold in Canadian and international markets.

Lloydminster Asphalt Refinery

The Lloydminster Asphalt Refinery processes heavy crude oil and bitumen into asphalt products used in road construction and maintenance. The refinery has a throughput capacity of 30,000 barrels per day of heavy crude oil and bitumen. The refinery also produces straight run gasoline, bulk distillates and industrial products. The straight run gasoline stream

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is removed and re-circulated into HMLP’s pipeline network as pipeline diluent. The distillate stream is transferred to the Lloydminster Upgrader and treated for blending into the Husky Synthetic Blend (“HSB”) stream. Industrial products are a blend of medium and light distillate and gas oil streams, which are typically sold directly to customers as refinery feedstock, drilling and well-fracturing fluids, or used in asphalt cutbacks and emulsions.

Refinery throughput averaged 28,000 barrels per day of blended heavy crude oil and bitumen feedstock in 2020. Due to the seasonal demand for asphalt products, many asphalt refineries typically operate at full capacity only during the normal paving season in Canada and the northern U.S. Husky has implemented various strategies to increase refinery throughput during the other months of the year that are outside of the normal paving season, such as increasing storage capacity and developing U.S. markets for asphalt products. This allows the Lloydminster Asphalt Refinery to run at or near full capacity throughout the year.

Asphalt Distribution Network

In addition to sales directly from the Lloydminster Asphalt Refinery, Husky, through its asphalt division, has an asphalt distribution network which consists of seven asphalt terminals located at: Kamloops, British Columbia; Edmonton and Lethbridge, Alberta; Yorkton, Saskatchewan; Winnipeg, Manitoba; Rhinelander, Wisconsin; and Crookston, Minnesota and an emulsion plant located at Saskatoon, Saskatchewan. Husky also markets asphalt from independently operated terminals in the states of Washington, Minnesota, Wisconsin and Ohio.

The asphalt terminals in Rhinelander, Wisconsin and Crookston, Minnesota and the independently operated terminals in the states of Washington, Minnesota, Wisconsin and Ohio are part of Husky’s U.S. Refining business segment.

Ethanol Plants

Husky’s ethanol plant in Lloydminster, Saskatchewan has an annual nameplate capacity of 130 million liters and its Minnedosa, Manitoba ethanol plant has an annual nameplate capacity of 130 million liters. Combined ethanol production averaged 733,000 liters per day in 2020.

During 2012, the Lloydminster plant commissioned a CO2 capture facility. The plant is currently capturing CO2 for use in Husky’s non-thermal EOR projects and ethanol produced at the plant has a low carbon intensity designation.

Husky Midstream Limited Partnership

HMLP was created in July 2016 with the sale of selected pipeline gathering systems in Alberta and Saskatchewan and the Lloydminster and Hardisty terminals. CKI Infrastructure Holdings Limited owns 16.25 percent, Power Assets Holdings Limited owns 48.75 percent and Husky owns 35 percent of HMLP and Husky is the operator. HMLP has approximately 2,200 kilometers of pipeline in the Lloydminster region, 5.9 million barrels of storage capacity at Hardisty and Lloydminster and other ancillary assets.

Husky’s Lloydminster terminal, with a total storage capacity of 1.0 million barrels, serves as a hub for the gathering systems. The pipeline systems transport blended heavy crude oil to Lloydminster, accessing markets through the Lloydminster Upgrader and Lloydminster Asphalt Refinery. Blended heavy crude oil and bitumen from the field and synthetic crude oil from the upgrading operations are transported south to Hardisty, Alberta to a connection with the major export trunk pipelines. Husky’s Hardisty terminal, with a total storage capacity of 4.9 million barrels, acts as the exclusive blending hub for WCS. HMLP has diversified its operations with its Ansell Corser gas processing plant in west-central Alberta, with 120 million cubic feet per day of processing capacity.

Oil Sands

Sunrise Energy Project

On March 31, 2008, Husky and BP completed a transaction that created integrated North American oil sands and refining businesses. The businesses are comprised of a 50/50 partnership to develop the Sunrise Energy Project, operated by Husky, and a 50/50 limited liability company for the BP-Husky Toledo Refinery, operated by BP Products North America Inc.

The Sunrise Energy Project is a SAGD oil sands project located in the Athabasca region of northern Alberta. Bitumen production averaged approximately 44,800 barrels per day (22,400 barrels per day Husky working interest) in 2020.

Tucker Thermal Project

The Tucker Thermal Project is a SAGD oil sands project reported within the Lloydminster Heavy Oil Value Chain. See “Lloydminster Heavy Oil Value Chain - Thermal and Non-Thermal Developments” for more information.

Western Canada Production

Northern Operations

Husky’s Northern Operations are located primarily in northwest Alberta. Production in 2020 consisted of approximately 1,176 barrels per day of light crude oil, 5,208 barrels per day of NGLs and 148.2 million cubic feet per day of conventional natural gas reflecting heavily weighted conventional natural gas production of approximately 79 percent. Primary areas of operations include Edson and Grande Prairie, where operations are centered on liquids-rich gas resource production.

Edson operations are located primarily in west-central Alberta and consist of the Ansell and Galloway areas. The Ansell natural gas resource play is located in the deep basin Cretaceous formations. Husky holds an average 95 percent working interest in approximately 177 net sections of contiguous lands. Production from the Ansell and Galloway areas has doubled since 2012 and averaged 1,420 barrels per day of NGL and 100.1 million cubic feet per day of conventional natural gas in 2020.

Grande Prairie operations are located primarily in northwest Alberta and consist primarily of the

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Wembley, Kakwa, and Wapiti areas. Production from Grande Prairie averaged 1,170 barrels per day of light crude oil, 3,794 barrels per day of NGLs and 48.1 million cubic feet per day of conventional natural gas in 2020. The Kakwa Spirit River liquids-rich natural gas resource play averaged 36 barrels per day of light crude oil, 1,861 barrels per day of NGLs and 27.8 million cubic feet per day of conventional natural gas in 2020. Wapiti averaged 976 barrels per day of NGLs and 3.8 million cubic feet per day of conventional natural gas in 2020.

Southern Operations

Husky’s Southern Operations are primarily located in central and southern Alberta. As at December 31, 2020, Husky operated three natural gas facilities with approximately 600 active wells throughout the area. Production from Southern Operations averaged 265 barrels per day of light crude oil, 1,500 barrels per day of NGLs and 23.1 million cubic feet per day of conventional natural gas in 2020.

Rainbow Lake Operations

Rainbow Lake, located approximately 900 kilometers northwest of Edmonton, Alberta, is the site of Husky’s largest light crude oil production operation in Western Canada. Production from the Rainbow Lake assets averaged 4,286 barrels per day of light crude oil, 3,500 barrels per day of NGL and 78.7 million cubic feet per day of conventional natural gas in 2020.

Husky holds a 50 percent interest in a 90 megawatt natural gas fired cogeneration facility adjacent to its Rainbow Lake processing plant.

Canadian Refined Products

Retail and Commercial Network

As of December 31, 2020, Husky’s retail and commercial network included 546 independently operated Husky and Esso-branded petroleum product outlets. Husky’s retail and commercial operating model is balanced by corporate-owned/dealer-operated and branded dealer-owned-and-operated sites. The network consists of a variety of full- and self-serve retail stations, travel centres and cardlocks serving urban and rural markets across the country, while Husky’s bulk distributors offer direct sales to commercial and agricultural markets in the Prairie provinces.

U.S. Refining

Lima Refinery

The Lima Refinery has a crude oil throughput capacity of up to 175,000 barrels per day. The Lima Refinery processes both light sweet crude oil and heavy crude oil feedstock sourced from the U.S. and Canada, which includes Canadian synthetic crude oil, including HSB produced by the Lloydminster Upgrader. The Lima Refinery produces low-sulphur gasoline, gasoline blend stocks, ultra-low sulphur diesel, jet fuel, petrochemical feedstock and other by-products. The feedstocks are received via the Mid-Valley and Marathon pipelines, and the refined products are transported via the Buckeye, Inland and Energy Transfer Partners pipeline systems and by rail car to

primary markets in Ohio, Illinois, Indiana, Pennsylvania and southern Michigan.

During 2020, total throughput at the Lima Refinery averaged 140,000 barrels per day. Production consisted of an average of 68,000 barrels per day of gasoline, 53,000 barrels per day of total distillates and 19,000 barrels per day of other products in 2020.

The refinery is designed to allow for the processing of up to 40,000 barrels per day of heavy crude oil from Western Canada and the ability to swing between light and heavy crude oil feedstock.

BP-Husky Toledo Refinery

Husky’s BP-Husky Toledo Refinery has a nameplate capacity of 160,000 barrels per day. Products from the refinery include low-sulphur gasoline, ultra-low sulphur diesel, aviation fuels and by-products.

Husky’s share of total throughput averaged 65,400 barrels per day in 2020, with Husky’s share of sales averaging 38,900 barrels per day of gasoline, 20,100 barrels per day of distillates and 9,600 barrels per day of other fuel and feedstock.

Superior Refinery

On November 8, 2017, Husky completed the acquisition of the Superior Refinery, which has a permitted throughput capacity of 50,000 barrels per day and an operating capacity of 49,000 barrels per day on its crude slate at the time of acquisition. The refinery produces motor fuel products and asphalt from light and heavy crude oil originating from North Dakota and Western Canada.

The refinery also has associated infrastructure including five storage and distribution terminals that are strategically located throughout the northern area of the U.S. These terminals include: the Superior products terminal; the Duluth Terminal in Duluth, Minnesota, which has a storage capacity of 200,000 barrels; the Duluth Marine Terminal in Duluth, Minnesota which has a storage capacity of 14,000 barrels; the Rhinelander Terminal in Rhinelander, Wisconsin, which has a storage capacity of 166,000 barrels; and the Crookston Terminal in Crookston, Minnesota, which has a storage capacity of 156,000 barrels.

On April 26, 2018, the Superior Refinery experienced an incident while preparing for a major turnaround and was taken out of operation. During 2019, demolition, site preparation work and permitting were completed, and the rebuild work commenced. The rebuild is ongoing and Cenovus anticipates a substantial portion of the investment will be recovered from property damage insurance.

OFFSHORE

Asia Pacific

China

Liwan Gas Project

The Liwan Gas Project includes the natural gas discoveries at the Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 fields within the Contract Area 29/26

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exploration block located in the Pearl River Mouth Basin of the South China Sea, approximately 300 kilometers southeast of the Hong Kong Special Administrative Region.

Husky has a 49 percent working interest in the Liwan 3-1 and Liuhua 34-2 fields and a 75 percent working interest in the Liuhua 29-1 field, and China National Offshore Oil Corporation Limited or its subsidiaries (“CNOOC”) has 51 percent and 25 percent working interests, respectively.

Construction work was completed in the third quarter of 2020 at Liuhua 29-1, the third deepwater gas field of the Liwan Gas Project. First gas production from the Liuhua 29-1 development started in November 2020 and sales were initiated that same month. This seven-well subsea development is fully installed and utilizes the existing Liwan Gas Gathering system and the facilities located on the central platform and Gaolan Onshore Gas Plant. The buyer began taking 40 million cubic feet per day on November 4, 2020.

Total gas sales from Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 averaged 366 million cubic feet per day, 34 million cubic feet per day and 6 million cubic feet per day, respectively in 2020. Husky’s working interest share of production from the three fields was 201 million cubic feet per day of conventional natural gas and 8,600 barrels per day of NGL in 2020.

Block 15/33

Husky executed a production sharing contract (“PSC”) in December 2015 for an exploration block offshore China. Block 15/33 is located in the Pearl River Mouth Basin in the South China Sea, about 140 kilometers southeast of the Hong Kong Special Administrative Region and covers an area of 155 square kilometers in water depths of approximately 80 to 100 meters. Husky is the operator of the block during the exploration phase, with a working interest of 100 percent. In the event of a commercial discovery, its partner CNOOC may assume a working interest of up to 51 percent during the development and production phase by paying its proportional share of all development costs. Under the PSC, the corresponding CNOOC share of exploration costs is to be recovered from production allocated to Husky.

In the third quarter of 2020, an agreement was signed between Husky and CNOOC to extend the end of the second phase of exploration period of the petroleum contract to December 31, 2021.

Block 16/25

Husky executed a PSC in April 2017 for an exploration block offshore China. Block 16/25 is located in the Pearl River Mouth Basin in the South China Sea, about 150 kilometers southeast of the Hong Kong Special Administrative Region and approximately 72 kilometers northeast of Block 15/33. The block covers an area of 44 square kilometers in water depths of approximately 85 to 100 meters.

During 2020, an amendment agreement was signed between Husky and CNOOC under which the first phase of the exploration period was extended to April 30, 2022, with the remaining obligatory

exploration well to be completed in the area to be agreed upon by the parties. The initial contract area under the Block 16/25 petroleum contract was relinquished pursuant to the terms of the amendment agreement.

Blocks 22/11 and 23/07

Husky and CNOOC signed two PSCs for Blocks 22/11 and 23/07 in the Beibu Gulf area of the South China Sea in the first half of 2018. Husky is the operator of both blocks with a working interest of 100 percent during the exploration phase. In the event of a commercial discovery, its partner CNOOC may assume a participating partnership interest of up to 51 percent in either or both blocks for the development and production phases. Husky entered into the two-year exploration phase II of the PSC for Block 23/07 and committed to drill one exploration well before November 30, 2021. Block 22/11 was relinquished during 2020.

Taiwan

In December 2012, Husky signed a joint venture agreement with CPC Corporation, the Taiwan national oil and gas company. Husky and CPC Corporation have rights to an exploration block in the South China Sea covering approximately 7,700 square kilometers located southwest of the island of Taiwan. Husky holds a 75 percent working interest during exploration, while CPC Corporation holds the remaining 25 percent and has the right to participate in any development programs up to a 50 percent interest.

Indonesia

Madura Strait

Husky has a 40 percent interest in the joint venture that holds the Madura Strait PSC encompassing approximately 622,000 acres (2,516 square kilometers) in the Madura Strait area, located offshore East Java, Indonesia. Husky’s two partners in the incorporated joint venture are CNOOC, which is the contracted operator and has a 40 percent working interest, and Samudra Energy Ltd., which holds the remaining 20 percent interest through its affiliate, SMS Development Ltd. The Madura Strait includes the operating BD field and future developments at the MDA, MBH, MDK and MAC fields.

Total BD field sales averaged 86 million cubic feet per day of gas and 6,000 barrels per day of associated liquids in 2020. Husky’s working interest share of production was 34 million cubic feet per day of conventional natural gas and 2,400 barrels per day of NGLs in 2020.

Atlantic

Husky’s Atlantic exploration and development program is focused in the Jeanne d’Arc Basin and the Flemish Pass offshore Newfoundland and Labrador (“NL”). The Jeanne d’Arc Basin contains the Hibernia, Terra Nova and Hebron fields, as well as the White Rose field and satellite extensions, including North Amethyst, West White Rose and South White Rose. In the Flemish Pass Basin, Husky holds a 35 percent non-operated working interest in each of the Bay

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du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries. Husky is the operator of the White Rose field and satellite extensions and holds an ownership interest in the Terra Nova field, as well as a number of smaller undeveloped fields. Husky also holds significant exploration acreage offshore NL.

The White Rose field is located 354 kilometers off the coast of NL and is approximately 48 kilometers east of the Hibernia field on the eastern flank of the Jeanne d’Arc Basin. Husky is the operator of the main White Rose field and satellite tiebacks, including the North Amethyst, West White Rose and South White Rose extensions. Husky has a 72.5 percent working interest in the main field and a 68.875 percent working interest in the satellite extensions. To date, production has been facilitated via subsea tie-ins with wells drilled independently through drill centres and connected via flowlines to the SeaRose floating production, storage and offloading vessel.

Husky’s share of light crude oil production from the White Rose field and satellite extensions was 17,600 barrels per day (Husky working interest) during 2020.

In May 2017, Husky and its co-venturers announced plans to proceed with full field development at West White Rose using a fixed drilling platform. Major construction was suspended in March 2020 due to the COVID-19 situation. In October 2020, Husky announced the continued suspension of construction on the Concrete Gravity Structure in Argentia, NL.

DESCRIPTION OF THE BUSINESS FOLLOWING THE HUSKY ARRANGEMENT

Management is in the process of finalizing the determination of the operating and reporting segments for the Corporation following the Husky Arrangement. It is anticipated that the Corporation’s business will be conducted predominately through an upstream and downstream segment. Management continues to evaluate how the segments may be presented and will make a final determination during the first quarter of 2021.

The upstream business is anticipated to be reported as follows:

•	Oil Sands, includes the development and production of heavy oil and bitumen in northeast Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise and Tucker oil sands projects, as well as Lloydminster Thermal and Cold and Enhanced Oil Recovery assets.

•	Conventional, includes the operations from conventional oil and natural gas production, including processing operations in the Deep Basin and other parts of Western Canada.

•	Offshore, includes the offshore operations, exploration and development activities in the Asia Pacific region and Atlantic Canada region.

The downstream business is anticipated to be reported as follows:

•	Canadian Manufacturing, includes Cenovus’s owned and operated upgrader and asphalt refinery in Lloydminster, the owned and operated crude-by-rail terminal and two ethanol plants.

•	Retail, includes the Canadian retail, commercial and wholesale channels.

•	U.S. Manufacturing, includes the U.S. operations of wholly-owned refineries in Lima and Superior, the jointly owned Wood River and Borger refineries with operator Phillips 66 and the jointly owned Toledo refinery with BP Products North America Inc. as operator.

COMPETITIVE CONDITIONS

All aspects of the energy industry are highly competitive. For further information on the competitive conditions affecting Cenovus, refer to the section entitled “Risk Management and Risk Factors – Operational Risk” in the Corporation’s annual 2020 MD&A, which section of the MD&A is incorporated by reference into this AIF.

ENVIRONMENTAL PROTECTION

All phases of crude oil, natural gas and refining operations are subject to environmental regulation pursuant to a variety of federal, provincial, territorial, state, municipal and local laws and regulations in the jurisdictions in which Cenovus operates, as well as international conventions (collectively, the “environmental regulations”). For further information on the environmental regulations affecting Cenovus, refer to the section entitled “Risk Management and Risk Factors – Environmental Risk” in the Corporation’s annual 2020 MD&A, which section of the MD&A is incorporated by reference into this AIF.

CODE OF BUSINESS CONDUCT & ETHICS

Cenovus has established policies and standards relating to the conduct of business in a safe, healthy, ethical, legal and environmentally, socially and fiscally responsible manner. Cenovus’s commitment in these areas is reflected in the Code of Business Conduct & Ethics (the “Code”). The Code applies to the Corporation’s directors, officers and all employees, as well as contractors and suppliers who conduct activities for, or on behalf of, Cenovus. Individuals subject to the Code are accountable for applying it to their own conduct and work. Each employee, officer and director is also asked to regularly review the Code to confirm they understand their individual responsibilities and that they conform to the requirements of the Code.

The Code addresses the identification and management of ethical situations and provides guidance in making ethical business decisions and reporting violations of the Code. The Code provides a message from the President & Chief Executive Officer and addresses a number of matters including: (a) Cenovus’s values and reputation; (b) responsible information use; (c) acting with integrity;

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(d) compliance with laws and regulations; and (e) reporting potential violations.

Sustainability Policy

Cenovus’s Sustainability Policy addresses business conduct to help ensure the Corporation’s activities are undertaken in a responsible, transparent and respectful manner and in compliance with all applicable laws, regulations and industry standards in the jurisdictions in which Cenovus operates. The Sustainability Policy specifically references the following matters: (a) leadership and governance; (b) people; (c) environment; (d) stakeholder engagement; (e) Indigenous engagement; and (f) community involvement and investment.

With respect to the environment specifically, the Sustainability Policy provides that Cenovus recognizes the importance of: integrating environmental considerations into Cenovus’s business plans, spending decisions, performance management, project development, operations, communications and stakeholder relations; tracking and reporting on a broad range of environmental metrics; and committing to limit Cenovus’s impact on climate, air, land and water by investing in technology, continuously improving operating practices and collaborating externally to find innovative solutions to minimize environmental impact and maximize business value.

With respect to social aspects, the Sustainability Policy provides that Cenovus recognizes the importance of: conducting its business with respect and care for the people and communities affected by

its activities, noting the Corporation’s commitment to health and safety and support for the principles of the Universal Declaration of Human Rights; engaging stakeholders, including Indigenous communities, in a manner based on honesty, trust and respect; and developing and maintaining positive relationships with the communities within which Cenovus operates by, among other means, providing opportunities that help neighbouring communities share in the benefits that come from responsibly developing oil and natural gas resources, and striving to create a positive impact for both the community and Cenovus’s business through community investment programs.

In addition to the Code and Sustainability Policy, Cenovus has established other policies and practices that in some instances relate to environmental and or social aspects of Cenovus’s business. Stakeholders, employees and contractors are encouraged to report any business conduct concerns, including violations of applicable laws or any Cenovus policy, through the Corporation’s anonymous Integrity Helpline. Employees and contractors may also report any such concerns to their supervisor, a human resources business partner, or a member of the Investigations Committee.

The aforementioned policies are accessible on the Corporation’s website at cenovus.com, as is Cenovus’s Environmental, Social & Governance Report (“ESG Report”). The ESG Report is published annually to detail management’s efforts and performance across environment, social and governance topics that are important to its stakeholders.

EMPLOYEES

The following table summarizes Cenovus’s full-time equivalent (“FTE”) employees as at December 31, 2020:


	FTE Employees
Upstream	1,415
Downstream	109
Corporate	889
Total	2,413

Cenovus also engages contractors and service providers. As of December 31, 2020, Husky had 4,598 FTE employees. Refer to the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2020 MD&A, which section of the MD&A is incorporated by reference into this AIF, for further information on employee and other workforce related risks affecting Cenovus.

RISK FACTORS

A discussion of risk factors can be found in the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2020 MD&A, which section of the MD&A is incorporated by reference into this AIF.

RESERVES DATA AND OTHER OIL AND GAS INFORMATION

As a Canadian issuer, Cenovus is subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of the Corporation’s reserves in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51‑101”).

As at December 31, 2020, the Corporation’s reserves were located in Alberta and British Columbia, Canada. Cenovus retained two independent qualified reserves evaluators (“IQREs”), McDaniel & Associates

Consultants Ltd. (“McDaniel”) and GLJ Ltd. (“GLJ”), to evaluate and prepare reports on 100 percent of its bitumen, heavy crude oil, light crude oil and medium crude oil combined (“light and medium oil”), NGLs, conventional natural gas and shale gas proved and probable reserves. McDaniel evaluated approximately 96 percent of Cenovus’s proved reserves, all located in Alberta, and GLJ evaluated approximately four percent of the Corporation’s proved reserves, located in Alberta and British Columbia.

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The Safety, Environment, Responsibility and Reserves Committee (“SERR Committee”), composed entirely of independent directors, reviews, among other things, the qualifications and appointment of the IQREs, the procedures relating to the disclosure of information with respect to oil and gas activities and the procedures for providing information to the IQREs. The SERR Committee meets independently with the management of Cenovus and each IQRE to determine whether any restrictions affect the ability of the IQREs to report on the reserves data without reservation. In addition, the SERR Committee reviews the reserves data and the report of the IQREs and provides a recommendation regarding approval of the reserves disclosure to the Board.

Classifications of reserves as proved or probable are only attempts to define the degree of certainty associated with the estimates. There are numerous uncertainties inherent in estimating quantities of petroleum reserves. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. Readers should review the definitions and information contained in “Additional Notes to Reserves Data Tables”, “Definitions” and “Pricing Assumptions” in

conjunction with the reserves disclosure. The reserves estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates disclosed. See the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2020 MD&A, which section of the MD&A is incorporated by reference into this AIF, for additional information.

Cenovus’s reserves data and other oil and gas information contained in this AIF is dated February 8, 2021, with an effective date of December 31, 2020. McDaniel’s preparation date of the information is January 19, 2021 and GLJ’s preparation date is January 6, 2021. For certain reserves data, additional disclosure is provided to show the anticipated effect of the Husky Arrangement – see “Expected Changes to Reserves - Husky Arrangement”. For certain categories of “Other Oil and Gas Information” additional disclosure is provided to show the anticipated effect of the Husky Arrangement, which disclosure is identified as including information from Husky. Additional information concerning Husky and its reserves data and other oil and gas information as of December 31, 2020 may be found in the Husky AIF and the Husky MD&A, each of which is filed and available on SEDAR under Husky’s profile at sedar.com and on EDGAR at sec.gov.

Disclosure of Reserves Data

The reserves data presented summarizes the Corporation’s bitumen, heavy crude oil, light and medium oil, NGLs, conventional natural gas, shale gas and total reserves and the net present values (“NPV”) and future net revenue (“FNR”) for these reserves. The reserves data uses forecast prices and costs prior to provision for interest, G&A expenses or the impact of any hedging activities. Estimates of FNR have been presented on a before and after income tax basis. For the purposes of this section and the section entitled “Expected Changes to Reserves – Husky Arrangement”, references to “Company” are to Cenovus Energy Inc.

Summary of Company Interest Oil and Gas Reserves as at December 31, 2020

(Forecast prices and costs)


Before Royalties⁽¹⁾	Bitumen (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas⁽²⁾ (Bcf)	Total (MMBOE)
Proved Reserves
Developed Producing	765	7	40	790	943
Developed Non-Producing	199	-	1	18	203
Undeveloped	3,848	-	9	157	3,884
Proved Reserves	4,812	7	50	965	5,030
Probable Reserves	1,520	6	31	601	1,656
Proved plus Probable Reserves	6,332	13	81	1,566	6,686


After Royalties⁽³⁾	Bitumen⁽⁴⁾ (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas⁽²⁾ (Bcf)	Total (MMBOE)
Proved Reserves
Developed Producing	604	6	33	745	768
Developed Non-Producing	156	-	1	17	160
Undeveloped	2,999	-	8	149	3,032
Proved Reserves	3,759	6	42	911	3,960
Probable Reserves	1,115	5	27	561	1,240
Proved plus Probable Reserves	4,874	11	69	1,472	5,200

(1)	Before royalties excludes royalty interest reserves.

(2)	Includes shale gas that is not material representing less than 1% of total conventional natural gas on a proved plus probable basis.

(3)	Includes royalty interest reserves.

(4)	Includes heavy crude oil that is not material representing less than 1% of total bitumen on a proved plus probable basis.

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Summary of Net Present Value of Future Net Revenue as at December 31, 2020

(Forecast prices and costs)


	Discounted at %/year ($ millions)					Unit Value Discounted at 10%⁽¹⁾
Before Income Taxes	0%	5%	10%	15%	20%	$/BOE
Proved Reserves
Developed Producing	11,486	12,182	10,814	9,517	8,464	14.09
Developed Non-Producing	4,215	3,155	2,440	1,938	1,572	15.30
Undeveloped	83,708	30,790	14,080	7,530	4,478	4.64
Proved Reserves	99,409	46,127	27,334	18,985	14,514	6.90
Probable Reserves	46,804	11,424	4,576	2,621	1,807	3.69
Proved plus Probable Reserves	146,213	57,551	31,910	21,606	16,321	6.14


	Discounted at %/year ($ millions)
After Income Taxes⁽²⁾	0%	5%	10%	15%	20%
Proved Reserves
Developed Producing	9,143	10,201	9,229	8,196	7,333
Developed Non-Producing	3,267	2,437	1,880	1,490	1,208
Undeveloped	64,765	23,546	10,578	5,550	3,230
Proved Reserves	77,175	36,184	21,687	15,236	11,771
Probable Reserves	36,095	8,724	3,488	1,999	1,377
Proved plus Probable Reserves	113,270	44,908	25,175	17,235	13,148

(1)	Unit values have been calculated using Company Interest After Royalties reserves.

(2)

Values are calculated by considering existing tax pools and tax circumstances for Cenovus and its subsidiaries in the consolidated evaluation of Cenovus’s oil and gas properties and taking into account current federal and provincial tax regulations. Values do not represent an estimate of the value at the business entity level, which may be significantly different. For information at the business entity level, please see Cenovus’s Consolidated Financial Statements and MD&A for the year ended December 31, 2020.

Total Future Net Revenue (undiscounted) as at December 31, 2020

(Forecast prices and costs ‑ $ millions)


Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Total Abandonment and Reclamation Costs⁽¹⁾	Future Net Revenue Before Future Income Taxes	Future Income Taxes	Future Net Revenue After Future Income Taxes
Proved Reserves	258,732	57,269	62,975	32,576	6,503	99,409	22,234	77,175
Proved plus Probable Reserves	372,906	86,837	84,905	47,597	7,354	146,213	32,943	113,270

(1)	Total abandonment and reclamation costs included for all wells, facilities and other liabilities, known and existing, and to be incurred as a result of future development activity.

Future Net Revenue by Product Type as at December 31, 2020

(Forecast prices and costs)


Reserves Category	Product Types	Future Net Revenue Before Income Taxes (discounted at 10%/year) ($ millions)	Unit Value Discounted at 10%/year⁽¹⁾ ($/BOE)
Proved Reserves	Bitumen⁽²⁾	26,834	7.14
	Light and Medium Oil⁽³⁾	60	4.61
	Conventional Natural Gas⁽⁴⁾	440	2.34
	Total	27,334	6.90
Proved plus	Bitumen⁽²⁾	30,863	6.33
Probable Reserves	Light and Medium Oil⁽³⁾	124	4.87
	Conventional Natural Gas⁽⁴⁾	923	3.07
	Total	31,910	6.14

(1)	Unit values have been calculated using Company Interest After Royalties reserves.

(2)	Includes heavy crude oil that is not material.

(3)	Includes solution gas and other byproducts.

(4)	Includes shale gas and other byproducts, but excludes solution gas.

Cenovus Energy Inc.2020 Annual Information Form

Additional Notes to Reserves Data Tables

•	The estimates of FNR presented do not represent fair market value.

•	FNR from reserves excludes cash flows related to Cenovus’s risk management activities.

•	For disclosure purposes, Cenovus has included heavy crude oil with bitumen and shale gas with conventional natural gas, as the reserves of heavy crude oil and shale gas are not material.

•	In accordance with NI 51‑101, NPV and FNR amounts presented include all of Cenovus’s existing estimated abandonment and reclamation costs, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity associated with the reserves.

•	Barrels of oil equivalent estimates and tables may not sum due to rounding.

Definitions

1.	After Royalties means volumes after deduction of royalties and includes royalty interest reserves.

2.	Before Royalties means volumes before deduction of royalties and excludes royalty interest reserves.

3.	Company Interest means, in relation to production, reserves, resources and property, the interest (operating or non‑operating) held by Cenovus.

4.	Gross means: (a) in relation to wells, the total number of wells in which Cenovus has an interest; and (b) in relation to properties, the total acreage of properties in which Cenovus has an interest.

5.	Net means: (a) in relation to wells, the number of wells obtained by aggregating Cenovus’s working interest in each of its gross wells; and (b) in relation to Cenovus’s interest in a property, the total acreage in which it has an interest multiplied by its working interest.

6.	Proved plus probable reserves life index means Company Interest Before Royalties proved plus probable reserves divided by Company Interest Before Royalties production.

7.	Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on analysis of drilling, geological, geophysical and

engineering data, the use of established technology and specified economic conditions, which are generally accepted as being reasonable, and are disclosed later in this AIF.

Reserves are classified according to the degree of certainty associated with the estimates:

•

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

•

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Each of the reserves categories may be divided into developed and undeveloped categories:

•

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided as follows:

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

•

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

Cenovus Energy Inc.2020 Annual Information Form

Pricing Assumptions

The forecast of prices, inflation and exchange rate provided in the table below is computed using the average of forecasts (“IQRE Average Forecast”) by McDaniel, GLJ and Sproule Associates Limited (“Sproule”) and is used to estimate FNR associated with the reserves disclosed herein. The IQRE Average Forecast is dated January 1, 2021. The inflation forecast was applied uniformly to prices beyond the forecast interval, and to all future costs. For historical prices realized during 2020, see “Production History and Per-Unit Results” in this AIF.


	Oil and Liquids				Natural Gas
Year	WTI Cushing Oklahoma (US$/bbl)	Edmonton Par Price 40 API (C$/bbl)	Western Canadian Select (C$/bbl)	Edmonton C5+ (C$/bbl)	AECO Gas Price (C$/MMBtu)	Inflation Rate (%/year)	Exchange Rate (US$/C$)
2021	47.17	55.76	44.63	59.24	2.78	0.0	0.7683
2022	50.17	59.89	48.18	63.19	2.70	1.3	0.7650
2023	53.17	63.48	52.10	67.34	2.61	2.0	0.7633
2024	54.97	65.76	54.10	69.77	2.65	2.0	0.7633
2025	56.07	67.13	55.19	71.18	2.70	2.0	0.7633
2026	57.19	68.53	56.29	72.61	2.76	2.0	0.7633
2027	58.34	69.95	57.42	74.07	2.81	2.0	0.7633
2028	59.50	71.40	58.57	75.56	2.86	2.0	0.7633
2029	60.69	72.88	59.74	77.08	2.92	2.0	0.7633
2030	61.91	74.34	60.93	78.62	2.98	2.0	0.7633
2031	63.15	75.83	62.15	80.19	3.04	2.0	0.7633
2032+	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	2.0	0.7633

Future Development Costs

The following table outlines undiscounted future development costs deducted in the estimation of FNR for the years indicated:


Reserves Category ($ millions)	2021	2022	2023	2024	2025	Remainder	Total
Proved Reserves	340	457	886	821	630	29,442	32,576
Proved plus Probable Reserves	378	501	890	826	652	44,350	47,597

Cenovus believes that existing cash balances, internally generated cash flows, existing credit facilities, management of its asset portfolio and access to capital markets will be sufficient to fund the Corporation’s future development costs. However, there can be no guarantee that the necessary funds will be available or that Cenovus will allocate funding to develop all of its reserves. Failure to develop those reserves would have a negative impact on the Corporation’s FNR.

The interest or other costs of external funding are not included in the reserves and FNR estimates and would reduce FNR depending upon the funding sources utilized. Cenovus does not believe that interest or other funding costs would make development of any property uneconomic.

Cenovus Energy Inc.2020 Annual Information Form

Reserves Reconciliation

The following tables provide a reconciliation of Company Interest Before Royalties reserves for bitumen, heavy crude oil, light and medium oil, NGLs, conventional natural gas and shale gas for the year ended December 31, 2020, presented using forecast prices and costs.


Proved	Bitumen⁽¹⁾ (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas⁽²⁾ (Bcf)	Total (MMBOE)
As at December 31, 2019	4,826	9	60	1,242	5,103
Extensions and Improved Recovery	4	-	1	10	6
Discoveries	-	-	-	-	-
Technical Revisions	131	-	(3)	(126)	108
Economic Factors	-	-	(2)	(37)	(9)
Acquisitions	-	-	1	18	3
Dispositions	(8)	-	-	-	(8)
Production⁽³⁾	(141)	(2)	(7)	(142)	(173)
As at December 31, 2020	4,812	7	50	965	5,030


Probable	Bitumen⁽¹⁾ (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas⁽²⁾ (Bcf)	Total (MMBOE)
As at December 31, 2019	1,594	8	37	783	1,768
Extensions and Improved Recovery	(4)	1	-	4	(2)
Discoveries	-	-	-	-	-
Technical Revisions	(50)	(2)	(4)	(155)	(83)
Economic Factors	-	(1)	(2)	(35)	(8)
Acquisitions	-	-	-	4	1
Dispositions	(20)	-	-	-	(20)
Production⁽³⁾	-	-	-	-	-
As at December 31, 2020	1,520	6	31	601	1,656


Proved plus Probable	Bitumen⁽¹⁾ (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas⁽²⁾ (Bcf)	Total (MMBOE)
As at December 31, 2019	6,420	17	97	2,025	6,871
Extensions and Improved Recovery	-	1	1	14	4
Discoveries	-	-	-	-	-
Technical Revisions	81	(2)	(7)	(281)	25
Economic Factors	-	(1)	(4)	(72)	(17)
Acquisitions	-	-	1	22	4
Dispositions	(28)	-	-	-	(28)
Production⁽³⁾	(141)	(2)	(7)	(142)	(173)
As at December 31, 2020	6,332	13	81	1,566	6,686

(1)	Includes heavy crude oil that is not material.

(2)	Includes shale gas that is not material.

(3)

Production used for the reserves reconciliation differs from publicly reported production. In accordance with NI 51‑101, Company Interest Before Royalties production used for the reserves reconciliation above includes Cenovus’s share of gas volumes provided to FCCL for steam generation, but does not include royalty interest production.

Bitumen proved and proved plus probable reserves decreased by 14 million barrels and 88 million barrels, respectively, as additions from improved performance in Oil Sands were more than offset by the disposition of the Marten Hills heavy oil assets and current year production;

Light and medium oil proved and proved plus probable reserves decreased by two million barrels and four million barrels, respectively, as minor additions were more than offset by technical revisions attributed to updates to the Conventional development plan, economic factors due to reduced product pricing, and current year production;

NGLs proved and proved plus probable reserves decreased by 10 million barrels and 16 million barrels, respectively, as minor additions and a minor acquisition were more than offset by reductions due to technical revisions attributed to updates to the Conventional development plan, economic factors due to reduced product pricing, and current year production; and

Conventional natural gas proved and proved plus probable reserves decreased by 277 billion cubic feet and 459 billion cubic feet, respectively, as additions attributed to Conventional development and minor acquisitions were more than offset by reductions due to technical revisions attributed to updates to the Conventional development plan, economic factors due to reduced product pricing, and current year production.

Undeveloped Reserves

Proved and probable undeveloped reserves have been estimated by the IQREs in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”). In general, undeveloped reserves are scheduled to be produced within the next one to 50 years.

Cenovus Energy Inc.2020 Annual Information Form

The undeveloped tables presented here reflect the product type groups reported above, specifically, bitumen includes heavy crude oil and conventional natural gas includes shale gas.


Company Interest Proved Undeveloped – Before Royalties
	Bitumen⁽¹⁾ (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional Natural Gas⁽²⁾ (Bcf)		Total (MMBOE)
	First Attributed	Total at Year-End	First Attributed	Total at Year-End	First Attributed	Total at Year-End	First Attributed	Total at Year-End	First Attributed	Total at Year-End
2018	197	3,986	1	1	7	15	159	324	233	4,056
2019	37	3,827	–	1	2	10	30	208	43	3,873
2020	99	3,848	–	–	1	9	16	157	103	3,884

(1)	Includes heavy crude oil that is not material.

(2)	Includes shale gas that is not material.


Company Interest Probable Undeveloped – Before Royalties
	Bitumen⁽¹⁾ (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional Natural Gas⁽²⁾ (Bcf)		Total (MMBOE)
	First Attributed	Total at Year-End	First Attributed	Total at Year-End	First Attributed	Total at Year-End	First Attributed	Total at Year-End	First Attributed	Total at Year-End
2018	30	1,502	2	2	15	25	365	619	108	1,632
2019	7	1,474	3	5	5	21	87	433	29	1,571
2020	–	1,407	1	3	1	18	13	317	3	1,481

(1)	Includes heavy crude oil that is not material.

(2)	Includes shale gas that is not material.

Development of Proved and Probable Undeveloped Reserves

Bitumen

At the end of 2020, Cenovus had proved undeveloped bitumen reserves of 3,848 million barrels Before Royalties, or approximately 80 percent of the Corporation’s proved bitumen reserves. Of Cenovus’s 1,520 million barrels of probable bitumen reserves, 1,407 million barrels, or approximately 93 percent, are undeveloped. The evaluation of these reserves anticipates that the reserves will be recovered using SAGD.

Typical SAGD project development involves the initial installation of a steam generation facility, at a cost much greater than drilling a production/injection well pair, and then progressively drilling sufficient SAGD well pairs to fully utilize the available steam.

Bitumen reserves can be classified as proved when there is sufficient stratigraphic drilling to have demonstrated to a high degree of certainty the presence of the bitumen in commercially recoverable volumes. McDaniel’s standard for sufficient drilling in the McMurray formation is a minimum of eight stratigraphic wells per section with 3D seismic, or 16 stratigraphic wells per section with no seismic. Additionally, all requisite legal and regulatory approvals must have been obtained, operator funding approvals must be in place, and a reasonable development timetable must be established. Proved developed bitumen reserves are differentiated from proved undeveloped bitumen reserves by the presence of drilled production/injection well pairs at the reserves estimation effective date. Because a steam plant has a long life relative to well pairs, in the early stages of a SAGD project, only a small portion of proved reserves will be developed as the number of well pairs drilled will be limited by the available steam capacity.

Recognition of probable reserves requires sufficient drilling of stratigraphic wells to establish reservoir suitability for SAGD. McDaniel’s standard for probable reserves is a minimum of four stratigraphic wells per section. Reserves will be classified as probable if the number of wells drilled falls between the stratigraphic well requirements for proved reserves and for probable reserves, or if the reserves are located outside of an approved development plan area, but within an approved project area. If reserves lie outside the approved development area, approval to include those reserves in the development area must be obtained before development drilling of SAGD well pairs can commence.

Development of the proved and probable Foster Creek and Christina Lake undeveloped reserves will take place in an orderly manner as additional well pairs are drilled to utilize the available steam when existing well pairs reach the end of their steam injection phase. Development and capital spending on the proved and probable undeveloped reserves at Narrows Lake continues with the project currently scheduled to be on stream by 2026. The forecast production of Cenovus’s proved and proved plus probable bitumen reserves, extends approximately 46 years and 50 years, respectively. Production of the current proved developed portion is estimated to take approximately 21 years.

Light and Medium Oil, NGLs and Conventional Natural Gas

Cenovus’s Conventional Assets proved undeveloped and proved plus probable undeveloped reserves are approximately one percent and two percent of the Corporation’s proved and proved plus probable reserves, respectively. Cenovus plans to develop the Conventional proved and proved plus probable undeveloped reserves over the next five years and ten years, respectively.

Cenovus Energy Inc.2020 Annual Information Form

Significant Factors or Uncertainties Affecting Reserves Data

The evaluation of reserves is a continuous process that can be significantly impacted by a variety of internal and external influences. Revisions are often required resulting from changes in pricing, economic conditions, regulatory changes, and historical performance. While these factors can be considered and potentially anticipated, certain judgments and assumptions are always required. As new information becomes available, these areas are reviewed and revised accordingly. For a discussion of the risk factors and uncertainties affecting Cenovus’s reserves data, see the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2020 MD&A, which section of the MD&A is incorporated by reference into this AIF. For a discussion of the risk factors and uncertainties affecting Husky’s reserves data, see the section entitled “Risk Management and Risk Factors” in the Husky MD&A.

Expected Changes to Reserves – Husky Arrangement

The pro forma reserves information presented in this AIF sets forth Cenovus’s anticipated gross reserves as at December 31, 2020 after giving effect to the Husky Arrangement as though the transaction had occurred on December 31, 2020. Cenovus has not constructed a consolidated reserves report of the combined assets of Cenovus and Husky, and has not engaged an independent reserves evaluator to produce such a report in accordance with NI 51-101.

Cenovus and Husky employed different methodologies to estimate their reserves information for the year ended December 31, 2020. Cenovus retained two IQREs, McDaniel and GLJ, to evaluate and prepare reports on 100 percent of its proved and probable reserves. All of Husky’s oil and gas reserves estimates were prepared by internal qualified reserves evaluators using a formalized process for determining, approving and booking reserves, and do not form part of Cenovus's reserves data as at December 31, 2020. For the purposes of Husky’s NI 51-101 reserves disclosure in the Husky AIF, Husky engaged Sproule to conduct a complete audit and review of 100 percent of Husky’s oil and gas reserves estimates. Sproule issued an audit opinion stating that Husky’s internally generated proved and probable reserves and net present values based on forecast and constant price assumptions are, in aggregate, reasonable, and have been prepared in accordance with generally accepted oil and gas engineering and evaluation practices as set out in the COGE Handbook. Cenovus's Board has not independently reviewed Husky’s process and procedures for determining, approving and booking Husky's reserves estimates and has relied on Sproule’s audit opinion as to the reasonableness of Husky’s reserves estimates as at December 31, 2020, and on Husky’s review and approval of such audit.

As a result, the actual reserves of Cenovus (after giving effect to the Husky Arrangement), if calculated as at December 31, 2020 by an independent reserves evaluator in accordance with NI 51-101, may differ from the reserves information presented in this AIF for a number of reasons, and such differences may be material. Additional information concerning Husky’s oil and natural gas properties and Husky’s operations and business as of December 31, 2020 may be found in the Husky AIF and the Husky MD&A, each of which is filed and available on SEDAR under Husky’s profile at sedar.com and on EDGAR at sec.gov.

Summary of Company Interest Oil and Gas Reserves as at December 31, 2020
(after giving effect to the Husky Arrangement)

(Forecast prices and costs)


Canada Before Royalties⁽¹⁾	Bitumen⁽²⁾ (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas⁽³⁾ (Bcf)	Total (MMBOE)
Proved Reserves
Developed Producing	920	27	65	1,352	1,238
Developed Non-Producing	214	2	3	38	224
Undeveloped	4,608	–	17	276	4,672
Proved Reserves	5,742	29	85	1,666	6,134
Probable Reserves	1,791	152	52	902	2,145
Proved plus Probable Reserves	7,533	181	137	2,568	8,279

(1)	Before royalties excludes royalty interest reserves.

(2)	Includes heavy crude oil that is not material.

(3)	Includes shale gas that is not material.


China Before Royalties⁽¹⁾	Bitumen (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (Bcf)	Total (MMBOE)
Proved Reserves
Developed Producing	–	–	18	493	100
Developed Non-Producing	–	–	–	–	–
Undeveloped	–	–	–	–	–
Proved Reserves	–	–	18	493	100
Probable Reserves	–	–	1	63	12
Proved plus Probable Reserves	–	–	19	556	112

(1)	Before royalties excludes royalty interest reserves.

Cenovus Energy Inc.2020 Annual Information Form


Indonesia Before Royalties⁽¹⁾	Bitumen (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas (Bcf)	Total (MMBOE)
Proved Reserves
Developed Producing	–	–	4	129	26
Developed Non-Producing	–	–	–	–	–
Undeveloped	–	–	–	68	11
Proved Reserves	–	–	4	197	37
Probable Reserves	–	–	2	56	11
Proved plus Probable Reserves	–	–	6	253	48

(1)	Before royalties excludes royalty interest reserves.


Company Total Before Royalties⁽¹⁾	Bitumen⁽²⁾ (MMbbls)	Light and Medium Oil (MMbbls)	NGLs (MMbbls)	Conventional Natural Gas⁽³⁾ (Bcf)	Total (MMBOE)
Proved Reserves
Developed Producing	920	27	87	1,974	1,364
Developed Non-Producing	214	2	3	38	224
Undeveloped	4,608	–	17	344	4,683
Proved Reserves	5,742	29	107	2,356	6,271
Probable Reserves	1,791	152	55	1,021	2,168
Proved plus Probable Reserves	7,533	181	162	3,377	8,439

(1)	Before royalties excludes royalty interest reserves.

(2)	Includes heavy crude oil that is not material.

(3)	Includes shale gas that is not material.

Summary of Net Present Value of Future Net Revenue as at December 31, 2020
(after giving effect to the Husky Arrangement)

(Forecast prices and costs)


Canada	Discounted at %/year ($ millions)
Before Income Taxes	0%	5%	10%	15%	20%
Proved Reserves
Developed Producing	8,309	12,620	11,915	10,783	9,756
Developed Non-Producing	4,023	3,041	2,362	1,880	1,528
Undeveloped	94,363	34,510	15,694	8,275	4,792
Proved Reserves	106,695	50,171	29,971	20,938	16,076
Probable Reserves	55,558	16,993	8,142	4,961	3,370
Proved plus Probable Reserves	162,253	67,164	38,113	25,899	19,446


China	Discounted at %/year ($ millions)
Before Income Taxes	0%	5%	10%	15%	20%
Proved Reserves
Developed Producing	5,049	4,225	3,635	3,196	2,860
Developed Non-Producing	–	–	–	–	–
Undeveloped	–	–	–	–	–
Proved Reserves	5,049	4,225	3,635	3,196	2,860
Probable Reserves	565	404	309	248	206
Proved plus Probable Reserves	5,614	4,629	3,944	3,444	3,066


Indonesia	Discounted at %/year ($ millions)
Before Income Taxes	0%	5%	10%	15%	20%
Proved Reserves
Developed Producing	435	372	324	287	257
Developed Non-Producing	–	–	–	–	–
Undeveloped	241	194	157	128	106
Proved Reserves	676	566	481	415	363
Probable Reserves	179	117	80	56	41
Proved plus Probable Reserves	855	683	561	471	404


Company Total	Discounted at %/year ($ millions)
Before Income Taxes	0%	5%	10%	15%	20%
Proved Reserves
Developed Producing	13,793	17,217	15,874	14,266	12,873
Developed Non-Producing	4,023	3,041	2,362	1,880	1,528
Undeveloped	94,604	34,704	15,851	8,403	4,898
Proved Reserves	112,420	54,962	34,087	24,549	19,299
Probable Reserves	56,302	17,514	8,531	5,265	3,617
Proved plus Probable Reserves	168,722	72,476	42,618	29,814	22,916

Cenovus Energy Inc.2020 Annual Information Form

Total Future Net Revenue (undiscounted) as at December 31, 2020
(after giving effect to the Husky Arrangement)

(Forecast prices and costs ‑ $ millions)


Canada Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Total Abandonment and Reclamation Costs⁽¹⁾	Future Net Revenue Before Future Income Taxes
Proved Reserves	310,192	62,070	87,376	41,556	12,495	106,695
Proved plus Probable Reserves	449,680	94,168	118,047	61,402	13,810	162,253

(1)	Total abandonment and reclamation costs included for all wells, facilities and other liabilities, known and existing, and to be incurred as a result of future development activity.


China Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Total Abandonment and Reclamation Costs⁽¹⁾	Future Net Revenue Before Future Income Taxes
Proved Reserves	6,953	376	1,368	–	160	5,049
Proved plus Probable Reserves	7,727	419	1,534	–	160	5,614

(1)	Total abandonment and reclamation costs included for all wells, facilities and other liabilities, known and existing, and to be incurred as a result of future development activity.


Indonesia Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Total Abandonment and Reclamation Costs⁽¹⁾	Future Net Revenue Before Future Income Taxes
Proved Reserves	2,342	719	883	36	28	676
Proved plus Probable Reserves	3,052	1,048	1,081	36	32	855

(1)	Total abandonment and reclamation costs included for all wells, facilities and other liabilities, known and existing, and to be incurred as a result of future development activity.


Company Total Reserves Category	Revenue	Royalties	Operating Costs	Development Costs	Total Abandonment and Reclamation Costs⁽¹⁾	Future Net Revenue Before Future Income Taxes
Proved Reserves	319,487	63,165	89,627	41,592	12,683	112,420
Proved plus Probable Reserves	460,459	95,635	120,662	61,438	14,002	168,722

(1)	Total abandonment and reclamation costs included for all wells, facilities and other liabilities, known and existing, and to be incurred as a result of future development activity.

Cenovus Energy Inc.2020 Annual Information Form

Pricing Assumptions (after giving effect to the Husky Arrangement)

Except as noted below, the forecast of prices, inflation and exchange rate provided in the table below is computed using the IQRE Average Forecast and is used to estimate FNR associated with the reserves after giving effect to the Husky Arrangement. The IQRE Average Forecast is dated January 1, 2021. The inflation forecast was applied uniformly to prices beyond the forecast interval, and to all future costs. China and Indonesia gas prices are derived from the gas sales agreements specific to each set of projects.


	Oil and Liquids				Natural Gas
						Asia Pacific
Year	WTI Cushing Oklahoma (US$/bbl)	Edmonton Par Price 40 API (C$/bbl)	Western Canadian Select (C$/bbl)	Edmonton C5+ (C$/bbl)	AECO Gas Price (C$/MMBtu)	China Gas Price⁽¹⁾ (US$/Mcf)	Indonesia Gas Price⁽¹⁾ (US$/Mcf)	Inflation Rate (%/year)	Exchange Rate (US$/C$)
2021	47.17	55.76	44.63	59.24	2.78	8.98	7.53	0.0	0.7683
2022	50.17	59.89	48.18	63.19	2.70	9.18	7.32	1.3	0.7650
2023	53.17	63.48	52.10	67.34	2.61	8.96	7.17	2.0	0.7633
2024	54.97	65.76	54.10	69.77	2.65	9.02	7.30	2.0	0.7633
2025	56.07	67.13	55.19	71.18	2.70	9.08	7.44	2.0	0.7633
2026	57.19	68.53	56.29	72.61	2.76	9.17	7.54	2.0	0.7633
2027	58.34	69.95	57.42	74.07	2.81	9.22	7.68	2.0	0.7633
2028	59.50	71.40	58.57	75.56	2.86	9.04	7.84	2.0	0.7633
2029	60.69	72.88	59.74	77.08	2.92	8.93	7.92	2.0	0.7633
2030	61.91	74.34	60.93	78.62	2.98	8.72	8.04	2.0	0.7633
2031	63.15	75.83	62.15	80.19	3.04	8.38	8.10	2.0	0.7633
2032+	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr			2.0	0.7633

(1)	China and Indonesia gas prices are derived from the gas sales agreements specific to each set of projects.

Future Development Costs (after giving effect to the Husky Arrangement)

The following tables outline undiscounted future development costs deducted in the estimation of FNR after giving effect to the Husky Arrangement for the years indicated:


Canada Reserves Category ($ millions)	2021	2022	2023	2024	2025	Remainder	Total
Proved Reserves	612	807	1,321	1,186	1,090	36,540	41,556
Proved plus Probable Reserves	821	1,547	2,011	2,023	1,484	53,516	61,402


China Reserves Category ($ millions)	2021	2022	2023	2024	2025	Remainder	Total
Proved Reserves	–	–	–	–	–	–	–
Proved plus Probable Reserves	–	–	–	–	–	–	–


Indonesia Reserves Category ($ millions)	2021	2022	2023	2024	2025	Remainder	Total
Proved Reserves	13	23	–	–	–	–	36
Proved plus Probable Reserves	13	23	–	–	–	–	36
Company Total Reserves Category ($ millions)	2021	2022	2023	2024	2025	Remainder	Total
Proved Reserves	625	830	1,321	1,186	1,090	36,540	41,592
Proved plus Probable Reserves	834	1,570	2,011	2,023	1,484	53,516	61,438

Cenovus Energy Inc.2020 Annual Information Form

Other Oil and Gas Information

Oil and Gas Properties and Wells

The following tables summarize Cenovus’s interests in producing and non-producing wells, as at December 31, 2020:



	Oil		Gas		Total
Producing Wells	Gross	Net	Gross	Net	Gross	Net
Oil Sands⁽¹⁾	731	731	232	214	963	945
Conventional⁽²⁾	608	361	3,954	2,856	4,562	3,217
Total	1,339	1,092	4,186	3,070	5,525	4,162

(1)	All producing Oil Sands wells are located in Alberta.

(2)	Includes 4,161 gross producing wells (2,889 net producing wells) located in Alberta; 401 gross producing wells (328 net producing wells) located in British Columbia.



	Oil					Gas		Total
Non-Producing Wells⁽¹⁾	Gross		Net	Gross			Net	Gross	Net
Oil Sands⁽²⁾	220		220	213			197	433	417
Conventional⁽³⁾		348	196		875		578	1,223	774
Total	568		416	1,088			775	1,656	1,191

(1)	Non-producing wells include wells which are capable of producing, but which are currently not producing. Non-producing wells do not include other types of wells such as stratigraphic test wells, service wells, or wells that have been abandoned.

(2)	All non-producing Oil Sands wells are located in Alberta.

(3)	Includes 1,152 gross non-producing wells (730 net non-producing wells) located in Alberta; 70 gross non-producing wells (43 net non-producing wells) located in British Columbia; one gross non-producing wells (one net non-producing wells) located in Saskatchewan.

As at December 31, 2020, Cenovus had no material properties with attributed reserves which are capable of producing, but which are not on production.

Exploration and Development Activity

The following tables summarize Cenovus’s gross participation and net interest in wells drilled in 2020⁽¹⁾:


	Oil Sands		Conventional		Total
Wells Drilled	Gross	Net	Gross	Net	Gross	Net
Oil	155	155	-	-	155	155
Gas	-	-	7	6	7	6
Dry & Abandoned	-	-	-	-	-	-
Total Canada	155	155	7	6	162	161

(1)	Oil Sands drilled no gross exploration wells (no net wells) in 2020. No exploration wells were drilled in Conventional in 2020.

During the year ended December 31, 2020, Oil Sands drilled 155 gross stratigraphic test wells (155 net wells). Conventional drilled no stratigraphic test wells.

During the year ended December 31, 2020, no service wells were drilled within Oil Sands and no service wells were drilled in Conventional.

SAGD well pairs are counted as a single oil producing well in the table above. During the year ended December 31, 2020, no well pairs were drilled.

For all types of wells except stratigraphic test wells, the calculation of the number of wells is based on the number of surface locations. For stratigraphic test wells, the calculation is based on the number of bottomhole locations.

Development activities were focused on sustaining bitumen production at Foster Creek and Christina Lake, and the production and de-risking resource potential of the Conventional properties.

Properties With No Attributed Reserves

Cenovus has approximately 5.7 million gross acres (4.6 million net acres) of properties in Canada to which no reserves have been specifically attributed. For lands in which Cenovus holds multiple leases under the same surface area, both gross and net areas have been counted for each lease.

Cenovus has rights to explore, develop, and exploit approximately 472,944 net acres that could potentially expire by December 31, 2021, which relate entirely to Crown and freehold land.

Properties with no attributed reserves include Crown lands where bitumen contingent and prospective resources have been identified and Crown lands where exploration activities to date have not identified potential reserves in commercial quantities. The Corporation regularly reviews the economic

viability of these unproved properties on the basis of product pricing, capital availability and level of related infrastructure development. From this process, some properties are selected for future development activity while others are retained as inactive, sold, swapped or relinquished back to the mineral rights owner.

Additional Information Concerning Abandonment and Reclamation Costs

The estimated total future abandonment and reclamation costs for existing wells, facilities, and infrastructure is based on management’s estimate of costs to remediate, reclaim and abandon wells and facilities having regard to Cenovus’s working interest and the estimated timing of the costs to be incurred in future periods. Cenovus has developed a process to calculate these estimates, which considers

Cenovus Energy Inc.2020 Annual Information Form

applicable regulations, actual and anticipated costs, type and size of the well or facility and the geographic location.

Cenovus has estimated undiscounted and uninflated future abandonment and reclamation costs for its existing upstream assets of approximately $2,508 million (approximately $543 million, discounted at 10 percent) at December 31, 2020, of which the Corporation expects to pay $124 million in the next three financial years.

Cenovus believes that the Husky Arrangement will increase estimated undiscounted and uninflated future abandonment and reclamation costs for its existing Canadian onshore and offshore upstream assets by approximately $3,455 million (approximately $1,553 million discounted at 10 percent), of which the Corporation expects to pay between $400 million and $500 million in the next three financial years. In Asia Pacific, and in accordance with the provisions of the regulations of the People’s Republic of China, Husky had deposited funds into separate accounts restricted to the funding of future abandonment and reclamation costs. As at December 31, 2020, Husky has deposited funds of

$164 million for future abandonment and reclamation costs, which were classified as non-current liabilities.

Of the undiscounted future abandonment and reclamation costs to be incurred over the life of Cenovus’s proved reserves, approximately $6.5 billion ($12.7 billion after giving effect to the Husky Arrangement) has been deducted in estimating the FNR, which represents the Corporation’s total existing estimated abandonment and reclamation costs, plus all forecast estimates of abandonment and reclamation costs attributable to future development activity associated with the reserves.

Tax Horizon

In 2020, the Corporation was subject to relatively insignificant cash taxes. Based on projected future net earnings (after taking into account the Husky Arrangement), the Corporation expects to pay cash taxes of approximately $200 million in 2021. This estimate could vary significantly if underlying assumptions change with respect to commodity prices, capital spending levels and acquisition and disposition transactions.

Costs Incurred


($ millions)	2020
Acquisitions
Unproved	12
Proved	6
Total Acquisitions	18
Exploration Costs	46
Development Costs	459
Total Costs Incurred	523

Forward Contracts

Cenovus may use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange and interest rates. A description of such instruments is provided in the notes to the Corporation’s annual audited Consolidated Financial Statements for the year ended December 31, 2020.

Production Estimates

The following table summarizes the 2021 estimated production of Company Interest Before Royalties reserves for all properties held on December 31, 2020 using forecast prices and costs, all of which will be produced in Canada. These estimates assume certain activities take place, such as the development of undeveloped reserves, and that there are no divestitures.


2021 Estimated Production Forecast Prices and Costs	Proved		Proved plus Probable
Bitumen (bbls/d)⁽¹⁾	392,037	402,414
Light and Medium Oil (bbls/d)	3,428	3,923
NGLs (bbls/d)	17,972	19,939
Conventional Natural Gas (MMcf/d)⁽²⁾	361	407
Total (BOE/d)	473,687	494,173

(1)	Includes Foster Creek production of 157,823 barrels per day for proved and 159,550 barrels per day for proved plus probable, and Christina Lake production of 234,214 barrels per day for proved and 242,864 barrels per day for proved plus probable.

(2)	Includes shale gas that is not material.

Cenovus Energy Inc.2020 Annual Information Form

The following table summarizes the 2021 estimated production of Company Interest Before Royalties reserves for all properties held on December 31, 2020 after giving effect to the Husky Arrangement as though such transaction had occurred on December 31, 2020.


Canada 2021 Estimated Production Forecast Prices and Costs	Proved		Proved plus Probable
Bitumen (bbls/d)⁽¹⁾	526,904	556,717
Light and Medium Oil (bbls/d)	20,066	22,387
NGLs (bbls/d)	26,707	29,240
Conventional Natural Gas (MMcf/d)⁽²⁾	580	637
Total (BOE/d)	670,358	714,479

(1)	Includes heavy crude oil that is not material.

(2)	Includes shale gas that is not material.


China 2021 Estimated Production Forecast Prices and Costs	Proved		Proved plus Probable
Bitumen (bbls/d)	-	-
Light and Medium Oil (bbls/d)	-	-
NGLs (bbls/d)	9,191	9,405
Conventional Natural Gas (MMcf/d)	235	239
Total (BOE/d)	48,307	49,282


Indonesia 2021 Estimated Production Forecast Prices and Costs	Proved		Proved plus Probable
Bitumen (bbls/d)	-	-
Light and Medium Oil (bbls/d)	-	-
NGLs (bbls/d)	2,493	2,514
Conventional Natural Gas (MMcf/d)	38	38
Total (BOE/d)	8,886	8,907


Company Total 2021 Estimated Production Forecast Prices and Costs	Proved		Proved plus Probable
Bitumen (bbls/d)⁽¹⁾	526,904	556,717
Light and Medium Oil (bbls/d)	20,066	22,387
NGLs (bbls/d)	38,391	41,159
Conventional Natural Gas (MMcf/d)⁽²⁾	853	914
Total (BOE/d)	727,551	772,668

(1)	Includes heavy crude oil that is not material.

(2)	Includes shale gas that is not material.

Cenovus Energy Inc.2020 Annual Information Form

Production History and Per-Unit Results


		2020	Q4	Q3		Q2	Q1
Bitumen
Total Production (bbls/d)		381,723	380,693	385,937		373,189	387,036
Foster Creek		163,210	158,068	164,954		166,032	163,820
Christina Lake		218,513	222,625	220,983		207,157	223,216

Sales Price ($/bbl)		28.64	39.02	39.67		12.64	22.35
Royalties ($/bbl)		2.34	3.73	3.54		0.80	1.21
Transportation and blending ($/bbl)		8.70	7.90	7.51		8.56	10.81
Operating expenses ($/bbl)		7.84	8.70	7.53		7.36	7.75
Netback excluding realized risk management⁽¹⁾		9.76	18.69	21.09		(4.08)	2.58
Heavy Oil
Total Production (bbls/d)		2,751	1,966	3,236		2,232	3,576

Sales Price ($/bbl)		31.45	38.85	39.54		15.76	29.09
Royalties ($/bbl)		1.52	2.20	2.61		0.02	1.04
Transportation and blending ($/bbl)		2.02	2.42	2.45		1.18	1.89
Operating expenses ($/bbl)		9.78	8.72	6.91		13.68	10.70
Netback excluding realized risk management⁽¹⁾		18.13	25.51	27.57		0.88	15.46
Light and Medium Oil
Total Production (bbls/d)		4,493	4,263	4,318		4,309	5,086

Sales Price ($/bbl)		42.78	44.80	49.19		27.47	48.54
Royalties ($/bbl)		5.87	4.77	6.06		4.71	7.63
Transportation and blending ($/bbl)		3.20	2.74	4.21		3.13	2.78
Operating expenses ($/bbl)		10.81	10.30	10.85		10.25	11.67
Netback excluding realized risk management⁽¹⁾		22.90	26.99	28.07		9.38	26.46
Natural Gas⁽²⁾
Total Production (MMcf/d)		380	371	360		392	395

Sales Price ($/Mcf)		2.37	2.94	2.34		2.04	2.17
Royalties ($/Mcf)		0.10	0.06	0.28		0.04	0.02
Transportation and blending ($/Mcf)		0.32	0.30	0.32		0.32	0.33
Operating expenses ($/Mcf)		1.47	1.35	1.58		1.46	1.48
Netback excluding realized risk management⁽¹⁾	0.48		1.23		0.16	0.22	0.34
NGLs
Total Production (bbls/d)		19,513	18,358	18,297		20,320	21,104

Sales Price ($/bbl)		22.04	27.76	21.38		18.74	20.75
Royalties ($/bbl)		2.19	5.27	6.45		(1.38)	(0.80)
Transportation and blending ($/bbl)		4.15	3.75	4.66		3.87	4.34
Operating expenses ($/bbl)		9.06	8.61	9.98		9.33	8.40
Netback excluding realized risk management⁽¹⁾		6.64	10.13	0.29		6.92	8.81

(1)

Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netback is defined as gross sales less royalties, transportation and blending and operating expenses divided by sales volumes. Netbacks do not reflect non-cash write-downs (reversals) of product inventory until the inventory is sold. This calculation is consistent with the definition found in the Canadian Oil and Gas Evaluation Handbook. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Netback does not have a standardized meaning as prescribed by IFRS and therefore is considered a non-GAAP measure. As such, it may not be comparable to similar measures presented by other issuers. This measure has been described and presented in this AIF in order to provide shareholders and potential investors with additional information regarding Cenovus’s liquidity and its ability to generate funds to finance its operations, and to comply with the requirements of NI 51‑101. This measure should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. For further information, refer to Cenovus’s most recent MD&A available at cenovus.com. For the reconciliation of the financial components of Netback to the GAAP measure and the sales volumes used in the calculations, see “Netback Reconciliations” in Appendix D.

(2)	Includes shale gas that is not material.

DIVIDENDS

The declaration of dividends is at the sole discretion of Cenovus’s Board and is considered each quarter. On April 2, 2020 the Board announced the temporary suspension of the dividend in response to the low global crude oil price environment resulting in no dividends paid in the second, third and fourth quarters of 2020. The Board has approved a first quarter dividend of $0.0175 per share payable on March 31, 2021 to holders of Common Shares of record as of March 15, 2021. The Board declared a first quarter dividend on the Series 1, 2, 3, 5, and 7 First Preferred Shares, payable on March 31, 2021, in the amount of $8.5 million. Readers should also refer to the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2020 MD&A, which section of the MD&A is incorporated by reference into this AIF, for additional information.

Cenovus paid the following Common Share dividends over the last three years:


Common Share Dividends Paid
($ per share)	Year	Q4	Q3	Q2	Q1
2020	0.0625	-	-	-	0.0625
2019	0.2125	0.0625	0.05	0.05	0.05
2018	0.20	0.05	0.05	0.05	0.05

Cenovus Energy Inc.2020 Annual Information Form

DESCRIPTION OF CAPITAL STRUCTURE

Cenovus is authorized to issue an unlimited number of Common Shares, and First Preferred Shares and Second Preferred Shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding Common Shares. In connection with the Husky Arrangement, Cenovus’s articles were amended effective December 30, 2020 to create the Series 1 First Preferred Shares, the Series 2 First Preferred Shares, the Series 3 First Preferred Shares, the Series 4 First Preferred Shares, the Series 5 First Preferred Shares, the Series 6 First Preferred Shares, the Series 7 First Preferred Shares and the Series 8 First Preferred Shares.

As at December 31, 2020, there were approximately 1,228.9 million Common Shares and no First or Second Preferred Shares outstanding.

As at January 1, 2021, following completion of the Husky Arrangement, there were approximately 2,017.4 million Common Shares, 65.4 million Cenovus Warrants and 36.0 million First Preferred Shares outstanding (consisting of approximately 10.4 million Series 1 First Preferred Shares, 1.6 million Series 2 First Preferred Shares, 10.0 million Series 3 First Preferred Shares, 8.0 million Series 5 First Preferred Shares and 6.0 million Series 7 First Preferred Shares).

Common Shares

The holders of Common Shares are entitled to: (i) receive dividends if, as and when declared by Cenovus’s Board; (ii) receive notice of, to attend, and to vote on the basis of one vote per Common Share held, at all meetings of shareholders; and (iii) participate in any distribution of the Corporation’s assets in the event of liquidation, dissolution or winding up or other distribution of its assets among its shareholders for the purpose of winding up its affairs.

Preferred Shares

Cenovus may issue preferred shares in one or more series. Cenovus’s Board may determine the designation, rights, privileges, restrictions and conditions attached to each series of Preferred Shares before the issue of such series. Holders of Preferred Shares are not entitled to vote at any meeting of shareholders but may be entitled to vote if the Corporation fails to pay dividends on that series of Preferred Shares. The First Preferred Shares are entitled to priority over the Second Preferred Shares and the Common Shares with respect to the payment of dividends and the distribution of assets in the event of any liquidation, dissolution or winding up of Cenovus’s affairs. The aggregate number of Preferred Shares issued by the Corporation may not exceed 20 percent of the aggregate number of the then-outstanding Common Shares.

Series 1 First Preferred Shares

Holders of Series 1 First Preferred Shares are entitled to receive a cumulative quarterly fixed rate dividend, payable on the last day of March, June, September

and December in each year, if, as and when declared by Cenovus’s Board.

For the five-year period commencing March 31, 2016 to, but excluding, March 31, 2021, the dividend rate applicable to the Series 1 First Preferred Shares is set at 2.404%. Every fifth year thereafter, the dividend rate will be reset at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 1.73%.

Holders of Series 1 First Preferred Shares will have the right, at their option, to convert their Series 1 First Preferred Shares into Series 2 First Preferred Shares, subject to certain conditions, on March 31, 2021, and on March 31 every five years thereafter.

Cenovus may, at its option, redeem all or any number of the then-outstanding Series 1 First Preferred Shares, subject to certain conditions, on March 31, 2021 and on March 31 every five years thereafter, by payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Series 2 First Preferred Shares

Holders of Series 2 First Preferred Shares are entitled to receive a cumulative quarterly floating rate dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board.

The dividend rate is reset each quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 1.73%.

Holders of Series 2 First Preferred Shares will have the right, at their option, to convert their Series 2 First Preferred Shares into Series 1 First Preferred Shares, subject to certain conditions, on March 31, 2021, and on March 31 every five years thereafter.

Cenovus may, at its option, redeem all or any number of the then-outstanding Series 2 First Preferred Shares, subject to certain conditions, on (i) March 31, 2021 and on March 31 every five years thereafter, by payment of an amount in cash for each share to be redeemed equal to $25.00 and (ii) any other date that is not a Series 2 First Preferred Share conversion date, by payment of an amount in cash for each share to be redeemed equal to $25.50, plus in each case all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Series 3 First Preferred Shares

Holders of Series 3 First Preferred Shares are entitled to receive a cumulative quarterly fixed rate dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board.

Cenovus Energy Inc.2020 Annual Information Form

For the five-year period commencing December 31, 2019 to, but excluding, December 31, 2024, the dividend rate applicable to the Series 3 First Preferred Shares is set at 4.689%. Every fifth year thereafter, the dividend rate will be reset at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 3.13%.

Holders of Series 3 First Preferred Shares will have the right, at their option, to convert their Series 3 First Preferred Shares into Series 4 First Preferred Shares, subject to certain conditions, on December 31, 2024, and on December 31 every five years thereafter.

Cenovus may, at its option, redeem all or any number of the then-outstanding Series 3 First Preferred Shares, subject to certain conditions, on December 31, 2024 and on December 31 every five years thereafter, by payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Series 4 First Preferred Shares

Holders of Series 4 First Preferred Shares are entitled to receive a cumulative quarterly floating rate dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board.

The dividend rate is reset each quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 3.13%.

Holders of Series 4 First Preferred Shares will have the right, at their option, to convert their Series 4 First Preferred Shares into Series 3 First Preferred Shares, subject to certain conditions, on December 31, 2024 and on December 31 every five years thereafter.

Cenovus may, at its option, redeem all or any number of the then-outstanding Series 4 First Preferred Shares, subject to certain conditions, on (i) December 31, 2024 and on December 31 every five years thereafter, by payment of an amount in cash for each share to be redeemed equal to $25.00 and (ii) any other date that is not a Series 4 First Preferred Share conversion date, by payment of an amount in cash for each share to be redeemed equal to $25.50, plus in each case all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Series 5 First Preferred Shares

Holders of Series 5 First Preferred Shares are entitled to receive a cumulative quarterly fixed rate dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board.

For the five-year period commencing March 31, 2020 to, but excluding, March 31, 2025, the dividend rate applicable to the Series 5 First Preferred Shares is set at 4.591%. Every fifth year thereafter, the dividend

rate will be reset at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 3.57%.

Holders of Series 5 First Preferred Shares will have the right, at their option, to convert their Series 5 First Preferred Shares into Series 6 First Preferred Shares, subject to certain conditions, on March 31, 2025 and on March 31 every five years thereafter.

Cenovus may, at its option, redeem all or any number of the then-outstanding Series 5 First Preferred Shares, subject to certain conditions, on March 31, 2025 and on March 31 every five years thereafter, by payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Series 6 First Preferred Shares

Holders of Series 6 First Preferred Shares are entitled to receive a cumulative quarterly floating rate dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board.

The dividend rate is reset each quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 3.57%.

Holders of Series 6 First Preferred Shares will have the right, at their option, to convert their Series 6 First Preferred Shares into Series 5 First Preferred Shares, subject to certain conditions, on March 31, 2025 and on March 31 every five years thereafter.

Cenovus may, at its option, redeem all or any number of the then-outstanding Series 6 First Preferred Shares, subject to certain conditions, on (i) March 31, 2025 and on March 31 every five years thereafter, by payment of an amount in cash for each share to be redeemed equal to $25.00 and (ii) any other date that is not a Series 6 First Preferred Share conversion date, by payment of an amount in cash for each share to be redeemed equal to $25.50, plus in each case all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Series 7 First Preferred Shares

Holders of Series 7 First Preferred Shares are entitled to receive a cumulative quarterly fixed rate dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board.

For the five-year period commencing June 30, 2020 to, but excluding, June 30, 2025, the dividend rate applicable to the Series 5 First Preferred Shares is set at 3.935%. Every fifth year thereafter, the dividend rate will be reset at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 3.52%.

Holders of Series 7 First Preferred Shares will have the right, at their option, to convert their Series 7 First Preferred Shares into Series 8 First Preferred

Cenovus Energy Inc.2020 Annual Information Form

Shares, subject to certain conditions, on June 30, 2025 and on June 30 every five years thereafter.

Cenovus may, at its option, redeem all or any number of the then-outstanding Series 7 First Preferred Shares, subject to certain conditions, on June 30, 2025 and on June 30 every five years thereafter, by payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Series 8 First Preferred Shares

Holders of Series 8 First Preferred Shares are entitled to receive a cumulative quarterly floating rate dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board.

The dividend rate is reset each quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 3.52%.

Holders of Series 8 First Preferred Shares will have the right, at their option, to convert their Series 8 First Preferred Shares into Series 7 First Preferred Shares, subject to certain conditions, on June 30, 2025 and on June 30 every five years thereafter.

Cenovus may, at its option, redeem all or any number of the then-outstanding Series 8 First Preferred Shares, subject to certain conditions, on (i) June 30, 2025 and on June 30 every five years thereafter, by payment of an amount in cash for each share to be redeemed equal to $25.00 and (ii) any other date that is not a Series 8 First Preferred Share conversion date, by payment of an amount in cash for each share to be redeemed equal to $25.50, plus in each case all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld).

Cenovus Warrants

The Cenovus Warrants were created and issued pursuant to the terms of the warrant indenture dated January 1, 2021 (the “Warrant Indenture”) between Cenovus and Computershare Trust Company of Canada, as warrant agent.

Each whole Cenovus Warrant is exercisable for one Common Share at any time up to 4:30 pm (MST) on January 1, 2026, with an exercise price of $6.54 per Common Share, subject to adjustment in accordance with the terms of the Warrant Indenture. Cenovus Warrants do not have voting or any other rights of

Common Shares. A copy of the Warrant Indenture is filed and available on SEDAR under Cenovus’s profile at sedar.com and on EDGAR at sec.gov.

Shareholder Rights Plan

Cenovus has a shareholder rights plan (the “Shareholder Rights Plan”) which was adopted in 2009 and creates a right that attaches to each issued Common Share. Until the separation time, which typically occurs at the time of an unsolicited take-over bid, whereby a person acquires or attempts to acquire 20 percent or more of Cenovus’s Common Shares, the rights are not separable from the Common Shares, are not exercisable and no separate rights certificates are issued. Each right entitles the holder, other than the 20 percent acquiror, from and after the separation time (unless delayed by Cenovus’s Board) and before certain expiration times, to acquire Common Shares at 50 percent of the market price at the time of exercise. In connection with the Husky Arrangement, the Corporation’s shareholders approved certain amendments to the Shareholder Rights Plan to ensure that an acquisition by any person of Common Shares or of rights to acquire Common Shares pursuant to (i) the Husky Arrangement, (ii) the Cenovus Warrants, including the exercise thereof, or (iii) any exercise of pre-emptive rights, including pursuant to any follow-on offering, under any Husky Arrangement Pre-Emptive Rights Agreement (defined below) does not and will not result in the occurrence of a “Flip-In Event” or the “Separation Time” (as those terms are defined in the Shareholder Rights Plan). The Shareholder Rights Plan was reconfirmed at the 2018 annual meeting of shareholders and must be reconfirmed by the Corporation’s shareholders every three years. Shareholders will be asked to approve certain amendments and reconfirm the plan at the 2021 annual meeting of shareholders.

Dividend Reinvestment Plan

Cenovus has a dividend reinvestment plan which permits holders of Common Shares to automatically reinvest all or any portion of the cash dividends paid on their Common Shares in additional Common Shares. At the discretion of the Corporation, the additional Common Shares may be issued from treasury at the volume weighted average price of the Common Shares (denominated in the currency in which the Common Shares trade on the applicable stock exchange) traded on the Toronto Stock Exchange (“TSX”) during the last five trading days preceding the relevant dividend payment date or purchased on the market.

Cenovus Energy Inc.2020 Annual Information Form

Ratings

The following information relating to Cenovus’s credit ratings is provided as it relates to the Corporation’s financing costs and liquidity. Specifically, credit ratings affect Cenovus’s ability to obtain short-term and long-term financing and the cost of such financing. A reduction in the current rating on Cenovus’s debt by the Corporation’s rating agencies or a negative change in its ratings outlook could adversely affect Cenovus’s cost of financing, its access to sources of liquidity and capital, and potentially obligate it to post incremental collateral in the form of cash, letters of credit or other financial instruments. See the section entitled “Risk Management and Risk Factors” in the Corporation’s annual 2020 MD&A, which section of the MD&A is incorporated by reference into this AIF, for further information.

The following table outlines the current ratings and outlooks of Cenovus’s debt and First Preferred Shares:


	S&P Global Ratings (“S&P”)	Moody’s Investors Service (“Moody’s”)	DBRS Limited (“DBRS”)	Fitch Ratings Inc. (“Fitch”)
Senior Unsecured Long-Term Rating	BBB-	Baa3	BBB	BB+
Outlook/Trend	Stable	Negative	Stable	Positive
Series 1 First Preferred Shares	P-3		Pfd-3
Series 2 First Preferred Shares	P-3		Pfd-3
Series 3 First Preferred Shares	P-3		Pfd-3
Series 5 First Preferred Shares	P-3		Pfd-3
Series 7 First Preferred Shares	P-3		Pfd-3

Credit ratings are intended to provide an independent measure of the credit quality of an issue of securities. The credit ratings assigned by the rating agencies are not recommendations to purchase, hold or sell the securities nor do the ratings comment on market price or suitability for a particular investor. A rating may not remain in effect for any given period of time and may be revised or withdrawn entirely by a rating agency at any time in the future if, in its judgment, circumstances so warrant.

S&P’s long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of BBB- by S&P is within the fourth highest of 10 categories and indicates that the obligation exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation. The addition of a “+” or “-” designation after a rating indicates the relative standing within the major rating categories. An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate term (generally up to two years for investment grade and generally up to one year for speculative grade). Rating outlooks fall into four categories – “Positive”, “Negative”, “Stable” and “Developing”. In determining a rating outlook, consideration is given to any changes in the economic and/or fundamental business conditions. A “Stable” outlook indicates that a rating is not likely to change.

S&P began rating Cenovus’s First Preferred Shares on its Canadian preferred share scale in conjunction with the Husky Arrangement. S&P’s preferred share ratings are a forward-looking opinion about the creditworthiness of an issuer with respect to a specific preferred share obligation. There is a direct correspondence between the ratings assigned on the preferred share scale and S&P’s ratings scale for long-term credit ratings. According to S&P’s ratings system, a P-3 rating on the Canadian preferred share rating scale is equivalent to a BB rating on the long-

term credit rating scale. A rating of BB by S&P is within the fifth highest of 10 categories and indicates that the obligation is less vulnerable to nonpayment than other speculative issues. However, it faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions that could lead to the obligor’s inadequate capacity to meet its financial commitments on the issue.

Moody’s long-term credit ratings are on a rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. A rating of Baa3 by Moody’s is within the fourth highest of nine categories and is assigned to debt securities which are considered to be medium grade and subject to moderate credit risk and as such may possess certain speculative characteristics. The addition of a 1, 2 or 3 modifier after a rating indicates the relative standing within a particular rating category. The modifier 3 indicates that the issue ranks in the lower end of its generic rating category. A Moody’s rating outlook is an opinion regarding the likely rating direction over the medium term. Rating outlooks fall into four categories – “Positive”, “Negative”, “Stable”, and “Developing”. A designation of Negative indicates a higher likelihood of a downward rating change over the medium term.

DBRS’s long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of BBB by DBRS is within the fourth highest of 10 categories and is assigned to debt securities considered to be of adequate credit quality, with acceptable capacity for payment of financial obligations. Entities in the BBB category may be vulnerable to future events. The assignment of a “(high)” or “(low)” modifier within each rating category indicates relative standing within such category. The absence of either modifier indicates the rating is in the middle of the category. Rating trends provide guidance in respect of DBRS’s opinion regarding the outlook for the rating in question, with rating trends falling into one of three categories ‑ “Positive”, “Stable” or “Negative”. The rating trend

Cenovus Energy Inc.2020 Annual Information Form

indicates the direction in which DBRS considers the rating is headed should present circumstances continue, or in some cases, unless challenges are addressed.

DBRS began rating Cenovus’s First Preferred Shares on its Preferred Share Rating Scale in conjunction with the Husky Arrangement. DBRS’s preferred share ratings are meant to give an indication of the risk that an issuer will not fulfill its full obligations in a timely manner, with respect to both dividend and principal commitments. DBRS’s preferred share ratings range from Pdf 1 (highest) to D (lowest). According to DBRS’s ratings system, preferred shares rated Pfd-3 are generally of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adverse conditions present which detract from debt protection.

Fitch’s long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of BB+ is within the fifth highest of 11 categories and is assigned to debt securities that indicate an elevated vulnerability to default risk, particularly in the event of adverse changes in

business or economic conditions over time; however, business or financial flexibility exists that supports the servicing of financial commitments. The modifiers “+” or ”-” may be appended to a rating to denote relative status within major rating categories. A Fitch rating outlook indicates the direction a rating is likely to move over a one to two-year period, with rating outlooks falling into four categories: “Positive”, “Negative”, “Stable” or “Evolving”. Rating outlooks reflect financial or other trends that have not yet reached, or have not been sustained at, a level that would trigger a rating action, but which may do so if such trends continue. Positive or Negative outlooks do not imply that a rating change is inevitable and similarly, ratings with Stable outlooks can be raised or lowered without prior revision of the outlook. Where the fundamental trend has strong, conflicting elements of both positive and negative, the rating outlook may be described as Evolving. A Positive Rating Outlook indicates an upward trend on the rating scale.

Throughout the last four years, Cenovus has made payments to each of S&P, Moody’s, DBRS and Fitch related to the rating of the Corporation’s debt. Additionally, Cenovus has purchased products and services from S&P, Moody’s, DBRS and Fitch.

MARKET FOR SECURITIES

All of the outstanding Common Shares are listed and posted for trading on the TSX and the New York Stock Exchange (“NYSE”) under the symbol CVE. The following table outlines the share price trading range and volume of shares traded by month in 2020:


	TSX							NYSE
	Share Price Trading Range							Share Price Trading Range
	High⁽¹⁾	Low⁽¹⁾		Close⁽¹⁾		Share Volume⁽²⁾		High⁽³⁾	Low⁽³⁾		Close⁽³⁾	Share Volume⁽⁴⁾
	($ per share)						(thousands)	(US$ per share)				(thousands)

January	13.66	11.16	11.52		182,247			10.49	8.48	8.71		79,957
February	12.45	9.41	9.87		195,111			9.39	7.00	7.37		93,778
March	10.07	2.06	2.84		708,848			7.56	1.41	2.02		279,556
April	5.23	2.52	5.05		613,431			3.76	1.78	3.64		258,256
May	6.23	4.49	6.00		316,128			4.52	3.18	4.33		154,383
June	7.80	5.78	6.35		314,857			5.83	4.22	4.67		174,588
July	6.83	5.64	5.96		222,733			5.09	4.14	4.46		123,288
August	7.10	6.01	6.16		143,362			5.34	4.44	4.72		83,900
September	6.39	5.01	5.19		171,061			4.87	3.74	3.89		110,017
October	5.52	4.15	4.36		339,354			4.21	3.15	3.28		194,243
November	7.27	4.32	6.44		287,148			5.57	3.26	4.96		159,416
December	8.21	6.40	7.75		268,814			6.44	4.94	6.04		170,007

(1)	As reported by the TSX.

(2)	As reported by all Canadian marketplaces. Source: Bloomberg.

(3)	As reported by the NYSE.

(4)	As reported by all U.S. marketplaces. Source: Bloomberg.

As of January 6, 2021, the Cenovus Warrants are listed and posted for trading on the TSX under the symbol CVE.WT and on the NYSE under the symbol CVE WS and the Series 1 First Preferred Shares, Series 2 First Preferred Shares, Series 3 First Preferred Shares, Series 5 First Preferred Shares and Series 7 First Preferred Shares are listed and posted for trading on the TSX under the symbols CVE.PR.A, CVE.PR.B, CVE.PR.C, CVE.PR.E and CVE.PR.G, respectively.

Cenovus Energy Inc.2020 Annual Information Form

DIRECTORS AND EXECUTIVE OFFICERS

Directors

The following individuals are the directors of Cenovus:


Name and Residence	Director Since⁽¹⁾	Principal Occupation During the Past Five Years

Keith M. Casey^(3,5) San Antonio, Texas, United States	2020 Independent	Mr. Casey is the Chief Executive Officer of Tatanka Midstream LLC, a private midstream company, since March 2020. Mr. Casey spent five years with Andeavor Corporation (“Andeavor”), formerly known as Tesoro Corporation, an integrated petroleum refining, logistics, and marketing company and served as Executive Vice-President Commercial and Value Chain of Andeavor, from August 2016 to October 2018, Executive Vice-President, Operations of Andeavor from May 2014 to August 2016, and Senior Vice-President, Strategy and Business Development of Andeavor from April 2013 to May 2014. Mr. Casey served as a director of Andeavor Logistics LP, formerly Tesoro Logistics LP, a publicly traded midstream service company, from April 2014 to April 2015 and has served as a director of a number of private midstream companies. Mr. Casey has worked in the refining industry since 1998 and prior to that, he held leadership and operational roles with BP Products North America Inc., Praxair Incorporated and Union Carbide Corp.

Canning K.N. Fok Hong Kong Special Administrative Region	2021 Non-independent	Mr. Fok is Chairman and a Director of Hutchison Telecommunications Hong Kong Holdings Limited, Hutchison Telecommunications (Australia) Limited, Hutchison Port Holdings Management Pte. Limited as the trustee-manager of Hutchison Port Holdings Trust, Power Assets Holdings Limited, HK Electric Investments Manager Limited as the trustee-manager of HK Electric Investments, and HK Electric Investments Limited. Mr. Fok is Deputy Chairman and an Executive Director of CK Infrastructure Holdings Limited, and a Non-Executive Director of TPG Telecom Limited. Mr. Fok is a director of Husky since 2000 and was Co-Chairman of Husky from 2000 to January 1, 2021.

Jane E. Kinney^(2,5) Toronto, Ontario, Canada	2019 Independent	Ms. Kinney is a director of Intact Financial Corporation, a publicly traded insurance company, since May 2019. Ms. Kinney spent 25 years with Deloitte LLP Canada (“Deloitte”) and was admitted to the Deloitte Partnership in 1997. She was appointed Vice Chair, Leadership Team Member of Deloitte in June 2010 and served in this role until her retirement in June 2019. Previous positions with Deloitte include Canadian Managing Partner, Quality & Risk from May 2010 to June 2015, Global Chief Risk Officer from June 2010 to May 2012, and Risk and Regulatory Practice Leader from June 1999 to May 2010. She has also served as a lecturer at the University of Manitoba, Dalhousie University and Saint Mary’s University.

Harold N. Kvisle⁽³^,4) Calgary, Alberta, Canada	2018 Independent	Mr. Kvisle is a director, since May 2009, and Chairman of ARC Resources Ltd., a publicly traded oil and gas company; and a director, since June 2017, and Board Chair of Finning International Inc., a publicly traded heavy equipment company. He served as a director of Cona Resources Ltd. (“Cona”), a publicly traded heavy oil company, from November 2011 to May 2018 when Cona was acquired by Waterous Energy Fund. Mr. Kvisle served as President and Chief Executive Officer of Talisman Energy Inc. (“Talisman”), a publicly traded oil and gas company, from September 2012 to May 2015 and as a director of Talisman from May 2010 to May 2015. From 2001 to 2010, Mr. Kvisle was President and Chief Executive Officer of TransCanada Corporation, now TC Energy Corporation (“TC Energy”), a publicly traded energy infrastructure company. Prior to joining TC Energy in 1999, he was the President of Fletcher Challenge Energy Canada Inc. Mr. Kvisle has worked in the oil and gas industry since 1975 and in the utilities and power industries since 1999.

Cenovus Energy Inc.2020 Annual Information Form


Name and Residence	Director Since⁽¹⁾	Principal Occupation During the Past Five Years

Eva L. Kwok^(3,4) Vancouver, British Columbia, Canada	2021 Independent	Mrs. Kwok is Chairman, a Director and Chief Executive Officer of Amara Holdings Inc., a private investment holding company. Mrs. Kwok is also a Director of CK Life Sciences Int’l., (Holdings) Inc., CK Infrastructure Holdings Limited and the Li Ka Shing (Canada) Foundation and a director of Husky since 2000.

Keith A. MacPhail⁽^4,6⁾ Calgary, Alberta, Canada	2018 Independent	Mr. MacPhail has served as the Chair of Cenovus’s Board since April 2020. He is a director (since July 2003) and served as Chairman of NuVista Energy Ltd., a publicly traded oil and gas company, from July 2003 to May 2020. He also served as a director of Bonavista Energy Corporation, formerly Bonavista Petroleum Ltd. (“Bonavista”), a publicly traded oil and gas company, from November 1997 to August 2020; Chairman from March 2012 to August 2020; Executive Chairman from 2012 to 2018; Chairman and Chief Executive Officer from 2008 to 2012; and as President and Chief Executive Officer from 1997 to 2008. Mr. MacPhail served as a director of Canadian Natural Resources Limited (“CNRL”) from 1993 to 2015. Prior to joining Bonavista in 1997, Mr. MacPhail held progressively more responsible positions with CNRL, with his final position being Executive Vice President and Chief Operating Officer. Previously, he held the position of Production Manager with Poco Petroleums Ltd.

Richard J. Marcogliese⁽²^,5) Alamo, California, United States	2016 Independent	Mr. Marcogliese is the Principal of iRefine, LLC, a privately owned petroleum refining consulting company, since June 2011; and a director of Delek US Holdings, Inc., a publicly traded downstream energy company, since January 2020. He served as Executive Advisor of Pilko & Associates L.P., a private chemical and energy advisory company, from June 2011 to December 2019; Operations Advisor to NTR Partners III LLC, a private investment company from October 2013 to December 2017; and from September 2012 to January 2016 as Operations Advisor to the Chief Executive Officer of Philadelphia Energy Solutions, a partnership between The Carlyle Group and a subsidiary of Energy Transfer Partners, L.P. that operates an oil refining complex on the U.S. Eastern seaboard.

Claude Mongeau^(2,5) Montreal, Quebec, Canada	2016 Independent	Mr. Mongeau is a director of The Toronto-Dominion Bank, an international financial institution, since March 2015; and a director of Norfolk Southern Corporation, a publicly traded North American rail transportation provider, since September 2019. He served as a director of TELUS Corporation, a publicly traded telecommunications company, from May 2017 to August 2019. He also served as a director of Canadian National Railway Company, a publicly traded railroad and transportation company, from October 2009 to July 2016 and as President and Chief Executive Officer from January 2010 to June 2016. During his tenure with Canadian National Railway Company, he also served as Executive Vice-President and Chief Financial Officer from October 2000 until December 2009 and held various increasingly senior positions from the time he joined in 1994. Mr. Mongeau also served as a director of SNC‑Lavalin Group Inc. from August 2003 to May 2015.

Alexander J. Pourbaix⁽⁷⁾ Calgary, Alberta, Canada	2017 Non-independent	Mr. Pourbaix has served as President & Chief Executive Officer of Cenovus since November 6, 2017 and is a director of Canadian Utilities Limited, a publicly traded diversified global energy infrastructure corporation, since November 2019. He served as a director of Trican Well Service Ltd., a publicly traded oilfield services provider, from May 2012 to December 2019. Mr. Pourbaix served as Chief Operating Officer of TC Energy from October 2015 to April 2017. During his tenure with TC Energy, he also served as Executive Vice-President and President, Development from March 2014 to September 2015 and President, Energy & Oil Pipelines from July 2010 to February 2014, and held various increasingly senior positions from the time he joined TC Energy in 1994.

Cenovus Energy Inc.2020 Annual Information Form


Name and Residence	Director Since⁽¹⁾	Principal Occupation During the Past Five Years

Wayne E. Shaw⁽^2,5⁾ Toronto, Ontario, Canada	2021 Independent	Mr. Shaw is the President of G.E. Shaw Investments Limited, a private investment holding company. Prior to his retirement in April 2013, he was a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors, Toronto, Ontario. Mr. Shaw is also a director of the Li Ka Shing (Canada) Foundation and a director of Husky since 2000.

Frank J. Sixt⁽⁴⁾ Hong Kong Special Administrative Region	2021 Non-independent	Mr. Sixt is an Executive Director, Group Finance Director and Deputy Managing Director of CK Hutchison Holdings Limited. Mr. Sixt is also the Non-Executive Chairman of TOM Group Limited, an Executive Director of CK Infrastructure Holdings Limited, a Non-Executive Director of TPG Telecom Limited, a Director of Hutchison Telecommunications (Australia) Limited (HTAL) and an Alternate Director to a Director of HTAL, HK Electric Investments Manager Limited as the trustee-manager of HK Electric Investments and HK Electric Investments Limited. Mr. Sixt is also a Director of the Li Ka Shing (Canada) Foundation and a director of Husky since 2000.

Rhonda I. Zygocki^(3,4) Friday Harbor, Washington, United States	2016 Independent	Ms. Zygocki served as Executive Vice President, Policy and Planning of Chevron Corporation (“Chevron”), a publicly traded integrated energy company, from March 2011 until her retirement in February 2015 and prior thereto, during her 34 years with Chevron, she held a number of senior management and executive leadership positions in international operations, public affairs, strategic planning, policy, government affairs and health, environment and safety.

(1)	Directors were elected or appointed to Cenovus’s Board as follows:

•

Ms. Zygocki and Mr. Marcogliese were first elected as directors of Cenovus’s Board at the annual meeting of shareholders held on April 27, 2016;

•

Mr. Mongeau was appointed as a director of Cenovus’s Board as of December 1, 2016;

•

Mr. Pourbaix was appointed as President and Chief Executive Officer and a director of Cenovus’s Board as of November 6, 2017;

•

Messrs. Kvisle and MacPhail were first elected as directors of Cenovus’s Board at the annual meeting of shareholders held on April 25, 2018;

•

Ms. Kinney was first elected as a director of Cenovus’s Board at the annual meeting of shareholders held on April 24, 2019;

•

Mr. Casey was first elected as a director of Cenovus’s Board as of April 29, 2020; and

•

Mrs. Kwok, and Messrs. Fok, Shaw and Sixt were appointed as directors of Cenovus’s Board as of January 1, 2021.

The term of each of the directors is from the date of the meeting at which he or she is elected or appointed until the next annual meeting of shareholders or until a successor is elected or appointed.

(2)	Member of the Audit Committee.

(3)	Member of the Human Resources and Compensation Committee.

(4)	Member of the Nominating and Corporate Governance Committee.

(5)	Member of the Safety, Environment, Responsibility and Reserves Committee.

(6)

Ex officio, by standing invitation, non‑voting member of the Audit Committee, the Human Resources and Compensation Committee and the Safety, Environment, Responsibility and Reserves Committee. As an ex officio non‑voting member, Mr. MacPhail attends as his schedule permits and may vote when necessary to achieve a quorum.

(7)	As an officer and a non‑independent director, Mr. Pourbaix is not a member of any of the committees of Cenovus’s Board.

As at December 31, 2020, Susan F. Dabarno, Steven F. Leer and M. George Lewis were directors of Cenovus. Each of Ms. Dabarno and Messrs. Leer and Lewis were members of the Nominating and Corporate Governance Committee. Messrs. Leer and Lewis were also members of the Human Resources and Compensation Committee and Ms. Dabarno was also a member of the Audit Committee. Each of Ms. Dabarno and Messrs. Leer and Lewis resigned from Cenovus’s Board on January 1, 2021, prior to closing of the Husky Arrangement.

Executive Officers

The following individuals are the executive officers of Cenovus:


Name and Residence	Office Held and Principal Occupation During the Past Five Years

Alexander J. Pourbaix Calgary, Alberta, Canada	President & Chief Executive Officer Mr. Pourbaix’s biographical information is included under “Directors”.

Jeffrey R. Hart Calgary, Alberta, Canada	Executive Vice-President & Chief Financial Officer Mr. Hart was appointed Executive Vice-President & Chief Financial Officer of Cenovus effective January 1, 2021. From November 2018 to January 1, 2021, Mr. Hart was Chief Financial Officer of Husky; from April 2018 to November 2019, Mr. Hart was Acting Chief Financial Officer of Husky; and from February 2015 to April 2018, Mr. Hart was Vice President, Controller of Husky Oil Operations Limited.

Cenovus Energy Inc.2020 Annual Information Form


Name and Residence	Office Held and Principal Occupation During the Past Five Years
Jonathan M. McKenzie Calgary, Alberta, Canada	Executive Vice-President & Chief Operating Officer Mr. McKenzie was appointed Executive Vice-President & Chief Operating Officer of Cenovus effective January 1, 2021. From May 2018 to January 1, 2021, Mr. McKenzie was Executive Vice-President and Chief Financial Officer of Cenovus. From April 2015 to April 2018, Mr. McKenzie was Chief Financial Officer of Husky. From April 2011 to April 2015, Mr. McKenzie was Chief Financial Officer and Chief Commercial Officer of Irving Oil Ltd.; and from March 2009 to May 2011, Mr. McKenzie was Vice-President and Controller of Suncor Energy Inc.

Keith A. Chiasson Calgary, Alberta, Canada	Executive Vice-President, Downstream Mr. Chiasson was appointed Executive Vice-President, Downstream of Cenovus on March 1, 2019. From December 2017 to February 2019, Mr. Chiasson was Senior Vice-President, Downstream of Cenovus; from May 2017 to December 2017, Mr. Chiasson was Vice-President, Oil Sands Production Operations of Cenovus; and from July 2016 to May 2017, Mr. Chiasson was Vice-President, Operations of Cenovus. From April 2016 to July 2016, Mr. Chiasson was Kearl Operations Manager at Imperial Oil Resources; from September 2013 to April 2016, Mr. Chiasson was U.S. Operations Manager for ExxonMobil; and from January 2012 to September 2013, Mr. Chiasson was Planning and Business Analysis Manager for ExxonMobil Production Company.

P. Andrew Dahlin Calgary, Alberta, Canada	Executive Vice-President, Safety & Operations Technical Services Mr. Dahlin was appointed Executive Vice-President, Safety & Operations Technical Services of Cenovus effective January 1, 2021. From November 2020 to January 1, 2021, Mr. Dahlin was Executive Vice-President, Downstream of Husky; from May 2020 to November 2020, Mr. Dahlin was Executive Vice President, Onshore Upstream of Husky; from May 2018 to May 2020, Mr. Dahlin was Senior Vice President, Heavy Oil & Oil Sands of Husky Oil Operations Limited; from June 2017 to May 2018, Mr. Dahlin was Senior Vice President, Heavy Oil of Husky Oil Operations Limited; and from April 2012 to May 2017, Mr. Dahlin was Vice President, Upstream of Husky Oil Operations Limited.

Norrie C. Ramsay Calgary, Alberta, Canada	Executive Vice-President, Upstream – Thermal, Major Projects & Offshore Dr. Ramsay was appointed Executive Vice-President, Upstream – Thermal, Major Projects & Offshore of Cenovus effective January 1, 2021. From January 2020 to January 1, 2021, Dr. Ramsay was Executive Vice-President, Upstream of Cenovus; from December 2019 to January 2020, Dr. Ramsay was Executive Vice-President of Cenovus. From June 2019 to November 2019, Dr. Ramsay was Senior Vice-President, Projects at TC Energy; from August 2014 to May 2019, Dr. Ramsay was Senior Vice-President, Technical Centre & Projects at TC Energy; and from May 2010 to July 2014, Dr. Ramsay was Global Vice-President, Projects & Engineering at Talisman Energy Inc.

Karamjit S. Sandhar Calgary, Alberta, Canada	Executive Vice-President, Strategy & Corporate Development Mr. Sandhar was appointed Executive Vice-President, Strategy & Corporate Development of Cenovus effective January 1, 2021. From January 2020 to January 1, 2021, Mr. Sandhar was Senior Vice-President, Conventional of Cenovus, and Senior Vice-President, Deep Basin of Cenovus prior to the Deep Basin segment being renamed the Conventional segment in the first quarter of 2020. From December 2017 to December 2019, Mr. Sandhar was Senior Vice-President, Strategy & Corporate Development of Cenovus; from July 2016 until December 2017, Mr. Sandhar was Vice-President, Investor Relations & Corporate Development of Cenovus; from May 2016 to July 2016, Mr. Sandhar was Vice‑President, Investor Relations of Cenovus; from May 2015 to May 2016, Mr. Sandhar was Director, Investor Relations of Cenovus; and from April 2013 to May 2015 Mr. Sandhar was Principal, Portfolio Management of Cenovus.

Cenovus Energy Inc.2020 Annual Information Form


Name and Residence	Office Held and Principal Occupation During the Past Five Years

Sarah J. Walters Calgary, Alberta, Canada	Executive Vice-President, Corporate Services Mrs. Walters was appointed Executive Vice-President, Corporate Services of Cenovus effective January 1, 2021. From December 2017 to January 1, 2021, Mrs. Walters was Senior Vice-President, Corporate Services of Cenovus; from January 2017 until December 2017, Mrs. Walters was Vice-President, Human Resources of Cenovus; from September 2015 to December 2016, Mrs. Walters was Vice-President, Organization & People of Cenovus; from March 2014 to August 2015, Mrs. Walters was Vice-President HR Business Partners & Organizational Design of Cenovus; from July 2013 to February 2014, Mrs. Walters was Vice‑President, HR Business Partners of Cenovus; and from March 2013 to July 2013, Mrs. Walters was Vice-President, HR Advisory of Cenovus. Prior to joining Cenovus in March 2013, Mrs. Walters was Vice-President HR, International Operations West at Talisman Energy Inc.

J. Drew Zieglgansberger Calgary, Alberta, Canada	Executive Vice-President, Upstream – Conventional & Integration Mr. Zieglgansberger was appointed Executive Vice-President, Upstream – Conventional & Integration of Cenovus effective January 1, 2021. From January 2020 to January 1, 2021, Mr. Zieglgansberger was Executive Vice-President, Strategy & Corporate Development of Cenovus; from January 2018 to December 2019, Mr. Zieglgansberger was Executive Vice-President, Upstream of Cenovus; from April 2017 to January 2018, Mr. Zieglgansberger was Executive Vice-President, Deep Basin of Cenovus; from September 2015 to April 2017, Mr. Zieglgansberger was Executive Vice-President, Oil Sands Manufacturing of Cenovus; from June 2015 to August 2015, Mr. Zieglgansberger was Executive Vice-President, Operations Shared Services of Cenovus; from June 2012 to May 2015, Mr. Zieglgansberger was Senior Vice-President, Operations Shared Services of Cenovus; from January 2012 to May 2012, Mr. Zieglgansberger was Senior Vice-President, Regulatory, Local Community & Military of Cenovus; and from December 2010 to January 2012, Mr. Zieglgansberger was Senior Vice-President, Christina Lake of Cenovus.

Rhona M. DelFrari Calgary, Alberta, Canada	Chief Sustainability Officer & Senior Vice-President, Stakeholder Engagement Ms. DelFrari was appointed Chief Sustainability Officer & Senior Vice-President, Stakeholder Engagement of Cenovus effective January 1, 2021. From June 2017 to January 1, 2021, Ms. DelFrari was Vice-President, Sustainability & Engagement. From January 2012 to June 2017, Ms. DelFrari held various positions within the communications, external relations and strategy portfolios.

Gary F. Molnar Calgary, Alberta, Canada	Senior Vice-President Legal, General Counsel & Corporate Secretary Mr. Molnar was appointed Senior Vice-President Legal, General Counsel & Corporate Secretary of Cenovus effective January 1, 2021. From December 2015 to January 1, 2021, Mr. Molnar was Vice-President, Legal, Assistant General Counsel & Corporate Secretary; from March 2011 to December 2015, Mr. Molnar was Vice-President, Legal & Assistant Corporate Secretary; and from November 2009 to March 2011, Mr. Molnar was Vice-President & Assistant Corporate Secretary of Cenovus.

As at December 31, 2020, Harbir S. Chhina and Alan C. Reid were executive officers of Cenovus. Each of Messrs. Chhina and Reid resigned from his respective office on January 1, 2021, following closing of the Husky Arrangement.

As of December 31, 2020, all of Cenovus’s directors and executive officers, as a group, beneficially owned or exercised control or direction over, directly or indirectly, 2,817,469 Common Shares or approximately 0.23 percent of the number of Common Shares that were outstanding as of such date. As of February 1, 2021, all of Cenovus’s directors and executive officers, as a group, beneficially owned or exercised control or direction over, directly or indirectly, 2,507,805 Common Shares or approximately 0.12 percent of the number of Common Shares that were outstanding as of such date.

Investors should be aware that some of Cenovus’s directors and officers are directors and officers of other private and public companies. Some of these private and public companies may, from time to time, be involved in business transactions or banking relationships which may create situations in which conflicts might arise. Any such conflicts shall be resolved in accordance with the procedures and requirements of the relevant provisions of the CBCA, including the duty of such directors and officers to act honestly and in good faith with a view to the best interests of Cenovus.

Cenovus Energy Inc.2020 Annual Information Form

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

To the Corporation’s knowledge, none of its current directors or executive officers are, as at the date of this AIF, or have been, within 10 years prior to the date of this AIF, a director, chief executive officer or chief financial officer of any company that:

(a)

was subject to a cease trade order, an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, that was in effect for a period of more than 30 consecutive days (each, an “Order”) and that was issued while that director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or

(b)

was subject to an Order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.

To the Corporation’s knowledge, none of its directors or executive officers:

(a)	is, as at the date of this AIF, or has been within 10 years prior to the date of this AIF, a director or executive officer of any company that, while that person was acting in that capacity, or within a

year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or

(b)

has, within 10 years prior to the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director or executive officer.

To the Corporation’s knowledge, none of its directors or executive officers has been subject to:

(a)	any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or

(b)	any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

AUDIT COMMITTEE

The Audit Committee mandate is included as Appendix C to this AIF.

Composition of the Audit Committee

The Audit Committee consists of four members, each

of whom is independent and financially literate in accordance with National Instrument 52-110 Audit Committees. The Board determined that each of the following members of Cenovus’s Audit Committee qualifies as an “audit committee financial expert”, as that term is defined under U.S. securities legislation: Claude Mongeau and Jane E. Kinney. The education and experience of each of the members of the Audit Committee relevant to the performance of the responsibilities as an Audit Committee member is outlined below.

As at December 31, 2020, the Audit Committee consisted of Claude Mongeau, Jane E. Kinney, Susan F. Dabarno and Harold N. Kvisle. Concurrently with the completion of the Husky Arrangement, Cenovus’s Board, and each committee of the Board, were reconstituted, resulting in the current Audit Committee membership.

Claude Mongeau (Audit Committee Chair)

Mr. Mongeau holds a Masters of Business Administration degree from McGill University and has received honorary doctorate degrees from St. Mary’s and Windsor University. He is a director of The Toronto-Dominion Bank, an international financial institution, and Norfolk Southern Corporation, a publicly traded rail transportation provider. He served

as a director of TELUS Corporation, a publicly traded telecommunications company, from May 2017 to August 2019. He served as a director of Canadian National Railway Company, a publicly traded railroad and transportation company, from October 2009 to July 2016 and as President and Chief Executive Officer from January 2010 to June 2016. During his tenure with Canadian National Railway Company, he served as Executive Vice-President and Chief Financial Officer from October 2000 until December 2009 and from the time he joined Canadian National Railway Company in 1994 he held the titles of Senior Vice-President and Chief Financial Officer, Vice-President, Strategic and Financial Planning and Assistant Vice-President, Corporate Development.

Jane E. Kinney

Ms. Kinney is a chartered professional accountant, a Fellow of the Chartered Professional Accountants of Ontario (FCPA) and holds a Mathematics degree from the University of Waterloo. She is a seasoned business leader with over 30 years of experience in providing advisory services to global financial institutions and has extensive experience in enterprise risk management, regulatory compliance, cyber and IT risk management, digital transformation and stakeholder relations.

Cenovus Energy Inc.2020 Annual Information Form

Ms. Kinney is a director and Chair of the Audit Committee of Intact Financial Corporation, a publicly traded insurance company. She spent 25 years with Deloitte and was admitted to the Deloitte Partnership in 1997. She was appointed Vice Chair, Leadership Team Member of Deloitte in June 2010 and served in this role until her retirement in June 2019. Previous positions with Deloitte include Canadian Managing Partner, Quality & Risk from May 2010 to June 2015, Global Chief Risk Officer from June 2010 to May 2012, and Risk and Regulatory Practice Leader from June 1999 to May 2010.

Richard J. Marcogliese

Mr. Marcogliese holds a Bachelor of Engineering degree in Chemical Engineering from the New York University School of Engineering and Science. He is the Principal of iRefine, LLC, a privately owned petroleum refining consulting company, and a director of Delek US Holdings, Inc., a publicly traded downstream energy company. He served as Executive Advisor of Pilko & Associates L.P., a private chemical and energy advisory company, from June 2011 to December 2019; Operations Advisor to NTR Partners III LLC, a private investment company from October 2013 to December 2017; and from September 2012 to January 2016 as Operations Advisor to the Chief Executive Officer of Philadelphia Energy Solutions, a partnership between The Carlyle Group and a subsidiary of Energy Transfer Partners, L.P. that operates an oil refining complex on the U.S. Eastern seaboard.

Wayne E. Shaw

Mr. Shaw holds a Bachelor of Arts degree and a Bachelor of Laws degree from the University of Alberta. He is a member of the Law Society of Ontario. He is the President of G.E. Shaw Investments Limited, a private investment holding company. Prior to his retirement in 2013, Mr. Shaw was a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors, Toronto, Ontario.

The above list does not include Keith A. MacPhail who is, by standing invitation as Chair of the Board, an ex officio member of Cenovus’s Audit Committee.

Pre-Approval Policies and Procedures

Cenovus has adopted policies and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by PricewaterhouseCoopers LLP. The Audit Committee has established a budget for the provision of a specified list of audit and permitted non-audit services that the Audit Committee believes to be typical, recurring or otherwise likely to be provided by PricewaterhouseCoopers LLP, the Corporation’s auditor. Subject to the Audit Committee’s discretion, the budget generally covers the period between the adoption of the budget and the next meeting of the Audit Committee. The list of permitted services is sufficiently detailed to ensure that: (i) the Audit Committee knows precisely what services it is being asked to pre-approve; and (ii) it is not necessary for any member of management to make a judgment as to whether a proposed service fits within the pre-approved services.

Subject to the following paragraph, the Audit Committee has delegated authority to the Chair of the Audit Committee (or if the Chair is unavailable, any other member of the Audit Committee) to pre-approve the provision of permitted services by PricewaterhouseCoopers LLP which are not otherwise pre-approved by the Audit Committee, including the fees and terms of the proposed services (“Delegated Authority”). Any required determination about the Chair’s unavailability will be required to be made by the good faith judgment of the applicable other member(s) of the Audit Committee after considering all facts and circumstances deemed by such member(s) to be relevant. All pre-approvals granted pursuant to Delegated Authority must be presented by the member(s) who granted the pre-approvals to the full Audit Committee at its next meeting.

The fees payable in connection with any particular service to be provided by PricewaterhouseCoopers LLP that have been pre-approved pursuant to Delegated Authority: (i) may not exceed $200,000, in the case of pre-approvals granted by the Chair of the Audit Committee; and (ii) may not exceed $50,000, in the case of pre-approvals granted by any other member of the Audit Committee.

All proposed services or the fees payable in connection with such services that have not already been pre-approved must be pre-approved by either the Audit Committee or pursuant to Delegated Authority. Prohibited services may not be pre-approved by the Audit Committee or pursuant to Delegated Authority.

Cenovus Energy Inc.2020 Annual Information Form

External Auditor Service Fees

The following table provides information about the fees billed to Cenovus for professional services rendered by PricewaterhouseCoopers LLP in the years ended December 31, 2020 and 2019:


($ thousands)	2020		2019
Audit Fees⁽¹⁾	2,598	2,938
Audit-Related Fees⁽²⁾	382	226
Tax Fees⁽³⁾	128	2
All Other Fees⁽⁴⁾	46	284
Total	3,154	3,450

(1)	Audit Fees consist of the aggregate fees billed for the audit of the Corporation’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements.

(2)

Audit-Related Fees consist of the aggregate fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the Corporation’s financial statements and are not reported as Audit Fees. The services provided in this category included audit-related services in relation to Cenovus’s prospectuses and participation fees levied by the Canadian Public Accountability Board. Fees related to the acquisition or divestiture of assets are also included in Audit-Related Fees.

During the year ended December 31, 2020, there were no legal proceedings to which Cenovus is or was a party, or that any of its property is or was the subject of, which involves a claim for damages in an amount, exclusive of interest and costs, that exceeds 10 percent of Cenovus’s current assets and it is not aware of any such legal proceedings that are contemplated.

During the year ended December 31, 2020, there were no penalties or sanctions imposed against Cenovus by a court relating to securities legislation or by a securities regulatory authority, nor have there been any other penalties or sanctions imposed by a court or regulatory body against the Corporation that would likely be considered important to a reasonable investor in making an investment decision, and it has not entered into any settlement agreements before a court relating to securities legislation or with a securities regulatory authority.

None of the Corporation’s directors or executive officers or any person or company that beneficially owns, or controls or directs, directly or indirectly, more than 10 percent of any class or series of Cenovus’s outstanding voting securities, or any associate or affiliate of any of the foregoing persons or companies, in each case, as at the date of this AIF, has or has had any material interest, direct or indirect, in any past transaction within the three most recently completed financial years or any proposed transaction that has materially affected or is reasonably expected to materially affect Cenovus.

Other than as set forth below, during the year ended December 31, 2020, Cenovus has not entered into any contracts, nor are there any contracts still in effect, that are material to the business, other than contracts entered into in the ordinary course of business.

On March 29, 2017, Cenovus entered into a purchase and sale agreement (the “COP Acquisition Agreement”) with ConocoPhillips to acquire: (i) ConocoPhillips’ 50 percent interest (the “FCCL Interest”) (being the remaining 50 percent interest that Cenovus did not already own) in FCCL Partnership, the owner of the Foster Creek, Christina Lake and Narrows Lake oil sands projects in northeast Alberta, and (ii) the majority of ConocoPhillips’ western Canadian conventional assets, including ConocoPhillips’ exploration and production assets and related infrastructure and agreements in the Elmworth-Wapiti, Kaybob-Edson and Clearwater operating areas and other operating areas, and all of ConocoPhillips’ interest in petroleum and natural gas rights and oil sands leases within a certain area of mutual interest northwest of Foster Creek (the “Deep Basin Assets”). The FCCL Interest and the Deep Basin Assets

were acquired by Cenovus for total consideration of $17.6 billion, comprised of $15.0 billion cash, and 208 million Common Shares.

At closing of the COP Acquisition Agreement, Cenovus and ConocoPhillips entered into a contingent payment agreement (the “COP Contingent Payment Agreement”), pursuant to which Cenovus agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date of the COP Acquisition Agreement for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52 per barrel. There are no maximum payment terms. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment.

Also, at closing of the COP Acquisition Agreement, Cenovus and ConocoPhillips entered into a registration rights agreement (“COP Registration Rights Agreement”) and an investor agreement (“COP Investor Agreement”), which, among other things, restricted ConocoPhillips from selling or hedging its Common Shares until November 17, 2017. In addition, the COP Registration Rights Agreement provides ConocoPhillips with certain rights to facilitate the sale of its Common Shares, including the right to require Cenovus to qualify the distribution of the Common Shares held by ConocoPhillips and the right to piggy-back on an offering of Common Shares by Cenovus. The COP Investor Agreement places certain restrictions on ConocoPhillips, including from nominating new members to Cenovus’s board of directors and by requiring ConocoPhillips to vote its Common Shares in accordance with management recommendations or abstain from voting. The COP Registration Rights Agreement and the COP Investor Agreement will terminate when ConocoPhillips owns 3.5 percent or less of the then-outstanding Common Shares.

A copy of the COP Acquisition Agreement, which includes the forms of the COP Contingent Payment Agreement, COP Registration Rights Agreement and COP Investor Agreement, in redacted form, was filed on SEDAR on April 5, 2017, and a copy of the amendment to the COP Acquisition Agreement was filed on SEDAR on May 17, 2017, each of which may be viewed under Cenovus’s profile at sedar.com and on EDGAR at sec.gov.

On October 24, 2020, each of Hutchison Whampoa Europe Investments S.à r.l. and L.F. Investments S.à r.l. entered into a separate standstill agreement with Cenovus (each, a “Husky Arrangement Standstill Agreement”), with effect as of January 1, 2021. Each Husky Arrangement Standstill Agreement sets forth certain restrictions and obligations in connection with such shareholder’s shareholdings in Cenovus following completion of the transactions contemplated by the Husky Arrangement, including but not limited to the following:

The Husky Arrangement Standstill Agreements terminate on the earlier of January 1, 2026, the date on which either of the Husky Arrangement Standstill Agreement is terminated by the written agreement of the parties, provided that the Transfer Restrictions have been complied with under each Husky Arrangement Standstill Agreement, the date on which Hutchison Whampoa Europe Investments S.à r.l. and L.F. Investments S.à r.l., together with their affiliates, cease to beneficially own, or control or direct, in aggregate, at least 10 percent of the then-outstanding Common Shares, or any Qualified Individual (as defined in the Husky Arrangement Standstill Agreements) duly nominated in accordance with the Husky Arrangement Standstill Agreements is not appointed to the Board in accordance with the Husky Arrangement Standstill Agreements.

Copies of the Husky Arrangement Standstill Agreements were filed on SEDAR on November 3, 2020 and may be viewed under Cenovus’s profile at sedar.com and on EDGAR at sec.gov.

On January 1, 2021, Cenovus and each of Hutchison Whampoa Europe Investments S.à r.l. and L.F. Investments S.à r.l. entered into a registration rights agreement (each, a “Husky Arrangement Registration Rights Agreement”) which provides such shareholders with certain rights to facilitate the sale of their Common Shares, including the right to require Cenovus to qualify the distribution of the Common Shares held by such shareholders and the right to piggy-back on an offering of Common Shares by Cenovus. These rights are available to such shareholders for a term beginning on July 1, 2022 and ceasing on the earlier of January 1, 2026, the date on which the Husky Arrangement Registration Rights Agreement is terminated by agreement of the parties, the date the holder ceases to, directly or indirectly, beneficially own in aggregate more than 5 percent of the then-outstanding Common Shares, or the date on which the Husky Arrangement Standstill Agreements are terminated.

Copies of the Husky Arrangement Registration Rights Agreements were filed on SEDAR on January 4, 2021 and may be viewed under Cenovus’s profile at sedar.com and on EDGAR at sec.gov.

On January 1, 2021, Cenovus and each of Hutchison Whampoa Europe Investments S.à r.l. and L.F. Investments S.à r.l. entered into a pre-emptive rights agreement (each, a “Husky Arrangement Pre-Emptive Rights Agreement”) which provides such shareholders with certain rights to allow such shareholder to maintain its pro rata share of the then-outstanding Common Shares. These rights are available to such shareholders for a term beginning on January 1, 2021 and ceasing on the earlier of January 1, 2026, the date on which the Husky Arrangement Pre-Emptive Rights Agreement is terminated by agreement of the parties, the date the shareholder ceases to, directly or indirectly, beneficially own in aggregate more than 5 percent of the then-outstanding Common Shares, or the date on which the Husky Arrangement Standstill Agreements are terminated.

Copies of the Husky Arrangement Pre-Emptive Rights Agreements were filed on SEDAR on January 4, 2021 and may be viewed under Cenovus’s profile at sedar.com and on EDGAR at sec.gov.

At closing of the Husky Arrangement, the Cenovus Warrants were created and issued pursuant to the terms of the Warrant Indenture entered into with Computershare Trust Company of Canada, as warrant agent, which governs the Cenovus Warrants. The Warrant Indenture provides for customary adjustments to the number of Common Shares issuable upon exercise of the Cenovus Warrants and/or to the exercise price in effect for the Cenovus Warrants, and for adjustment in the class and/or number of securities issuable upon exercise of the Cenovus Warrants and/or to the exercise price for the Cenovus Warrants, upon the occurrence of certain events. Cenovus also covenants in the Warrant Indenture that, so long as any Cenovus Warrant remains outstanding, Cenovus will give notice to holders of Cenovus Warrants of certain stated events, including events that would result in an adjustment to the exercise price for the Cenovus Warrants or the number of Common Shares issuable upon exercise of the Cenovus Warrants, at least 10 business days prior to the record date of such event.

A copy of the Warrant Indenture was filed on SEDAR on January 4, 2021 and may be viewed under Cenovus’s profile at sedar.com and on EDGAR at sec.gov.

The Corporation’s independent auditors are PricewaterhouseCoopers LLP, Chartered Professional Accountants, who have issued an independent auditor’s report dated February 8, 2021 in respect of Cenovus’s Consolidated Financial Statements which comprise the Consolidated Balance Sheets as at December 31, 2020 and December 31, 2019 and the Consolidated Statements of Earnings (Loss), Comprehensive Income, Shareholders’ Equity and Cash Flows for the years ended December 31, 2020, 2019, and 2018 and Cenovus’s internal control over financial reporting as at December 31, 2020. PricewaterhouseCoopers LLP has advised that they are independent with respect to Cenovus within the meaning of the Code of Professional Conduct of the Chartered Professional Accountants of Alberta and the rules of the SEC.

Information relating to Cenovus’s reserves in this AIF has been calculated by McDaniel and GLJ as independent qualified reserves evaluators. The partners, employees or consultants of each of McDaniel and GLJ, in each case, as a group own beneficially, directly or indirectly, less than one percent of any class of the Corporation’s outstanding securities.

Additional information relating to Cenovus is available on SEDAR at sedar.com and EDGAR at sec.gov. Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of Cenovus’s securities, and securities authorized for issuance under its equity-based compensation plans, is included in the Corporation’s management information circular for its most recent annual meeting of shareholders.

Additional financial information concerning Cenovus as at December 31, 2020 can be found in Cenovus’s audited annual Consolidated Financial Statements and MD&A for the year ended December 31, 2020.

As a Canadian corporation listed on the NYSE, Cenovus is not required to comply with most of the NYSE’s corporate governance standards, and instead may comply with Canadian corporate governance practices. However, the Corporation is required to disclose the significant differences between its corporate governance practices and the requirements applicable to U.S. domestic companies listed on the NYSE. Except as summarized on Cenovus’s website at cenovus.com, it is in compliance with the NYSE corporate governance standards in all significant respects.

Unless otherwise specified, all dollar amounts are expressed in Canadian dollars. All references to “dollars”, “C$” or to “$” are to Canadian dollars and all references to “US$” are to U.S. dollars. The information contained in this AIF is dated as at December 31, 2020 unless otherwise indicated. Numbers presented are rounded to the nearest whole number and tables may not add due to rounding.

Unless otherwise indicated, all financial information included in this AIF has been prepared in accordance with International Financial Reporting Standards, which are also generally accepted accounting principles for publicly accountable enterprises in Canada.

In this AIF, certain natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead.

Management of Cenovus Energy Inc. (the “Corporation”) are responsible for the preparation and disclosure of information with respect to the Corporation’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data.

Independent qualified reserves evaluators have evaluated the Corporation’s reserves data. A report from the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.

The Safety, Environment, Responsibility and Reserves Committee of the Board of Directors of the Corporation has:

The Board of Directors of the Corporation has reviewed the Corporation’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Safety, Environment, Responsibility and Reserves Committee, approved:

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

The Audit Committee (the “Committee”) is a committee of the Board of Directors (the “Board”) of Cenovus Energy Inc. (“Cenovus” or the “Corporation”) appointed to assist the Board in fulfilling its oversight responsibilities.

The Committee has the authority to conduct any review or investigation appropriate to fulfilling its responsibilities. The Committee shall have unrestricted access to personnel and information, and any resources necessary to carry out its responsibility. In this regard, the Committee may direct internal audit personnel to particular areas of examination.

The Committee shall consist of not less than three and not more than eight directors as determined by the Board, all of whom shall qualify as independent directors pursuant to National Instrument 52-110 Audit Committees (as implemented by the Canadian Securities Administrators (“CSA”) and as amended from time to time) (“NI 52-110”).

All members of the Committee shall be financially literate, as defined in NI 52-110, and at least one member shall have accounting or related financial managerial expertise. In particular, at least one member shall have, through (i) education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor or experience in one or more positions that involve the performance of similar functions; (ii) experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions; (iii) experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or (iv) other relevant experience:

Committee members may not, other than in their respective capacities as members of the Committee, the Board or any other committee of the Board, accept directly or indirectly any consulting, advisory or other compensatory fee from the Corporation or any subsidiary of the Corporation, or be an “affiliated person” (as such term is defined in the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules, if any, adopted by the U.S. Securities and Exchange Commission (“SEC”) thereunder) of the Corporation or any subsidiary of the Corporation. For greater certainty, directors’ fees and fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the Corporation that are not contingent on continued service should be the only compensation an Audit Committee member receives from the Corporation.

Committee members shall not simultaneously serve on the audit committees of more than two other public companies, unless the Board first determines that such simultaneous service will not impair the ability of the relevant members to effectively serve on the Committee, and required public disclosure is made.

The non-executive Board Chair shall be a non-voting member of the Committee. See “Quorum” for further details.

Committee members shall be appointed by the Board, effective after the election of directors at the annual meeting of shareholders, provided that any member may be removed or replaced at any time by the Board and shall, in any event, cease to be a member of the Committee upon ceasing to be a member of the Board.

Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board.

The Nominating and Corporate Governance Committee will recommend for approval to the Board an independent Director to act as Chair of the Committee. The Board shall appoint the Chair of the Committee.

If unavailable or unable to attend a meeting of the Committee, the Chair shall ask another member to chair the meeting, failing which a member of the Committee present at the meeting shall be chosen to preside over the meeting by a majority of the members of the Committee present at such meeting.

The Chair presiding at any meeting of the Committee shall not have a casting vote.

The items pertaining to the Chair in this section should be read in conjunction with the Committee Chair section of the Chair of the Board of Directors and Committee Chair General Guidelines.

The Committee shall appoint a Secretary who need not be a member of the Committee. The Secretary shall keep minutes of the meetings of the Committee.

The Committee shall meet at least quarterly. The Chair of the Committee may call additional meetings as required. In addition, a meeting may be called by the non-executive Board Chair, the Chief Executive Officer, or any member of the Committee or by the external auditors.

Committee meetings may, by agreement of the Chair of the Committee, be held in person, by video conference, by means of telephone or by a combination of any of the foregoing.

The Committee shall meet without the presence of management on a regular basis, to facilitate additional open and candid discussion among independent directors.

Notice of the time and place of each Committee meeting may be given orally, or in writing, or by facsimile, or by electronic means to each member of the Committee at least 24 hours prior to the time fixed for such meeting. Notice of each meeting shall also be given to the external auditors of the Corporation.

A member and the external auditors may, in any manner, waive notice of the Committee meeting. Attendance of a member at a meeting shall constitute waiver of notice of the meeting except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting was not lawfully called.

A majority of Committee members, present in person, by video conference, by telephone, or by a combination thereof, shall constitute a quorum. In addition, if an ex officio, non-voting member’s presence is required to attain a quorum of the Committee, then the said member shall be allowed to cast a vote at the meeting.

The Chief Executive Officer, the Chief Financial Officer, the Comptroller and the head of internal audit are expected to be available to attend the Committee’s meetings or portions thereof.

The Committee may, by specific invitation, have other resource persons in attendance.

The Committee shall have the right to determine who shall, and who shall not, be present at any time during a meeting of the Committee.

Directors, who are not members of the Committee, may attend Committee meetings, on an ad hoc basis, upon prior consultation and approval by the Committee Chair or by a majority of the members of the Committee.

Minutes of each Committee meeting should be succinct yet comprehensive in describing substantive issues discussed by the Committee. However, they should clearly identify those items of responsibilities scheduled by the Committee for the meeting that have been discharged by the Committee and those items of responsibilities that are outstanding.

Minutes of Committee meetings shall be sent to all Committee members and to the external auditors. The full Board of Directors shall be kept informed of the Committee’s activities by a report following each Committee meeting.

The review shall include a report from the external auditors about the quality of the most critical accounting principles upon which the Corporation’s financial status depends, and which involve the most complex, subjective or significant judgmental decisions or assessments.

Review and discuss with management financial information, including earnings press releases, the use of “pro forma” or non-GAAP financial information and earnings guidance, contained in any filings with the CSA or SEC or press releases related thereto, and consider whether the information is consistent with the information contained in the financial statements of the Corporation or any subsidiary with public securities.

Review and evaluate the Corporation’s risk management framework and related processes including the supporting guidelines and practice documents.

The duties and responsibilities of a member of the Committee are in addition to those duties set out for a member of the Board.

The following tables provide a reconciliation of the financial components comprising Netbacks (in millions of dollars) to the nearest GAAP measure found in the annual and interim consolidated financial statements.

	Oil Sands								Conventional									Refining and Marketing
For the years ended December 31,	2020			2019		2018			2020			2019			2018			2020			2019			2018
Revenues
Gross Sales		7,514			10,838		10,026			635			691			904			6,051			10,513			11,183
Less: Royalties		324			1,143		473			40			30			73			-			-			-
		7,190			9,695		9,553			595			661			831			6,051			10,513			11,183
Expenses
Purchased Product		-			-		-			-			-			-			5,397			8,795			9,201
Transportation and Blending		4,399			5,152		5,879			81			82			90			-			-			-
Operating		1,094			1,039		1,037			318			337			403			824			948			927
Inventory Write-Down (Reversal)		316			-		-			-			-			-			239			49			60
(Gain) Loss on Risk Management		268			23		1,551			-			-			26			(21	)		(16	)		(1	)
Operating Margin		1,113			3,481		1,086			196			242			312			(388	)		737			996
Depreciation, Depletion and Amortization		1,684			1,543		1,439			880			319			412			739			280			222
Exploration Expense		9			18		6			82			64			2,117			-			-			-
Segment Income (Loss)		(580	)		1,920		(359	)		(766	)		(141	)		(2,217	)		(1,127	)		457			774

									Corporate and Eliminations									Consolidated
For the years ended December 31,									2020			2019			2018			2020			2019			2018
Revenues
Gross Sales										(609	)		(689	)		(724	)		13,591			21,353			21,389
Less: Royalties										-			-			-			364			1,173			546
										(609	)		(689	)		(724	)		13,227			20,180			20,843
Expenses
Purchased Product										(278	)		(417	)		(517	)		5,119			8,378			8,684
Transportation and Blending										(36	)		(50	)		(27	)		4,444			5,184			5,942
Operating										(306	)		(236	)		(183	)		1,930			2,088			2,184
Inventory Write-Down (Reversal)										-			-			-			555			49			60
(Gain) Loss on Risk Management										61			149			(1,271	)		308			156			305
Depreciation, Depletion and Amortization										161			107			58			3,464			2,249			2,131
Exploration Expense										-			-			-			91			82			2,123
Segment Income (Loss)										(211	)		(242	)		1,216			(2,684	)		1,994			(586	)
General and Administrative										292			331			1,020			292			331			1,020
Finance Costs										536			511			627			536			511			627
Interest Income										(9	)		(12	)		(19	)		(9	)		(12	)		(19	)
Transaction Costs										29			-			-			29			-			-
Foreign Exchange (Gain) Loss, Net										(181	)		(404	)		854			(181	)		(404	)		854
Re-measurement of Contingent Payment										(80	)		164			50			(80	)		164			50
(Gain) Loss on Divestiture of Assets										(81	)		(2	)		795			(81	)		(2	)		795
Other (Income) Loss, Net										40			9			13			40			9			13
										546			597			3,340			546			597			3,340
Earnings (Loss) From Continuing Operations Before Income Tax																			(3,230	)		1,397			(3,926	)
Income Tax Expense (Recovery)																			(851	)		(797	)		(1,010	)
Net Earnings (Loss) From Continuing Operations																			(2,379	)		2,194			(2,916	)


[Check one]

☐	REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
		OR
☑		ANNUAL REPORT PURSUANT TO SECTION 13(a) or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


Title of each class	Trading Symbol(s)	Name of each exchange on which registered

Common shares, no par value (together with associated common share purchase rights) Warrants (each warrant entitles the holder to purchase one common share at an exercise price of C$6.54 per share)	CVE CVE WS	New York Stock Exchange New York Stock Exchange


(a)	Certifications. See Exhibits 99.5 99.6, 99.7 and 99.8 to this annual report on Form 40-F.

(b)	Disclosure Controls and Procedures. As of the end of the Registrant’s fiscal year ended December 31, 2020, an evaluation of the effectiveness of the Registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the Registrant’s management with the participation of the principal executive officer and principal financial officer. Based upon that evaluation, the Registrant’s principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the Registrant’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s (the “Commission”) rules and forms and (ii) accumulated and communicated to the Registrant’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

	It should be noted that while the Registrant’s principal executive officer and principal financial officer believe that the Registrant’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Registrant’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

(c)	Management’s Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the “Report of Management” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2020, filed as Exhibit 99.3 to this annual report on Form 40-F.

(d)	Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the “Report of Independent Registered Public Accounting Firm” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2020, filed as Exhibit 99.3 to this annual report on Form 40-F.

(e)	Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2020, there was no change in the Registrant’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting.



Date: February 9, 2021	CENOVUS ENERGY INC.
	By:	/s/ Jeffrey R. Hart
		Name:	Jeffrey R. Hart
		Title:	Executive Vice-President & Chief Financial Officer


Exhibits		Documents

99.1		Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2020.

99.2		Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2020.

99.3		Consolidated Annual Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2020.

99.4		Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2020.

99.5		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.

99.6		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.

99.7		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

99.8		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

99.9		Consent of PricewaterhouseCoopers LLP.

99.10		Consent of McDaniel & Associates Consultants Ltd.

99.11		Consent of GLJ Ltd.


101		Interactive data file


	(a)	Annual Information Form of Cenovus Energy Inc. for the fiscal year ended December 31, 2020.

	(b)	Management’s Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended December 31, 2020.

	(c)	Consolidated Financial Statements of Cenovus Energy Inc. for the fiscal year ended December 31, 2020.

	(d)	Supplementary Information – Oil and Gas Activities (unaudited) for the fiscal year ended December 31, 2020.


APPENDIX A -Report on Reserves Data by Independent Qualified Reserves Evaluators	A1
APPENDIX B -Report of Management and Directors on Reserves Data and Other Information	B1
APPENDIX C -Audit Committee Mandate	C1
APPENDIX D -Netback Reconciliations	D1


Subsidiaries & Partnerships	Percentage Owned⁽¹⁾	Jurisdiction of Incorporation, Continuance, Formation or Organization
Cenovus Energy Marketing Services Ltd.	100	Alberta
FCCL Partnership (“FCCL”)	100	Alberta
WRB Refining LP(“WRB”)⁽²⁾	50	Delaware


In Canada:	In the United States:
Computershare Investor Services, Inc. 8^th Floor, 100 University Avenue Toronto, ON M5J 2Y1 Canada	Computershare Trust Company NA 250 Royall St. Canton, MA 02021 U.S.
Tel: 1-866-332-8898 Website: www.investorcentre.com/cenovus

Crude Oil and Natural Gas Liquids		Natural Gas

bbl	barrel	AECO	Alberta Energy Company
bbls/d	barrels per day	Bcf	billion cubic feet
Mbbls/d	thousand barrels per day	Mcf	thousand cubic feet
MMbbls	million barrels	MMcf	million cubic feet
NGLs	natural gas liquids	MMcf/d	million cubic feet per day
BOE	barrel of oil equivalent	MMBtu	million British thermal units
BOE/d	barrels of oil equivalent per day
MMBOE	million barrels of oil equivalent
WTI	West Texas Intermediate
WCS	Western Canadian Select


Independent Qualified Reserves Evaluator	Effective Date of Evaluation Report	Location of Reserves	Evaluated Net Present Value of Future Net Revenue (before income taxes, 10% discount rate) $ millions

McDaniel & Associates Consultants Ltd.	December 31, 2020	Canada	$30,796


GLJ Ltd.	December 31, 2020	Canada	$1,114

			$31,910


/s/ Alexander J. Pourbaix		/s/ Jeffrey R. Hart
Alexander J. Pourbaix President & Chief Executive Officer		Jeffrey R. Hart Executive Vice-President & Chief Financial Officer
/s/ Keith A. MacPhail		/s/ Richard J. Marcogliese
Keith A. MacPhail Director and Chair of the Board		Richard J. Marcogliese Director and Chair of the Safety, Environment, Responsibility and Reserves Committee


	Per Consolidated Financial Statements
		Oil Sands⁽¹⁾	Conventional⁽¹⁾	Total Upstream

Revenues
Gross Sales		7,514	635	8,149
Less: Royalties		324	40	364
		7,190	595	7,785
Expenses
Transportation and Blending		4,399	81	4,480
Operating		1,094	318	1,412
Inventory Write-Down (Reversal)		316	-	316
Netback		1,381	196	1,577
(Gain) Loss on Risk Management		268	-	268
Operating Margin		1,113	196	1,309


		Basis of Netback Calculation					Adjustments			Per Above Table
	Bitumen		Heavy Crude Oil	Light and Medium Oil	NGLs	Natural Gas	Condensate	Inventory⁽²⁾	Other	Total Upstream
Gross Sales	4,053		30	71	157	328	3,452	-	58	8,149
Royalties	330		1	11	15	13	-	(6)	-	364
Transportation and Blending	1,232		2	5	30	44	3,452	(285)	-	4,480
Operating	1,109		9	18	65	203	-	(25)	33	1,412
Inventory Write-Down (Reversal)	-		-	-	-	-	-	316	-	316
Netback	1,382		18	37	47	68	-	-	25	1,577
(Gain) Loss on Risk Management										268
Operating Margin										1,309


(barrels per day, unless otherwise stated)	2020	Q4	Q3	Q2	Q1
Bitumen
Foster Creek	164,906	161,108	158,280	171,139	169,207
Christina Lake	221,675	220,676	238,140	198,954	228,764
Total Bitumen	386,581	381,784	396,420	370,093	397,971
Crude Oil (Heavy, Light and Medium) and NGLs
Heavy Crude Oil	2,640	1,922	3,087	1,981	3,576
Light and Medium Oil	4,493	4,263	4,318	4,309	5,086
NGLs	19,513	18,358	18,297	20,320	21,104
Total Bitumen, Crude Oil (Heavy, Light and Medium) and NGLs Sales	413,227	406,327	422,122	396,703	427,737
Natural Gas Sales (MMcf/d)⁽¹⁾	380	371	360	392	395
Total Sales (BOE/d)	476,488	468,249	482,133	462,068	493,529

OVERVIEW OF CENOVUS		1

LOW OIL PRICES AND THE NOVEL CORONAVIRUS (“COVID-19”)		2

YEAR IN REVIEW		3

OPERATING AND FINANCIAL RESULTS		4

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS		9

REPORTABLE SEGMENTS		11

OIL SANDS		12
CONVENTIONAL		16
REFINING AND MARKETING		19
CORPORATE AND ELIMINATIONS		20

DISCONTINUED OPERATIONS		23

QUARTERLY RESULTS		23

OIL AND GAS RESERVES		25

LIQUIDITY AND CAPITAL RESOURCES		26

RISK MANAGEMENT AND RISK FACTORS		30

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES		54

CONTROL ENVIRONMENT		57

SUSTAINABILITY		57

OUTLOOK		58

ADVISORY		62

ABBREVIATIONS		66
DEFINITIONS		66
NETBACK RECONCILIATIONS		67

Cenovus Energy Inc. – 2020 Management’s Discussion and Analysis

	2020		Percent Change			2019		Percent Change			2018
Upstream Production Volumes
Oil Sands (barrels per day)
Foster Creek		163,210		2			159,598		(1	)		161,979
Christina Lake		218,513		12			194,659		(3	)		201,017
Total Oil Sands Crude Oil		381,723		8			354,257		(2	)		362,996

Conventional ⁽¹⁾ (BOE per day)		89,932		(8	)		97,423		(19	)		120,258

Total Production from Continuing Operations (BOE per day)		471,740		4			451,680		(7	)		483,458

Production From Discontinued Operations (BOE per day)		-		-			-		(100	)		294

Sales from Continuing Operations ⁽²⁾ (BOE per day)		420,456		8			390,813		(10	)		436,163

Oil and Gas Reserves (MMBOE)
Proved		5,030		(1	)		5,103		(1	)		5,167
Probable		1,656		(6	)		1,768		(3	)		1,821
Proved plus Probable		6,686		(3	)		6,871		(2	)		6,988

Refining and Marketing
Crude Oil Runs⁽³⁾(Mbbls/d)		372		(16	)		443		(1	)		446
Refined Product ⁽³⁾ (Mbbls/d)		385		(17	)		466		(1	)		470
Crude Utilization ⁽³⁾ (percent)		75		(17	)		92		(5	)		97

Crude-by-Rail (barrels per day)
Crude-by-Rail Loads ⁽⁴⁾		30,422		(43	)		53,345		1,197			4,113
Crude-by-Rail Sales⁽⁵⁾		33,870		(30	)		48,626		1,367			3,314

($ millions, except per share amounts)	2020			Percent Change			2019		Percent Change			2018 ⁽¹⁾

Operating Margin ^{(2) (3)}		921			(79	)		4,460		86			2,394

Cash From (Used in) Operating Activities
From Continuing Operations		273			(92	)		3,285		55			2,118

Total		273			(92	)		3,285		53			2,154

Adjusted Funds Flow ⁽⁴⁾		147			(96	)		3,702		115			1,721

Operating Earnings (loss) ^{(2) (4)}		(2,604	)		(671	)		456		117			(2,755	)
Per Share ($) ⁽⁵⁾		(2.12	)		(673	)		0.37		117			(2.24	)

Net Earnings (Loss)
From Continuing Operations		(2,379	)		(208	)		2,194		175			(2,916	)
Per Share ($) ⁽⁵⁾		(1.94	)		(209	)		1.78		175			(2.37	)

Total		(2,379	)		(208	)		2,194		182			(2,669	)
Per Share ($) ⁽⁵⁾		(1.94	)		(209	)		1.78		182			(2.17	)

Total Assets		32,770			(7	)		35,173		-			35,174

Total Long-Term Financial Liabilities ⁽⁶⁾		9,041			7			8,483		(1	)		8,602

Capital Investment ⁽⁷⁾		841			(28	)		1,176		(14	)		1,363

Dividends
Cash Dividends		77			(70	)		260		6			245
Per Share ($)		0.0625			(71	)		0.2125		6			0.2000

($ millions)	2020		2019 ^{(1) (2)}		2018⁽²⁾
Gross Sales		14,200		22,042		22,113
Less: Royalties		364		1,173		546
Revenues		13,836		20,869		21,567
Expenses
Purchased Product		5,397		8,795		9,201
Transportation and Blending		4,480		5,234		5,969
Operating Expenses		2,236		2,324		2,367
Inventory Write-Down (Reversal)		555		49		60
Realized (Gain) Loss on Risk Management Activities		247		7		1,576
Operating Margin		921		4,460		2,394

($ millions)	2020 vs. 2019			2019 vs. 2018⁽¹⁾
Net Earnings (Loss), Comparative Year		2,194			(2,916	)
Increase (Decrease) due to:
Operating Margin		(3,539	)		2,066
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)		93			(1,398	)
Unrealized Foreign Exchange Gain (Loss)		(696	)		1,476
Re-measurement of Contingent Payment		244			(114	)
Gain (Loss) on Divestiture of Assets		79			797
Expenses ⁽²⁾		416			573
DD&A		(1,215	)		(118	)
Exploration Expense		(9	)		2,041
Income Tax Recovery (Expense)		54			(213	)
Net Earnings (Loss), End of Year		(2,379	)		2,194

($ millions)	2020		2019 ⁽¹⁾		2018⁽²⁾
Oil Sands		427		656		870
Conventional ⁽³⁾		78		103		228
Refining and Marketing		276		280		208
Corporate and Eliminations		60		137		57
Capital Investment ⁽⁴⁾		841		1,176		1,363

(US$/bbl, unless otherwise indicated)	Q4 2020			Q4 2019			2020			Percent Change			2019			2018
Brent
Average		45.24			62.50			43.21			(33	)		64.18			71.53
WTI
Average		42.66			56.96			39.40			(31	)		57.03			64.77
Average Differential Brent-WTI		2.58			5.54			3.81			(47	)		7.15			6.76
WCS at Hardisty ("WCS")
Average		33.36			41.13			26.80			(39	)		44.27			38.46
Average Differential WTI-WCS		9.30			15.83			12.60			(1	)		12.76			26.31
Average (C$/bbl)		43.41			54.29			35.59			(39	)		58.77			49.81
WCS at Nederland
Average		40.36			51.47			35.86			(35	)		55.56			62.05
Average Differential WTI-WCS at Nederland		2.30			5.49			3.54			141			1.47			2.72
West Texas Sour ("WTS")
Average		43.02			57.26			39.37			(30	)		56.27			57.24
Average Differential WTI-WTS		(0.36	)		(0.30	)		0.03			(96	)		0.76			7.53
Condensate (C5 @ Edmonton)
Average		42.54			53.01			37.16			(30	)		52.86			61.00
Average Differential WTI-Condensate (Premium)/Discount		0.12			3.95			2.24			(46	)		4.17			3.77
Average Differential WCS-Condensate (Premium)/Discount		(9.18	)		(11.88	)		(10.36	)		21			(8.59	)		(22.54	)
Average (C$/bbl)		55.36			69.97			49.44			(30	)		70.15			79.02
Average Refined Product Prices
Chicago Regular Unleaded Gasoline ("RUL")		47.31			64.83			45.24			(36	)		70.55			77.96
Chicago Ultra-low Sulphur Diesel ("ULSD")		54.21			78.09			50.08			(36	)		77.97			86.75
Refining Margin: Average 3-2-1 Crack Spreads ⁽²⁾
Chicago		7.05			12.27			7.54			(53	)		16.00			15.97
Group 3		7.57			14.60			8.67			(48	)		16.67			16.74
Average Natural Gas Prices
AECO ⁽³⁾ (C$/Mcf)		2.77			2.34			2.24			38			1.62			1.53
NYMEX (US$/Mcf)		2.66			2.50			2.08			(21	)		2.63			3.09
Foreign Exchange Rate (US$ per C$1)
Average		0.768			0.758			0.746			(1	)		0.754			0.772
End of Period		0.785			0.770			0.785			2			0.770			0.733

(barrels per day)	2020		Percent Change		2019		Percent Change			2018
Foster Creek		163,210		2		159,598		(1	)		161,979
Christina Lake		218,513		12		194,659		(3	)		201,017
		381,723		8		354,257		(2	)		362,996

(percent)	2020		2019		2018
Foster Creek		7.9		18.8		18.0
Christina Lake		14.4		21.6		4.8

($/bbl)	2020		Percent Change			2019		Percent Change			2018 ⁽¹⁾
Foster Creek
Fuel		2.83		15			2.47		16			2.13
Non-fuel		6.41		(4	)		6.67		(2	)		6.84
Total		9.24		1			9.14		2			8.97
Christina Lake
Fuel		2.18		6			2.06		10			1.87
Non-fuel		4.61		(13	)		5.27		11			4.73
Total		6.79		(7	)		7.33		11			6.60
Total		7.84		(4	)		8.15		7			7.65

	Gross Stratigraphic Test Wells						Gross Production Wells⁽¹⁾
	2020		2019		2018		2020		2019		2018
Foster Creek		38		14		43		-		-		14
Christina Lake		42		18		63		-		11		38
		80		32		106		-		11		52
Other ⁽²⁾		75		26		20		-		-		-
		155		58		126		-		11		52

($/BOE)	2020			2019			2018 ⁽¹⁾
Sales Price		17.84			17.95			19.31
Royalties		1.23			0.83			1.67
Transportation and Blending		2.46			2.31			1.97
Operating Expenses		8.99			8.79			8.58
Netback Excluding Realized Risk Management		5.16			6.02			7.09
Realized Risk Management Gain (Loss)		(0.01	)		(0.01	)		(0.59	)
Netback Including Realized Risk Management		5.15			6.01			6.50

($ millions, except per share	2020												2019
amounts)	Q4			Q3			Q2			Q1			Q4			Q3		Q2		Q1

Average Commodity Prices
Brent		45.24			43.37			33.27			50.96			62.50			62.00		68.34		63.88
WTI		42.66			40.93			27.85			46.17			56.96			56.45		59.83		54.90
WCS		33.36			31.84			16.38			25.64			41.13			44.21		49.18		42.53
Chicago Market Crack Spread		7.05			7.89			6.44			8.79			12.27			16.72		21.44		13.57

Production Volumes
Liquids (barrels per day)		405,280			411,788			400,050			416,802			400,329			380,699		371,390		370,983
Natural Gas (MMcf per day)		371			360			392			395			403			407		432		458
Total Production (BOE per day)		467,202			471,799			465,415			482,594			467,448			448,496		443,318		447,270

Refinery Operations
Crude Oil Runs (Mbbls/d)		338			382			325			442			456			465		474		375
Refined Products (Mbbls/d)		350			397			332			460			477			485		501		402

Revenues		3,426			3,659			2,174			3,968			4,838			4,736		5,603		5,004

Operating Margin ⁽¹⁾		625			594			291			(589	)		864			1,080		1,277		1,239

Cash From (Used in) Operating Activities		250			732			(834	)		125			740			834		1,275		436

Adjusted Funds Flow ⁽²⁾		341			414			(462	)		(146	)		687			928		1,082		1,005

Operating Earnings (Loss)		(551	)		(452	)		(414	)		(1,187	)		(164	)		284		267		69
Per Share ⁽³⁾ ($)		(0.45	)		(0.37	)		(0.34	)		(0.97	)		(0.13	)		0.23		0.22		0.06

Net Earnings (Loss)		(153	)		(194	)		(235	)		(1,797	)		113			187		1,784		110
Per Share⁽³⁾($)		(0.12	)		(0.16	)		(0.19	)		(1.46	)		0.09			0.15		1.45		0.09

Capital Investment ⁽⁴⁾		242			148			147			304			317			294		248		317

Dividends
Cash Dividends		-			-			-			77			77			60		62		61
Per Share ($)		-			-			-			0.0625			0.0625			0.0500		0.0500		0.0500

As at December 31, 2020 (before royalties)	Bitumen (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional Natural Gas ⁽¹⁾ (Bcf)		Total (MMBOE)

Proved		4,812		7		50		965		5,030
Probable		1,520		6		31		601		1,656
Proved plus Probable		6,332		13		81		1,566		6,686

As at December 31, 2019 (before royalties)	Bitumen ⁽²⁾ (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional Natural Gas ⁽¹⁾ (Bcf)		Total (MMBOE)

Proved		4,826		9		60		1,242		5,103
Probable		1,594		8		37		783		1,768
Proved plus Probable		6,420		17		97		2,025		6,871

($ millions)	Term	Amount Available
Cash and Cash Equivalents	Not applicable		378
Committed Credit Facilities
Revolving Credit Facility – Tranche A	November 2023		3,300
Revolving Credit Facility – Tranche B	November 2022		1,200
Uncommitted Demand Facilities
Cenovus Energy Inc.	Not applicable		600
WRB Refining LP (Cenovus's proportionate share)	Not applicable		70

As at December 31,	2020		2019		2018
Net Debt to Capitalization ⁽¹⁾ (percent)		30		25	32
Net Debt to Adjusted EBITDA (times)	11.9x		1.6x		5.8x

As at January 31, 2021	Units Outstanding (thousands)		Units Exercisable (thousands)
Common Shares⁽¹⁾		2,017,404	N/A
Common Share Warrants		65,418	N/A
Preferred Shares Series 1		10,436	N/A
Preferred Shares Series 2		1,564	N/A
Preferred Shares Series 3		10,000	N/A
Preferred Shares Series 5		8,000	N/A
Preferred Shares Series 7		6,000	N/A
Stock Options ⁽²⁾		30,499		23,305
Other Stock-Based Compensation Plans		3,715		1,293

	Expected Payment Date
($ millions)	2021		2022		2023		2024		2025		Thereafter		Total

Commitments
Transportation and Storage ⁽¹⁾		1,014		954		1,341		1,444		1,107		15,537		21,397
Real Estate ⁽²⁾		34		36		38		41		44		604		797
Capital Commitments		1		2		-		-		-		-		3
Other Long-Term Commitments		104		45		32		32		24		85		322
Total Commitments ⁽³⁾		1,153		1,037		1,411		1,517		1,175		16,226		22,519
Other Obligations
Long-term Debt (Principal and Interest)		385		1,024		941		346		1,620		8,627		12,943
Decommissioning Liabilities		41		45		41		42		41		2,429		2,639
Contingent Payment		36		28		-		-		-		-		64
Lease Liabilities (Principal and Interest)⁽⁴⁾		254		237		208		203		162		1,412		2,476
Total Commitments and Obligations		1,869		2,371		2,601		2,108		2,998		28,694		40,641